Solar investment in Iraq: costs, conditional returns and contract risks

Solar economics: cost, daytime demand and contracted revenue

Under a 20-year self-generation model, an assumed complete PV investment of $400,000/MWp gives a 33.4% real, unlevered, pre-tax project IRR and 2.9-year simple payback when 90% of generation displaces electricity costing 10 US cents/kWh. At $800,000/MWp, the same model gives 15.5% and 5.8 years. Both cases hold avoided prices and operating costs constant in real USD and assign no terminal value. The $400,000/MWp input is an illustrative complete-cost assumption; site and connection scope affect actual expenditure.

Runaki is the Kurdistan Regional Government’s programme to extend round-the-clock electricity with metered billing. At its posted commercial and industrial tariffs, savings can be substantially larger than at a ten-cent avoided cost, provided the plant displaces metered consumption. Agricultural tariffs leave a much narrower margin. The customer-class table below quantifies this difference; old electricity-debt instalments remain separate from current energy charges. ^{[3] [4]}

A separate 25-year utility PPA model gives a 14.5% real, unlevered, pre-tax IRR and 6.3-year simple payback at the Basra budget-derived $656,000/MWp cost and an assumed seven-cent/kWh price maintained in real USD. At an assumed complete cost of $400,000/MWp, it gives 25.1% and 3.8 years. There is no terminal value, and the model does not reproduce Basra’s actual tariff or contract. A fixed nominal price or a shorter contracted revenue period produces different returns. ^{[24] [25]}

Existing roofs or land, usable electrical infrastructure and high daytime consumption can reduce incremental costs and increase the value of business solar. Storage and off-site connection works can change that balance.

Installed cost in Iraq: what the evidence actually supports

ZMC Solar’s 22 August 2026 guide describes the following installed industrial-system estimates. They are supplier planning figures, not disclosed project awards or final costs. ^[31]

The guide’s 500 kWp example totals $187,500 ($375/kWp). It discusses batteries as necessary for factory continuity without specifying storage capacity in the price table. Battery scope, taxes and connection exclusions are therefore unresolved. ^[31]

ZMC’s 16 May 2026 guide quotes $140,000 for 200 kW, or $700 per reported kW, including panels, inverter, mounting, wiring and installation, with batteries extra. These two publications are from one supplier; they are neither independent corroboration nor matched quotations demonstrating a price decline. ^[32]

SOLYGENS provides a more explicit small-system comparison: IQD 4.5m installed for 2.6 kWp of panels, a 6.6 kW inverter and 12.03 kWh battery, versus IQD 3.5m for the same inverter and battery without the array. The IQD 1m difference covers the array and associated installation; it is not a complete PV-system price. These undated offers were checked on 10 October 2026 and cannot be scaled into a MW-project quotation. ^[33]

The Basra calculation combines a February 2025 budget estimate with the disclosed 1.25 GWp rating, assuming both describe the same full project. Its disclosure does not itemise land, connection works, taxes or financing. Muthanna’s amount is a May 2023 approval despite later implementation reports. The Baghdad paper was published in 2026, but the collection date of its equipment-price inputs is not established; it is a modelled estimate, not an executed construction price.

The $400,000/MWp input is an analytical assumption within advertised price ranges. No itemised quote or comparable completed Iraqi PV-only contract at that total cost was verified. Each scenario treats its capital input as the entire initial investment: any omitted civil works, connection costs, taxes or development expenditure increases it. Storage capacity and the DC/AC denominator also affect comparability.

Why a commercial installation can cost less than a utility project

A factory system can have a lower incremental investment requirement when it uses assets the business already owns. A national-grid project must create a generation site and deliver power to an agreed export point. The differences below are engineering and commercial explanations, not a verified breakdown of Basra’s or Muthanna’s budgets. ^{[34] [35] [36]}

Utility-scale projects retain bulk-purchasing and construction economies. Commercial PV is therefore not inherently cheaper. A low factory installation price and a large-project budget can differ because the former reuses infrastructure or excludes costs, while the latter covers a broader undertaking. The US Department of Energy’s cost model separates hardware, fieldwork, office work and developer overhead; that accounting structure is useful here, but its US price levels are not Iraqi benchmarks. ^[34]

Timing and units add two further differences. Basra’s February 2025 budget and Muthanna’s May 2023 approval are not October 2026 procurement offers, so later equipment repricing may contribute to the gap without proving its size. Basra’s same $820m budget is $820,000/MWac or $656,000/MWp: that apparent 20% reduction is denominator arithmetic, not a saving. At a new site, a $400,000/MWp installation plus $150,000/MWp of omitted works is a $550,000/MWp investment; the added amount here is illustrative, not an Iraqi cost estimate.

Yield is 1,700 kWh/kWp, annual O&M $15,000/MWp, degradation 0.5%, and replacement $60,000/MWp in year 12 of a 25-year life. These remain fixed as capex falls. The lower rows test commercial price levels under PPA operating assumptions; they do not demonstrate that an export project can be delivered for the same amount. Connection and development spending outside the quoted installation price increases the cost input.

Investment basis: assumptions and why they were selected

The reference analysis compares two 1 MWp investments. MWp is the DC module rating; MWac is the AC output rating. The business case assumes $400,000/MWp complete initial capital cost; the utility reference uses $656,000/MWp derived from Basra’s disclosed budget. These different modelling inputs do not establish that smaller plants are generally cheaper.

The $400,000/MWp business capital cost is an illustrative input within indicative supplier pricing. Self-consumption, O&M, replacement, operating life and return hurdles are also assumptions. Annual cleaning, insurance and servicing budgets stay constant across the capital-cost sensitivities. ^{[2] [24] [25] [31]}

Business solar: returns depend on avoidable cost and daytime use

The first table changes only the value of the electricity displaced. Capacity, capex, generation, self-consumption and operating costs stay at the business reference assumptions above. “Year-one net saving” deducts O&M. IRR and NPV also include annual degradation and the year-12 replacement; simple payback does not.

At the lower capital cost, a six-cent avoided electricity price clears the 12% hurdle, while three-cent energy does not. High returns in the upper rows require the stated price to be genuinely avoidable on 90% of generation throughout the modelled life. NPV measures value above the 12% hurdle; it is not a prediction of a typical Iraqi project outcome.

This table isolates the installation-cost effect: year-one net savings remain $137,000/MWp, annual O&M $16,000/MWp and year-12 replacement $60,000/MWp. The $300,000–$450,000 inputs test the recent indicative commercial range; $550,000 and $800,000 show the effect of higher complete-project costs. No battery, export revenue or subsidy is assumed.

Runaki tariffs apply to customers served under that KRG programme, rather than to all Iraq. The electricity ministry reported around 90% regional coverage in September 2026, with full coverage still a target. The table converts posted customer-class tariffs, rechecked on 11 October, at an illustrative 1,310 IQD/USD. It excludes discounts, arrears and other bill items and assumes the converted tariff remains constant in real USD. ^{[3] [4]}

Return and payback assume 90% self-consumption. The final column instead gives the share needed to reach the 12% hurdle with no export income. At the lower capex, agricultural PV could clear the hurdle above 94.8% self-use under these assumptions; at 90%, it falls short. Lower installation cost improves the case but does not eliminate the value difference between customer classes.

The relevant tariff is the expenditure actually avoided during solar-producing hours. Generator fuel displaced during outages can increase that value; a fixed generator subscription that remains payable cannot. Runaki’s pre-programme debt instalments also remain payable and should not be included in avoided current energy cost. At hybrid sites, generator minimum loading and grid-transfer controls affect the self-consumption achievable in practice. ^[4]

Utility PPA: conditional returns over a 25-year revenue period

The utility model commits $656,000/MWp upfront and receives operating cash flows over 25 years. It uses the Basra-derived cost input with the general assumptions above; it does not reproduce Basra’s actual contract, financing or returns. The downside applies a persistent 10% yield reduction followed by 5% uncompensated curtailment, reducing saleable energy by 14.5%. These are sensitivities, not measured Iraqi loss rates.

The seven-cent reference case clears the 12% hurdle; the same price falls short under the combined downside. The eight-cent row clears it under both conditions. These returns assume full payment and exclude debt and tax. They therefore describe the project’s operating economics, not sponsor equity returns.

The required-price table solves for the tariff consistent with each return hurdle and delivery condition. All capital, operating and replacement assumptions remain fixed. These are modelled break-even prices over 25 years, not observed or proposed Iraqi PPA tariffs.

This table asks how much total upfront investment each tariff can support at a 12% return. The ceiling includes all project costs paid at the start. Any land, connection or development cost outside the base estimate consumes the difference between that estimate and the ceiling. The public Basra budget does not itemise those costs, so its coverage cannot be assumed for another site.

Seven-year corporate PPA: contract duration and debt tenor

This separate illustration assumes a 1 MWp project with only seven years of contracted income: $400,000 complete initial capital, 1.7 GWh in year one, 0.5% annual degradation, a fixed nominal 12 cents/kWh paid on all generated output, and $16,000 nominal annual O&M. It includes no revenue or terminal value after year seven, no replacement within the term, and no taxes, finance fees or working-capital costs. The tariff, installation cost and financing terms are illustrative. The 12% nominal NPV hurdle below is separate from the 12% real hurdle used elsewhere.

These scenarios assign no probabilities. The reference case’s high return depends on a 12-cent paid price and a complete $400,000 cost; the seven-cent row changes only price. The combined downside separately reduces generation and collects only 95% of invoiced energy. A seven-year contract cannot inherit the 25-year model’s assumed revenue tail.

If the full $400,000 were financed at an assumed 10% nominal interest with three equal annual total repayments, each year-end payment would be $160,846. Interest is calculated on the declining outstanding balance. This convention differs from equal annual principal payments and does not imply that full-cost financing is available.

Full-cost borrowing leaves annual coverage of 1.16–1.17× before fees, reserves, tax and payment delays. At an illustrative minimum 1.30× coverage, level-payment debt would be limited to approximately $355,744, with the balance funded otherwise. This is an assumed coverage test, not a lender rule. With no initial equity contribution in the full-debt example, conventional equity IRR is undefined. Annual cash flow also cannot establish whether each month’s repayment can be met.

Iraq solar investment calculator

Financing and settlement: project return is only the first test

Debt capacity is calculated separately using cash available for debt service (CFADS). The illustration assumes a flat nominal USD electricity price and operating cost, 12-year repayment, 9% nominal interest and a 1.30× debt-service coverage ratio (DSCR). DSCR is CFADS divided by scheduled principal and interest. These are financing assumptions, not Iraqi loan offers; the calculation does not produce an equity IRR.

Annual CFADS deducts operating cost and a $5,000/MWp replacement reserve, chosen to fund the assumed $60,000 replacement over 12 years. Permissible debt service is CFADS divided by DSCR; discounting that service at the loan rate gives the initial principal. The reserve funds replacement, so the replacement is not charged a second time in this debt calculation.

Read the percentage as the mechanical debt ceiling divided by the reference capex. It is not committed leverage. The stressed column changes generation only; price, O&M and loan terms are unchanged. Fees, tax, a debt-service reserve account, receivables and lender gearing caps are excluded. Their inclusion can lower usable debt or increase the equity funding requirement.

The settlement table separates permanent non-collection from payment delay. Non-collection reduces revenue; delay consumes working capital and adds financing cost. The currency example concerns a fall in the dinar’s USD value, not the same percentage rise in an IQD-per-dollar quotation. A 30 May 2023 Cabinet notice records take-or-pay treatment for TotalEnergies’ solar purchase under the agreed contract. The notice does not disclose the tariff, term, curtailment definition, payment security, termination compensation or convertibility terms. It therefore establishes a project-specific purchase decision, not identical protection for other PPAs. ^[26]

Engineering and connection scope: translate performance into cash flow

The model’s net yield already includes an allowance for normal physical losses. The investment question is whether a different design, operating plan or grid interface changes delivered energy or total cost relative to that baseline. The following sensitivities place those changes on a consistent value basis; they should not be added mechanically to one another.

Soiling and heat require site-specific treatment. The IEA Photovoltaic Power Systems Programme (IEA PVPS) identifies seasonal and spatial variation in soiling and explains why non-uniform deposits can make a short-circuit-current proxy understate power loss. LONGi’s Hi-MO 7 LR5-72HGD brochure, for example, supplies a module temperature coefficient; converting that coefficient into annual revenue requires the site’s temperature, irradiance, clipping and dispatch profile. A product specification alone does not establish an Iraqi annual yield advantage. ^{[14] [15]}

Basra’s disclosed 1 GWac/1.25 GWp ratio illustrates why a price “per MW” needs a denominator. A $400,000/MWp price equals $500,000/MWac at that ratio. Conversely, $400,000/MWac would equal $320,000/MWp. Grid disconnection, generator controls, soiling and availability also need distinct loss allowances to avoid counting the same exposure twice. ^[25]

Grid capacity: a connection-specific opportunity

Solar can add substantial daytime energy and release fuel otherwise used in thermal generation. At the reference yield, a hypothetical 12 GWp fleet would produce about 20.4 TWh annually before additional curtailment. This is an energy calculation; it is not an estimate of firm capacity or an assertion that all those plants can connect. IRENA records a roughly 12 GW solar ambition for 2030, while EIA’s federal figures for 2024 put available peak generation at 25 GW against 48 GW summer demand. Neither dataset establishes a current grid-hosting limit. ^{[1] [16]}

The grid table explains why a large national supply deficit does not translate directly into a bankable connection offer. Local voltage and thermal constraints may bind before national energy demand does; minimum conventional generation and reserve requirements can create curtailment at other hours. Inverter support capabilities can help, but their active-power trade-offs, equipment scope and remuneration must be specified. No ancillary-services income or firm-capacity payment is included in this investment case. ^[17]

The investable capacity is therefore the capacity supported by a defined connection node, export envelope, reinforcement programme and curtailment allocation. The available evidence does not support a single national maximum. The PPA tables express the financial consequence of that uncertainty through explicit delivered-energy sensitivities.

Storage, net metering and wheeling: additional value must be contractible

IRENA’s 2025 assessment reports that the KRG Ministry of Electricity issued grid-connection regulations including energy-offset net metering (printed p.64). The underlying instrument, eligibility, settlement interval, carry-forward rules and implementation at a particular connection were not obtained. It does not establish cash payment for surplus exports or universal retail-rate credit. Federal and KRG arrangements remain distinct; the reference models assign no export revenue. ^[1]

These are independent options, not revenues included in the headline returns. Battery capital cost is an illustrative assumption. Usable capacity leaves a state-of-charge margin, the cycle allowance permits non-cycling days, and the shorter life recognises earlier replacement than PV. Constant throughput and no augmentation nevertheless make the result optimistic. The export case shows the payment required to rescue a lower-utilisation project. The wheeling case illustrates how delivery costs can consume the apparent discount to the customer’s tariff. None establishes a right to connect, export or wheel electricity.

The Central Bank of Iraq (CBI)’s July renewable-energy financing announcement supports the existence of a financing initiative, but does not establish one universally available commercial interest rate or tenor. No grant, subsidised loan, investment-licence tax relief or customs exemption is used to make the reference cases viable. Such benefits affect returns only if applicable to the particular borrower, project and import transaction. ^[18]

Project pipeline: disclosed stages and counterparties

TotalEnergies discloses a 1 GWac/1.25 GWp Basra solar project. The October 2024 partnership envisaged equal TotalEnergies/QatarEnergy ownership, subject to approvals; wider GGIP ownership is separate. A Reuters interview recorded on 21 April 2026 attributes to TotalEnergies supervisor Haider Adnan the statement that the first 250 MW unit began operating and connected to the grid in March. This advances the earlier 61 MW trial report, but is an attributed operating milestone rather than audited output or an October aggregate commissioning figure. ^{[6] [7] [25] [37]}

The table records disclosed development stages, not a near-term equipment-order forecast. Basra’s delivery progress supports an installed-base service opportunity; Muthanna’s phased target suggests potential staged construction demand; the UGTR/KAR work remains a development-services reference at the reported stage. Available evidence does not establish open procurement for each project or convert their combined headline capacity into committed capital. ^{[8] [10] [11] [12] [9] [13] [29] [30]}

EPCs and importers: execution capability and working capital

The supplier table identifies roles and channels, not market shares or exclusive distribution rights. Progress Sun’s distinction between EPC and owner’s-engineer assignments matters when interpreting its referenced MW. The imported-product examples establish visible channels for modules and inverters; they do not establish relative sales volumes. Karbala’s reported manufacturing capacity may affect service and lead times, but actual utilisation and delivered-cost competitiveness remain undisclosed. ^{[19] [20] [21] [22] [13]}

For importers, cash conversion can determine the return more than the equipment markup. The next table uses one illustrative $125,000 sale with $100,000 equipment cost, $8,000 logistics/clearance and a $2,000 warranty allowance. The resulting $15,000 contribution is reduced by financing $110,000 at an assumed 12% annual rate. Days measure the full funding period; they are not estimates of typical Iraqi distributor terms.

The comparison holds equipment, logistics and warranty costs constant, so the deterioration comes solely from time and price concessions. Warranty replacement stock, overseas diagnosis and credit extended to installers can lengthen that funding period. A manufacturer’s product warranty does not itself fund local labour, freight or customer downtime.

FAO notice 2026/FNIRQ/FNIRQ/138066 covers solar variable-frequency-drive systems for existing irrigation pumps in Sulaymaniyah, Babylon, Najaf and Dhi Qar, including delivery, installation, testing, commissioning and training. Its displayed deadline, rechecked on 11 October 2026, is 15 October at 14:00 Baghdad. The notice is not an award; quantities and any amendments are governed by the issuer’s tender documents. ^[23]

What the evidence and calculations establish

At a ten-cent avoided price, the 20-year business model gives roughly 30–45% real project IRR across assumed complete costs of $450,000–$300,000/MWp, versus 15.5% at $800,000/MWp. This isolates the cost effect at 90% self-use. It does not validate those installation budgets or guarantee two decades of avoided prices, daytime demand and performance.

The 25-year utility reference gives 14.5% real project IRR at a seven-cent real price, or 11.6% after the combined yield and curtailment downside. A complete $400,000/MWp project would give 25.1% on the same assumptions. These are pre-tax, unlevered outcomes with no terminal value. Existing infrastructure, different cost scope, procurement dates and capacity denominators can all contribute to the commercial-versus-utility cost gap; available disclosures do not quantify each contribution.

The three business models have different revenue foundations: avoided electricity purchases, contracted electricity sales, and equipment or service margins. Their outcomes turn on complete project cost, billable or self-consumed output, duration and collection. Storage, export settlement and wheeling add value only through defined costs and payment rights. The evidence supports these conditional comparisons; it does not establish a sector-wide return or an investment recommendation.

Calculation method and source notes

The 20-year business and 25-year utility models calculate annual cash flow as valued generation less O&M and the stated replacement. Initial capital is paid at time zero; generation degrades from year two. Prices and operating costs remain constant in real USD, with no terminal value. IRR sets NPV to zero; NPV uses the stated real hurdle. Simple payback divides capital cost by first-year savings after O&M and excludes later degradation and replacement. The separate seven-year case below the utility tables instead uses nominal USD. Values are rounded.

Required PPA price equals discounted costs divided by discounted paid energy. The capex ceiling equals discounted operating cash flows before the initial investment. The separate debt illustration uses nominal cash flows and nominal interest, a replacement reserve and no balloon. It is not an integrated equity-return forecast. The calculator exposes the assumptions and exports annual cash flows; it is an annual screening model, not an hourly dispatch, tax, construction-finance or network study.

1. IRENA: Energy transition assessment, Iraq, 2025

2. Iraq Technology Needs Assessment report for mitigation and adaptation (2022), Ministry of Environment-hosted; p.57 and annex p.86: resource potential, not metered project yield

3. Runaki official tariff calculator; tariffs rechecked 11 October 2026; effective-date instrument not obtained

4. KRG Ministry of Electricity: coverage and debt-instalment announcement, 20 September 2026

5. TotalEnergies: GGIP release, 10 January 2025

6. Qatar News Agency: solar partnership agreement, 28 October 2024

7. pv magazine: Basra trial milestone, 4 March 2026

8. Iraq Business News: PowerChina/Muthanna discussions, 29 August 2026

9. Masdar: five-project Iraq agreement, 7 October 2021

10. Shafaq News: UGTR/Sun Africa executive interview, 17 July 2026

11. 964media: Najaf land handover, 3 May 2026

12. IraqiNews: KRG/JEC solar proposals, 1 July 2026

13. pv magazine: Karbala module manufacturing, 22 July 2026

14. LONGi: Hi-MO 7 LR5-72HGD product brochure, temperature coefficient

15. IEA PVPS Task 13: Soiling losses, 2022, measurement and mitigation sections

16. EIA Iraq Country Analysis Brief (July 2025), p.11: 2024 federal electricity estimates

17. US Department of Energy: inverter and grid-services capabilities

18. CBI: renewable-energy finance initiative, 9 July 2026

19. Progress Sun: published project references and delivery roles

20. Solarix: Iraq office, services and listed brands

21. Sungrow: distributor directory, Kol AlManafith, Baghdad

22. Madi Renewable Energy: company-described distribution relationships

23. FAO/UNGM: solar VFD pumping systems, notice 2026/FNIRQ/FNIRQ/138066

24. Shafaq: direct interview with Basra Investment Commission director, 3 February 2025 — $820m solar estimate

25. TotalEnergies: Shareholders’ Newsletter 78, Fall 2025, p.12 — 1 GWac / 1.25 GWp

26. Iraqi Prime Minister’s Media Office, Cabinet decisions, 30 May 2023: Basra take-or-pay decision and Muthanna approval, posts 29040–29041

27. Hassan et al., JREE 13(3), 2026, section 5.3/Table 3: modelled Baghdad PV cost; price-observation date not established

28. North Power Company: completed solar contracts — 2.22 MWp / 3.379 MWh UNAMI package, July 2024

29. Ecoprogetti: Iraq module manufacturing line, 10 July 2026 — installed line capacity

30. Al-Kafeel: Karbala factory opening — first-phase capacity and operating organisation

31. ZMC Solar: industrial-solar guide, 22 August 2026 — indicative installed-price table and 500 kWp worked example

32. ZMC Solar: shops and businesses guide, 16 May 2026 — estimated installation prices; batteries extra

33. SOLYGENS: installed solar/storage package prices, undated offers checked 10 October 2026

34. US Department of Energy: 2025 PV cost-benchmark methodology — cost categories and configuration; not Iraqi prices

35. US Department of Energy: large-scale solar siting — land, connection and development scope

36. US Department of Energy: solar soft costs — permitting, financing and business overhead

37. Reuters: Basra solar interviews, April 2026; Haider Adnan operating-milestone statement recorded 21 April.