What does a RoR PPA contain?

Notes: Clause references are to the executed PPA unless otherwise stated.

The Power Purchase Agreement (PPA) under review is a take-or-pay arrangement – the foundational bankability requirement for project-financed run-of-river (RoR) hydropower. In review, I found many interlocking provisions that when read cumulatively materially dilute many commercial and operational risk.

In practice, its take-or-pay obligation is materially diluted through a series of interlocking provisions that, read cumulatively, transfer the majority of commercial and operational risk to the developer while insulating the off-taker from the financial consequences of its own infrastructure failures and grid management shortcomings. This post identifies 20 distinct risk provisions across nine thematic areas. Each is assessed for financial impact, benchmarked against international project finance standards, and accompanied by a recommended position.

Theme	Severity	Bankability Impact
A – Take-or-Pay Architecture	Critical	High
B – Pre-COD / RCOD Risk	Critical	Very High
C – 30% Dry Season Rule	High	High
D – Compensation Framework	High	Medium–High
E – Billing & Payment	Medium	Medium
F – Third-Party Sales Prohibition	High	Medium–High
G – Connection Agreement Asymmetries	Medium–High	Medium
H – Security & Termination	High	High
I – Additional Structural Risks	Medium	Medium

SECTION I  DOCUMENT FRAMEWORK & KEY PARAMETERS

1.1  Project Parameters

The following parameters are used consistently throughout this analysis.

Parameter	Value	Source
Annual Contract Energy (ACE)	418,078,634 kWh (~418 GWh)	Schedule 2.1, Table III
Dry Season Contract Energy (DSCE)	127,805,486 kWh (30.57%)	Schedule 2.1, Table III
Wet Season Contract Energy (WSCE)	290,273,148 kWh (69.43%)	Schedule 2.1, Table III
Dry Season Tariff – Year 1 (DST)	NPR 8.40 / kWh	Article 12.1
Wet Season Tariff – Year 1 (WST)	NPR 4.80 / kWh	Article 12.1
PPA Capacity	70,442 kW	Schedule 2.1, Table I
Total Project Cost (Base)	NPR 16,576,203,904	Schedule 1
Performance Guarantee	NPR 5 crore (~NPR 50 million)	Clause 38.15
PPA Term	30 years from COD or Generation Licence term, whichever shorter	Clause 2.1
RCOD	Ashad 20, 2082 BS (~July 4, 2025)	Clause 1.1(Jha)

BASELINE ANNUAL REVENUE – FULL CONTRACT DELIVERY (Year 1) Annual Revenue =  (DSCE × DST) + (WSCE × WST)                =  (127,805,486 × NPR 8.40)  +  (290,273,148 × NPR 4.80)                =  NPR 1,073,566,082  +  NPR 1,393,311,110                ≈  NPR 2.47 billion / year  (theoretical maximum, Year 1)   Blended Average Tariff  =  NPR 2,466,877,192 / 418,078,634 kWh  ≈  NPR 5.90 / kWh

1.2  Structural Architecture

The PPA is structured as a 30-year energy supply agreement with an embedded take-or-pay obligation on the off-taker (Clause 10.1). The developer sells exclusively to the utility at regulated tariffs; dispatch is managed by the Load Dispatch Centre (LDC). The transmission connection is governed by a separate Grid Connection MOU (Annex 6), originally executed in 2077/06/29 and amended in 2079/02/10 through a Minutes of Meeting.

The layered documentation – PPA body, Annex 6 MOU, Minutes of Meeting, and Connection Agreement exhibits – creates multiple points of interpretive risk. Several critical obligations are defined in one instrument while their financial consequences are determined in another, creating scope for the off-taker to benefit from gaps between a procedural promise and an enforceable remedy, which is a bankability concern.

SECTION II  THEMATIC RISK ANALYSIS

THEME A – TAKE-OR-PAY ARCHITECTURE: STRUCTURAL ASYMMETRY IN OBLIGATION DESIGN

The take-or-pay obligation is what allows project finance lenders to model assured debt service coverage. The provisions below, individually and cumulatively, dilute this obligation to a degree that requires structural amendment before the PPA meets standard bankability criteria.

A.1  The 80% Monthly Minimum – A Reverse Penalty on the Developer

Relevant Clause: Article 10.2

Article 10.2 establishes that if monthly energy delivered by the developer falls below 80% of the lesser of the Contract Energy or Availability Declaration for that month, the developer is obligated to pay compensation directly to the off-taker. If the calculation yields a negative result – meaning the developer has over-delivered – no obligation arises. The compensation formula is:

COMPENSATION FORMULA – ARTICLE 10.2 Compensation Payable by Developer to Off-Taker:   = [ 0.80 × min(Monthly Contract Energy, Availability Declaration) − (Actual Energy Delivered + Forced Outage Energy + Scheduled Outage Energy + Force Majeure Energy) ] × Purchase Rate for that Month   Note: If result is negative, amount = zero (no obligation on developer).

Problem

This clause inverts the standard risk allocation model. In a bankable take-or-pay PPA, the seller’s only consequence for underperformance is lost revenue – no energy delivered means no payment received. Here, the developer must also pay the off-taker cash out of pocket if delivery falls short of the 80% threshold for reasons attributable to the developer. The threshold is set at a commercially demanding level: in a four-unit plant, a single turbine failure reduces available capacity by 25%, and if the remaining three units cannot fully compensate due to concurrent flow constraints, the penalty triggers immediately. The developer suffers a revenue loss and simultaneously faces a cash outflow – a double-negative event that is particularly destructive during any unplanned outage.

Financial Impact

WORKED EXAMPLE – TURBINE FAILURE IN PEAK WET SEASON Scenario: One turbine fails in a peak wet month (32-day month). Monthly Contract Energy ≈ 64,130,041 kWh (Schedule 2.1)   80% Threshold = 0.80 × 64,130,041 = 51,304,033 kWh   Available with 3 of 4 turbines, constrained by flow:   Delivered Energy (assumed)  =  44,000,000 kWh   → Below 80% threshold: penalty triggered.   Cash Penalty to Off-Taker:   = (51,304,033 − 44,000,000) × NPR 4.80   = 7,304,033 kWh × NPR 4.80  =  NPR 35,059,358   Revenue Lost (same month):   = (64,130,041 − 44,000,000) × NPR 4.80  =  NPR 96,624,197   TOTAL IMPACT (one month):  NPR 35.1M penalty + NPR 96.6M lost revenue   = NPR ~131.7 million (~NPR 13.2 crore)   → Revenue loss AND outgoing cash penalty in the same event.

International Standard

Under IFC Performance Standards and comparable ADB-financed RoR PPAs in South Asia (Bhutan, Sri Lanka), unplanned outage risk is borne by the seller in terms of lost revenue only. The imposition of a positive cash penalty flowing from seller to buyer for mechanical underperformance is absent from any bankable regional PPA in the comparable universe. The closest analogue – liquidated damages for failure to achieve COD – applies only at the pre-commercial operation stage and is not replicated as an ongoing 30-year operational liability.

Bankability Concern

This clause introduces a liability that co-occurs directly with revenue loss. In a stressed hydrology scenario combined with equipment failure – both of which are foreseeable in a Himalayan run-of-river project – DSCR can breach 1.0x in a single month, potentially triggering lender covenant default. No standard project finance DSCR model incorporates outgoing cash penalties concurrent with revenue loss; lenders will require this risk to be either removed or capped before approving debt drawdown.

▶  RECOMMENDED RENEGOTIATION POSITION Replace Article 10.2 with a proportionate revenue-reduction mechanism only: if the developer delivers less than 80% of the monthly benchmark for reasons attributable to the developer(excluding Force Majeure, off-taker grid outage, and Scheduled Outage), payment for that month is reduced proportionally to actual delivery. No positive cash penalty should flow from the developer to the off-taker for operational underperformance.

A.2  The 10% Wet Season Reserve Margin – Uncompensated Capacity Withholding

Relevant Clause: Article 10.1(Ka) and associated provisos

During wet season months (Ashadh through Kartik – the peak generation period), Article 10.1 explicitly permits the off-taker to withhold 10% of the Contract Energy or Availability Declaration as a Reserve Margin at the LDC’s direction. The PPA states that no compensation is payable for energy withheld as Reserve Margin.

Problem

This provision grants the off-taker a contractual right to withhold payment for up to 10% of the developer’s peak-period generation capacity every wet season for the entire 30-year PPA life. The developer bears the full capital and operating cost of that capacity while receiving nothing in return. This is structurally equivalent to the off-taker holding a perpetual free call option on 10% of peak capacity – an instrument that has real economic value but is provided at zero cost.

Financial Impact

ILLUSTRATIVE ANNUAL COST OF RESERVE MARGIN Annual Wet Season Contract Energy (WSCE) = 290,273,148 kWh Peak wet months (Ashadh–Kartik) ≈ 5 months ≈ 5/8 of wet season energy   Reserve Margin Energy Withheld / Year (if consistently exercised):   = 10% × (5/8 × 290,273,148)  =  18,142,072 kWh / year   Annual Revenue Loss (wet season tariff NPR 4.80):   = 18,142,072 × NPR 4.80  =  NPR 87,081,946 (~NPR 87 million / year)   Present Value over 30 years (10% discount rate):   = NPR 87M × 9.427  ≈  NPR 820 million  (~NPR 82 crore)

International Standard

Under IFC model PPAs and the World Bank’s Regulatory Framework for Energy, any instruction by the off-taker to reduce generation below the plant’s available capacity is a dispatch curtailment triggering compensation at the applicable tariff rate or a capacity payment equivalent. A no-compensation reserve margin carve-out directly contradicts this standard.

▶  RECOMMENDED RENEGOTIATION POSITION Convert the Reserve Margin to a paid Capacity Reservation Fee: the off-taker pays a minimum of 50% of the applicable seasonal tariff for any energy withheld as Reserve Margin. This transforms a free option into a remunerated standby service, consistent with international capacity reservation conventions.

A.3  Excess Energy: 50% Discount and Forced Continued Operation

Relevant Clauses: Articles 9.7 and 12.2

Article 9.7 mandates that if the developer delivers 100% of the monthly Contract Energy or Availability Declaration before the calendar month ends, it must continue generating and delivering power for the remaining days. This continuation energy is classified as ‘Excess Energy.’ Article 12.2 then prescribes that the off-taker pays only 50% of the normal purchase rate for all Excess Energy and may decline to pay entirely if no Dispatch Instruction is issued.

Problem

Article 9.7 creates a binding legal obligation to continue generation. Even absent that obligation, a run-of-river developer faces a binary choice: generate excess energy at a deeply discounted rate, or spill the water entirely and earn nothing. The contractual compulsion simply eliminates the second option entirely. The developer bears full O&M cost, turbine wear, and depreciation while the off-taker pays at a deep discount for energy it compelled the developer to produce.

Financial Impact

EXCESS ENERGY – REVENUE LOSS ILLUSTRATION Scenario: Stronger monsoon delivers 10% excess in 4 wet months. Monthly CE (Shrawan) ≈ 50,847,041 kWh Excess per month = 10% × 50,847,041 = 5,084,704 kWh   At Normal Tariff (NPR 4.80):  5,084,704 × 4.80 = NPR 24,406,579 At 50% Tariff:                5,084,704 × 2.40 = NPR 12,203,290 Monthly Revenue Loss (discount only):            NPR 12,203,290   Annualised (4 excess months): NPR 12.2M × 4 = NPR ~48.8 million / year   [This is the discount loss – developer still receives 50% tariff]   If off-taker refuses Dispatch Instruction entirely (zero payment):   Full loss per month = NPR 24,406,579   Full annual loss    = NPR 24,406,579 × 4 = NPR 97,626,316 (~NPR 97.6M / year)   [These are two separate scenarios, not additive figures]

International Standard

ADB-financed run-of-river PPAs in South and Southeast Asia prescribe a secondary energy tariff of 70–80% of the primary tariff for excess generation. A 50% rate is at the severe end, and the right to refuse payment entirely for Excess Energy is absent from any bankable regional PPA.

▶  RECOMMENDED RENEGOTIATION POSITION Establish a tiered Excess Energy tariff: 80% of the applicable seasonal rate for excess up to 20% above the monthly declaration; 70% beyond that threshold. Eliminate the off-taker’s right to refuse payment for Excess Energy. If the grid cannot absorb the energy, that constitutes a Forced Outage attributable to the off-taker, triggering Schedule 3 compensation.

A.4  Availability Declaration Rigidity

Relevant Clauses: Articles 9.5(Ka), 9.5(Kha), 9.6

The PPA requires the developer to submit an hourly availability forecast at least 30 days before each contract month. Once accepted, this declaration becomes the reference benchmark for compensation calculations. A revision is permitted at least 7 days before the month, but once the month commences, the declaration is frozen.

What happens if no Availability Declaration is submitted?  Per Article 9.5(Ka), failure to submit defaults the declaration to the applicable Contract Energy values from Schedule 2.1. This has two material consequences. First, the developer cannot claim lower hydrology as a defence against the 80% monthly minimum penalty – the off-taker will hold it to the full schedule values regardless of actual river conditions. Second, without a timely declaration documenting reduced expected output, the developer weakens any subsequent compensation claim by losing the formal record of declared availability. Submitting the monthly declaration is therefore commercially essential: it creates the legal record against which all compensation calculations and penalty triggers are measured. In a drought year where the developer knowingly expects below-contract output, failing to submit a reduced declaration could turn a difficult month into a penalty-triggering one.

Problem

Himalayan run-of-river hydrology is not reliably predictable 30 days in advance. Flash floods, glacier-melt surges, and rapid dry-season drawdowns can materially alter flow within 48–72 hours. The 30-day horizon forces the developer into a dilemma: over-declare (risking the 80% monthly minimum penalty if flow disappoints) or under-declare conservatively (artificially suppressing the compensation ceiling). The 7-day revision window is inadequate given the river system’s hydrological behaviour.

▶  RECOMMENDED RENEGOTIATION POSITION Implement a tiered declaration system: a 30-day indicative forecast (non-binding), a 7-day preliminary declaration, and a 48-hour final declaration. Only the 48-hour final declaration should serve as the reference for compensation and penalty calculations. Annual contract energy should be subject to hydrology-based review every 5 years (see I.2).

THEME B – PRE-COD RISK ALLOCATION: THE STRANDED ASSET PROBLEM

This theme presents the highest bankability risk in the PPA. It concerns the financial consequences when a fully-built project cannot achieve its Commercial Operation Date (COD) because the off-taker’s grid infrastructure is not ready. The provisions analysed here are directly referenced in the Grid Connection MOU and constitute the core project finance viability test.

B.1  Absence of a Deemed COD Clause and the RCOD/COD Gap

Relevant Clauses: Articles 4.4, 12.4; Definitions Article 1.1(Ja) and 1.1(Jha)

COD (Commercial Operation Date, Article 1.1(Ja)) is the date on which the project completes commissioning tests, synchronises with the grid, and the off-taker officially declares commercial production begun. COD is therefore dependent not only on the developer completing its infrastructure but also on the off-taker completing its 220kV transmission line.

RCOD (Required Commercial Operation Date, Article 1.1(Jha)) is the contractually mandated deadline for achieving COD – Ashad 20, 2082 BS.

Article 12.4 provides that if the developer completes construction and testing before the RCOD, the off-taker may – at its option – issue Dispatch Instructions and take electricity up to the capacity its existing grid can absorb, paying at the rates in Articles 12.1 and 12.2. However, if energy is not taken or not given in this pre-RCOD window, neither party owes the other any compensation. This is an optional early offtake arrangement, not a mandatory take-or-pay obligation, and is not the primary source of stranded asset risk. That risk arises post-RCOD, governed by Article 4.4.

Article 4.4 provides a limited remedy for the post-RCOD period: once the RCOD has passed and the off-taker’s transmission infrastructure is still incomplete, the off-taker must pay a penalty:

CLAUSE 4.4 PENALTY FORMULA Penalty (NPR) = 0.05 × Contract Energy × (Days of Off-Taker Delay / Days between RCOD and COD) × Purchase Rate applicable at COD   Maximum annual penalty ≈ 5% of one year’s Contract Energy revenue.

Three Compounding Gaps

• Gap 1 – Pre-RCOD Early Completion Window: If the developer finishes early but NEA’s existing grid cannot absorb the output, Article 12.4 makes this an optional arrangement. NEA may take what the grid can absorb at PPA rates, but if it cannot take it, neither party compensates the other. The developer earns no guaranteed revenue during this early completion window. Clause 4.4 does not engage until after the RCOD passes.
• Gap 2 – The 5% Post-RCOD Penalty is Grossly Insufficient: A true Deemed Generation clause requires 100% of foregone revenue. Clause 4.4 delivers ~5% – wholly insufficient to cover debt service, O&M, or equity return during a prolonged off-taker delay.
• Gap 3 – No Deemed COD: The PPA contains no provision deeming COD to have occurred when the plant was ready, regardless of grid availability. Without this, full take-or-pay obligations never commence until the off-taker’s grid is ready.

Financial Impact

STRANDED ASSET SCENARIO – 18-MONTH COMBINED DELAY Scenario: Developer completes 6 months before RCOD.           Off-taker’s 220kV line is delayed 12 months beyond RCOD.           Total period of zero/minimal revenue = 18 months.   Monthly average revenue ≈ NPR 2,466,877,192 / 12 = NPR 205,573,099 / month   PRE-RCOD (6 months) – Article 12.4 optional arrangement:   If NEA grid cannot absorb: zero compensation to either party.   Lost Revenue = NPR 205,573,099 × 6 = NPR 1,233,438,598   POST-RCOD (12 months) – Clause 4.4 applies:   Annual Clause 4.4 Penalty = 0.05 × 418,078,634 kWh × NPR 5.90 = NPR 123,393,197   Actual Revenue Foregone   = NPR 205,573,099 × 12 = NPR 2,466,877,188   Compensation Gap (12 mths)= NPR 2,343,483,991 (~NPR 234 crore unrecovered)   TOTAL 18-MONTH IMPACT:   Revenue Lost = NPR 3,700,315,786 (~NPR 370 crore)   Compensation Received = NPR 123,393,197   (~NPR 12.3 crore)   Total Unrecovered = NPR 3,576,922,589 (~NPR 358 crore)   Estimated 18-month debt service derivation:   Debt (70% LTV): 0.70 × NPR 16,576,203,904 = NPR 11,603,342,733   Annuity factor (10%, 15yr): r(1+r)^n/((1+r)^n−1) = 0.10×4.177/(4.177−1) = 0.13147   Annual debt service = NPR 11.603B × 0.13147 = NPR 1,525,697,000   18-month debt service = NPR 1,525,697,000 × 1.5 = NPR 2,288,546,000 ≈ NPR 2.25B   → Clause 4.4 receipts cover only ~5.4% of 18-month debt service obligations.

International Standard

IFC model PPAs, ADB hydropower project standards, and EBRD financing terms all require: (1) a Deemed COD declared when the plant is ready and the off-taker cannot receive power; (2) full take-or-pay obligations commencing from Deemed COD; and (3) Deemed Generation compensation at 100% of the revenue the plant would have earned. The World Bank’s 2019 Utility-Scale Renewable Energy Procurement guidance explicitly classifies the absence of a Deemed COD provision as a ‘bankability-preventing clause’ requiring remedy before project finance approval.

Bankability Concern

This is the most critical bankability risk in the PPA. No project finance lender will accept a structure where a completed plant earns zero revenue with no adequate enforceable claim on the off-taker, and where the only remedy – Clause 4.4’s 5% formula – recovers approximately 5 cents on every rupee of debt service due. The gap between Clause 4.4’s recovery and actual debt service obligations is decisive.

▶  RECOMMENDED RENEGOTIATION POSITION 1. INSERT A DEEMED COD CLAUSE: If the plant achieves Test Generation but COD cannot be declared solely due to off-taker grid unavailability, COD shall be deemed to have occurred 15 days after Test Generation completion, regardless of grid readiness.   2. From Deemed COD, the off-taker’s full take-or-pay obligation at 100% of applicable tariff on Contract Energy commences immediately.   3. REPLACE CLAUSE 4.4’s 5% formula with a minimum guaranteed monthly payment equal to the scheduled monthly debt service (agreed at Financial Closure).   4. Clarify that Article 12.4’s optional pre-RCOD arrangement cannot be invoked as a basis to deny Deemed COD protection once the RCOD has passed.

B.2  Compounding Tariff Escalation Penalty for Construction Delays

Relevant Clause: Article 12.1

Article 12.1 grants the developer an annual 3% tariff escalation for the first 8 years of commercial operation – commercially essential for partially offsetting inflation over a 30-year concession. These escalations are then made conditional on timely COD achievement. If COD occurs beyond the RCOD, escalations are permanently reduced on the following schedule:

Delay vs. RCOD	Escalations Granted (of 8)	Escalations Lost
Up to 6 months	7	1
6 to 18 months	6	2
18 to 30 months	5	3
30 to 42 months	4	4
42 to 54 months	3	5

Problem

This is not a one-time cash fine – it is a permanent, compounding suppression of lifetime revenue. Each escalation period lost permanently reduces the applicable tariff in every subsequent year of the 30-year contract. The financial damage does not end at COD; it accumulates silently across decades, representing a continuous involuntary wealth transfer from developer to off-taker.

The more critical – and structurally unjust – dimension of this clause is that it is triggered purely by the calendar gap between RCOD and actual COD, with no distinction whatsoever as to which party caused the delay. The clause contains no carve-out for off-taker-caused delays, no exception for geological or force events, and no mechanism to extend the RCOD when the delay is attributable to NEA’s own infrastructure failures.

This creates the following scenario – not hypothetical but a direct contractual risk under current drafting:

• Developer completes all civil, mechanical, and electrical works on time or ahead of RCOD.
• NEA fails to complete its 220kV transmission line, rendering the project unable to synchronise with the grid and pushing COD 12–18 months beyond RCOD.
• Article 4.4’s 5% penalty is the sole post-RCOD remedy – insufficient to cover debt service (Theme B.1).
• Article 12.1 additionally strips 2 of the developer’s 8 tariff escalations – permanently – for a delay NEA itself caused.

The developer is therefore penalised twice for a single NEA failure: first through inadequate compensation during the delay period (Theme B.1), and then through a permanently suppressed tariff for every remaining year of the concession (Theme B.2). These are not alternative penalties – they stack. The NPR 1.57 billion present value loss calculated below could be triggered in its entirety by NEA’s own transmission infrastructure failure while the developer’s plant sits fully operational and idle.

Financial Impact

TARIFF SUPPRESSION – 12–18 MONTH DELAY (6 Escalations vs 8) Base Dry Tariff Year 1: NPR 8.40  |  Base Wet Tariff Year 1: NPR 4.80   With 8 escalations (no delay), tariff at Year 8+:   Dry: NPR 8.40 × (1.03)^8 = NPR 10.64  |  Wet: NPR 4.80 × (1.03)^8 = NPR 6.08   With 6 escalations (12–18 month delay – including NEA-caused delay):   Dry: NPR 8.40 × (1.03)^6 = NPR 10.03  |  Wet: NPR 4.80 × (1.03)^6 = NPR 5.73   Annual Revenue Difference from Year 9 onwards:   = (127,805,486 × [10.64 − 10.03]) + (290,273,148 × [6.08 − 5.73])   = NPR 77,961,346 + NPR 101,595,602 = NPR 179,556,948 / year   PV of lost escalations (Years 9–30, 10% discount, 22yr annuity factor 8.77):   = NPR 179,556,948 × 8.77  ≈  NPR 1.57 billion  (~NPR 157 crore)   Combined double-penalty for one 12-month NEA transmission delay:   Article 4.4 Unrecovered Revenue (12 months): NPR ~2.34 billion   Article 12.1 Tariff Suppression (PV):         NPR ~1.57 billion   Total impact of one NEA failure:              NPR ~3.91 billion (~NPR 391 crore)

▶  RECOMMENDED RENEGOTIATION POSITION 1. CAUSATION-LINKED TRIGGER ONLY: The escalation reduction must apply only to delays constituting Company Default under Clause 16. Any delay where COD is prevented by off-taker infrastructure unavailability, Force Majeure, or geological conditions must trigger an automatic RCOD extension – preserving all 8 escalations intact.   2. ELIMINATE PERMANENT TARIFF IMPACT: Replace escalation-stripping with a time-limited daily cash penalty for developer-caused delays (e.g., NPR X per day, capped at 5% of TPC). The tariff schedule should be inviolable regardless of construction timeline.   3. EXPLICIT NEA DELAY PROTECTION: Where COD is delayed solely due to off-taker failure to complete connection infrastructure by RCOD, Clause 4.4 compensation applies AND the RCOD is automatically extended day-for-day, fully preserving escalation entitlement.   4. RING-FENCE INTERACTION WITH ARTICLE 4.4: Where an RCOD extension is granted due to off-taker infrastructure delay, the Article 12.1 escalation schedule must be similarly extended, ensuring neither provision operates against the developer for the same off-taker default event.

B.3  Financial Closure Deadline and PPA Termination Risk

Relevant Clause: Article 38.2

Article 38.2 establishes a Financial Closure (FC) deadline tied to the generation licence timeline. If FC is not achieved by the specified date, the PPA may be cancelled and the Performance Guarantee forfeited. A 7-day cure notice window applies. The practical challenge is that FC in Nepal’s project finance environment depends heavily on macro-sovereign factors (exchange rate risk, repatriation restrictions, off-taker creditworthiness) that are entirely outside the developer’s control.

▶  RECOMMENDED RENEGOTIATION POSITION Extend the FC cure period to 90 days. Accept a binding term sheet (not a full loan agreement) as evidence of progress toward closure. Partial Performance Guarantee release should apply upon achieving 50% physical construction progress milestones, independent of FC status.

THEME C – SEASONAL ENERGY CONSTRAINTS: THE 30% DRY SEASON RULE

C.1  The Dry Season Minimum and Revenue Recalculation Penalty

Relevant Clause: Article 10.3

Article 10.3 mandates that energy supplied during the dry season (Mangsir 16 to Jestha 15, approximately December 1 to May 31) must represent at least 30% of total annual Contract Energy supplied. If this threshold is missed, the clause does not merely reduce the dry season payment – it recalculates the entire annual energy cap downward to match the actual dry season ratio. The off-taker then refuses payment for all energy above this reduced cap.

ARTICLE 10.3 RECALCULATION FORMULA New Annual Energy Cap  =  Actual Dry Season Energy Supplied / 0.30   Penalty Deduction (NPR)  =  [Total Annual Energy Delivered − New Annual Energy Cap] × Wet Season Purchase Rate   Adjustment spread across subsequent monthly bills.

Problem

A run-of-river developer cannot manufacture dry season flow. Himalayan hydrology is driven by glacier melt, precipitation, and upstream abstractions – all beyond the developer’s control. Schedule 2.1 shows the PPA’s baseline dry season energy at 30.57% – a margin of only 0.57 percentage points above the 30% threshold. Any year of below-average dry season hydrology will trigger this penalty. In the scenario where the dry season underperforms but the monsoon overperforms (the developer generates more total energy than planned), the off-taker receives the excess wet season energy for free while penalising the developer for the seasonal ratio.

Financial Impact – Detailed Worked Example

DROUGHT-YEAR SCENARIO (15% Below-Average Dry Season, 8% Above-Average Wet) Annual Contract Energy (ACE) = 418,078,634 kWh Normal DSCE = 127,805,486 kWh (30.57%)   Actual Dry Season (−15%):  127,805,486 × 0.85 = 108,634,663 kWh (25.98% → BELOW 30%) Actual Wet Season (+8%):   290,273,148 × 1.08 = 313,494,999 kWh Total Delivered:           422,129,662 kWh  → Developer OVER-DELIVERED, yet penalty triggered.   Step 1 – New Annual Cap:    108,634,663 / 0.30 = 362,115,543 kWh Step 2 – Excess Above Cap:  422,129,662 − 362,115,543 = 60,014,119 kWh Step 3 – Penalty Deduction: 60,014,119 × NPR 4.80 = NPR 288,067,771   Step 4 – Net Developer Revenue vs Normal Year:   Normal Annual Revenue:           NPR 2,466,877,192   Gross Revenue (actual delivery): NPR 2,417,307,164   Less Penalty:                  − NPR   288,067,771   Net Revenue Received:            NPR 2,129,239,393   Revenue Reduction vs Normal:     NPR   337,637,799  (~NPR 33.8 crore, −13.7%)   Result: Developer delivered 4 GWh MORE than normal contract.         Off-taker received 60 GWh of wet-season energy effectively for free.

Sensitivity Table

Dry Season Actual %	New Annual Cap (GWh)	Free Energy to Off-Taker (GWh)	Revenue Loss (NPR million)
30.57% (normal)	418.1 (unchanged)	0	0
28.0% (−2.6pp)	394.4	23.7	~114
25.0% (−5.6pp)	354.2	64.0	~307
22.0% (−8.6pp)	306.7	111.5	~535
20.0% (−10.6pp)	278.8	139.3	~669

International Standard

International RoR PPAs that include seasonal minimum requirements typically use a rolling 3-year average to smooth hydrology volatility, rather than a single-year trigger. No bankable international PPA provides the off-taker with free energy above the recalculated cap; the most developer-adverse international standard reduces the secondary energy tariff, it does not eliminate the payment.

Bankability Concern

P90 Hydrology: In hydrology, P90 refers to the flow level exceeded 90% of the time over a long-term record – meaning only 10% of years will be drier. Lenders routinely stress-test revenue projections at P90 (a 1-in-10 dry year) to ensure the project can still service debt in a moderately adverse but statistically probable year. At P90 conditions for Himalayan rivers, dry season flows can be 15–20% below the long-term average, meaning dry season shortfall is a near-certain occurrence in several years of any 30-year model. The revenue cliff created by this clause will appear in every lender’s P90 sensitivity analysis.

Q30 and the 30% Threshold: Q30 refers to the discharge level that a river equals or exceeds for 30% of the time – approximately 109 days per year. In run-of-river hydrology, dry season generation is often characterised relative to Q30 exceedance flows. The PPA’s 30% dry season energy threshold implicitly assumes that at design flow conditions the plant generates sufficient dry season energy to meet the ratio. Schedule 2.1’s baseline of 30.57% sits only marginally above this design assumption – confirming that the 30% threshold was calibrated to expected performance under normal Q30-equivalent hydrology, with virtually no buffer for any year that departs from the design basis.

▶  RECOMMENDED RENEGOTIATION POSITION 1. Replace the single-year threshold with a rolling 3-year average: the 30% threshold is assessed on the average of the current and two preceding fiscal years. Single-year weather events do not trigger recalculation.   2. If the threshold is breached, limit the remedy to a reduction in dry season tariff for that year’s shortfall – do not recalculate the wet season entitlement.   3. Insert a Force Majeure carve-out for drought years certified as statistically exceptional (below P90 flow levels) by the Department of Hydrology and Meteorology.

THEME D – COMPENSATION FRAMEWORK: THE DILUTED TAKE-OR-PAY PROMISE

D.1  The 72-Hour Annual Free Outage Window

Relevant Clause: Schedule 3 – Compensation Formula Conditions

Schedule 3 governs the take-or-pay compensation formula (triggered by Article 10.1). After establishing the Undelivered Energy calculation using Forced Outage and Non-dispatched Hours, Schedule 3 contains an override: Compensation Amount equals zero if the cumulative Prorated Time (PT) for the fiscal year is 72 hours or less (N = 72 hrs).

Problem

This gives the off-taker a contractual free pass to fail its take-or-pay obligation for up to 72 cumulative hours – three full days – per fiscal year without any financial consequence. Given the frequency of grid instabilities in developing hydropower markets, this provision is not a theoretical safeguard but a practically exploitable exemption.

ANNUAL COST OF 72-HOUR FREE OUTAGE WINDOW Available Capacity = 70,442 kW Free Outage Window = 72 hours / year   Maximum Free Energy per Year:   = 70,442 kW × 72 hrs = 5,071,824 kWh   Revenue Value (blended NPR 5.90/kWh):   = 5,071,824 × NPR 5.90 = NPR 29,923,762 (~NPR 30 million / year)   Present Value over 30 years (10% discount): NPR 29.9M × 9.43 ≈ NPR 282 million

▶  RECOMMENDED RENEGOTIATION POSITION Eliminate the 72-hour free window, or reduce to a maximum of 12 hours per fiscal year (consistent with international grid reliability standards). Any forced outage caused by off-taker grid failure should trigger compensation from the first hour. Routine scheduled maintenance should be governed by a pre-agreed maintenance schedule, not absorbed into a generic liability-free window.

D.2  The 100% Monthly Delivery Compensation Nullification

Relevant Clause: Schedule 3 – Second override condition

Schedule 3 also provides that Compensation Amount equals zero if dispatched and delivered energy in the month equals or exceeds 100% of the smaller of Contract Energy and the Availability Declaration. In such event, all Forced Outage Hours and Non-dispatched Hours for that month are deemed zero, retroactively cancelling any compensation liability.

Problem

This clause enables the off-taker to mismanage its grid in early weeks of a month, then receive complete absolution if the developer recovers by operating at maximum capacity in later weeks. The developer absorbs all cost of the forced downtime – lost water, recovery operational intensity, equipment wear – while the off-taker gains a full liability release. It creates a perverse incentive: the off-taker faces no financial consequence for week-one grid failures if the developer can recover by month-end.

▶  RECOMMENDED RENEGOTIATION POSITION Delete this provision. Compensation for discrete Forced Outage events should be calculated on an event-by-event basis and should not be subject to retroactive monthly cancellation based on recovery generation. If any form of this clause is retained, it should apply only where the off-taker pre-arranged a written recovery schedule with the developer.

D.3  Black Start and Off-Grid Mode Compensation Exemption

Relevant Clauses: Articles 7.1 and 7.2

Article 7.1 grants the off-taker an unconditional right to instruct the developer to perform a Black Start (restarting a completely dead national grid) or operate in Off-Grid Mode (running in isolation from the main grid). Article 7.2 states that if the developer fails to perform either operation upon instruction, the off-taker is exempt from paying take-or-pay compensation for that period.

When are these operations essential?  A Black Start is required when the entire national grid collapses – for example, if a major earthquake or cascading transmission fault simultaneously trips all generation units and the grid goes completely dark. In that scenario, NEA needs at least one unit capable of self-starting using its own stored energy (auxiliary power, batteries) and injecting initial voltage into a dead system. Hydropower units are among the most suitable Black Start sources because they can be started without external grid supply. Off-Grid Mode is required when a section of the grid becomes electrically isolated from the main system – for example, if a key 220kV transmission line fails and cuts off a load centre or district. NEA may then instruct a generating unit within or near that isolated section to operate as a standalone island, supplying only local load at stable frequency without synchronisation to the wider grid.

Problem

Black Start and Off-Grid operations impose severe electrical and mechanical stress on turbines and generators well beyond normal operating parameters. A national grid collapse requiring Black Start is definitionally a catastrophic off-taker failure. This clause transfers the financial consequence of that failure to the developer: if the developer hesitates to protect its multi-billion-rupee equipment, the off-taker escapes its payment obligations entirely.

▶  RECOMMENDED RENEGOTIATION POSITION 1. Remove the compensation exemption in Article 7.2. Take-or-pay obligations should not be contingent on the developer’s willingness to perform technically hazardous emergency grid operations.   2. Govern Black Start capability through a separate Technical Services Agreement with appropriate compensation for additional risk and equipment wear.   3. Off-taker should bear full liability for any equipment damage resulting from Black Start or Off-Grid operations performed at its direction.

THEME E – BILLING & PAYMENT: LIQUIDITY RISK THROUGH UNILATERAL DEDUCTIONS

E.1  Unilateral Deduction of Disputed Invoice Amounts

Relevant Clause: Article 13

Article 13 establishes a 45-day payment cycle. Upon receiving a monthly invoice, the off-taker may identify ‘discrepancies,’ unilaterally deduct the disputed amount, and pay only the undisputed balance. The disputed sum is held by the off-taker pending formal dispute resolution. Disputes not resolved within 90 days go to arbitration (Articles 29–30). A 6% annual simple interest applies to overdue amounts; a 3% rebate applies for timely payment.

Problem

The off-taker is simultaneously the buyer and the primary arbiter of invoice validity. By raising a ‘dispute’ requiring no third-party validation, it can legally withhold any portion of any invoice indefinitely. Nepal’s arbitration timeline for regulatory-level disputes can exceed 12–24 months. The 6% interest rate on withheld amounts is substantially below commercial project finance borrowing rates (10–13% in NPR), creating a negative incentive to resolve disputes promptly – the off-taker effectively benefits from withholding.

LIQUIDITY COST – DISPUTED INVOICE ILLUSTRATION Scenario: Off-taker disputes 20% of monthly invoice for 18 months. Monthly Invoice (Year 1): NPR 205,573,099 Disputed Amount (20%):    NPR  41,114,620   Interest Received by Developer (6% p.a., 18 months):  NPR 3,700,316 Developer’s Borrowing Cost (12%, 18 months):           NPR 7,400,632   Net Interest Cost to Developer:                        NPR 3,700,316   → Off-taker profits from delayed payment relative to developer’s cost of capital.   → No commercial deterrent to raising disputes exists under current drafting.

▶  RECOMMENDED RENEGOTIATION POSITION 1. Link the overdue interest rate to the off-taker’s commercial borrowing rate or the Nepal Rastra Bank rate plus 3%, whichever is higher.   2. Require disputed amounts to be deposited into a jointly-controlled escrow account within 10 days of dispute notification, earning market interest.   3. Limit the right of unilateral deduction to metering errors with physical evidence. Commercial disputes must be referred to the Coordination Committee, not resolved through invoice deduction.

THEME F – THIRD-PARTY SALES PROHIBITION: THE MONOPOLISTIC LOCK-IN

F.1  The Absolute Ban on Alternative Sales

Relevant Clause: Article 5.2

Article 5.2 prohibits the developer from selling or transferring rights to its generated electricity to any entity other than the off-taker without prior off-taker approval, for the full 30-year term.

Problem

Read alongside Excess Energy pricing (50% discount, potential non-payment), the Reserve Margin carve-out (10% free), and the Dispatch Instruction discretion, Article 5.2 creates a perfect monopoly trap. The developer generates power that the off-taker either takes at discounted rates, withholds free, or refuses – yet the developer cannot approach any alternative buyer. Cross-border electricity trading under Nepal’s Power Trade Agreement framework, and direct sales to large industrial consumers, are both blocked without off-taker approval the off-taker has no incentive to grant.

Dispatch order flexibility in Nepal’s context:  Under the NEA Grid Code and Article 9.4 of the PPA, Dispatch Instructions are issued by the Load Dispatch Centre (LDC) and can be issued at any time of day with virtually immediate effect. There is no minimum advance notice requirement in the PPA for routine generation changes – the LDC can reduce, increase, or curtail generation instructions within minutes of issuing them. In Nepal’s current power system, where grid frequency management is still developing and load patterns are irregular, dispatch instructions can fluctuate multiple times within a single day. The developer has no right to refuse or delay compliance, and no right to compensation for rapid generation changes – unless cumulative undelivered energy crosses the Schedule 3 threshold. Combined with the third-party sales ban, this means the developer is both unable to resist arbitrary curtailment and unable to redirect that curtailed energy elsewhere.

VALUE OF LOST THIRD-PARTY SALE OPTION Cross-border sale price (India exchange, approximate): NPR 7–9/kWh vs. Wet Season PPA Tariff:                            NPR 4.80/kWh Premium over PPA wet season tariff:                   NPR 2.20–4.20/kWh   Excess/curtailed energy estimate (conservative 15% of wet season):   = 15% × 290,273,148 kWh = 43,540,972 kWh / year   Lost Premium (at NPR 2.20 conservative):   = 43,540,972 × NPR 2.20 = NPR 95,790,138 / year (~NPR 95.8 million)   Present Value (10% discount, 30 years): NPR 95.8M × 9.43 ≈ NPR 903 million (~NPR 90 crore)

▶  RECOMMENDED RENEGOTIATION POSITION Amend Article 5.2 to include a Right of First Refusal structure:   – Off-taker retains first right to purchase all energy at PPA tariff.   – If off-taker exercises its right to withhold, curtail, or discount energy (Reserve Margin, Excess Energy non-dispatch), developer automatically gains the right to sell that quantity to any third party, including cross-border buyers, for 30 days.   – Off-taker approval is deemed granted for any energy the off-taker itself declines.   This preserves the off-taker’s priority position while eliminating its ability to simultaneously refuse purchase and block third-party sales.

THEME G – CONNECTION AGREEMENT: ASYMMETRIES IN ANNEX 6

G.1  Rental and Shutdown Charges on Developer-Funded Infrastructure

Relevant Provisions: Grid Connection MOU (Annex 6) – Clauses 13 and 14

Despite the developer constructing and fully funding a 1.4 km 220kV double circuit transmission line (MOU Clause 12.2), the MOU requires the developer to pay the off-taker annual charges from COD: NPR 432,000 per year per bay (if the off-taker provides land), NPR 108,000 per year for control panel space, and NPR 108,000 per year for control panel operation. MOU Clause 14 also requires a shutdown charge payable to the off-taker for the grid shutdown needed during commissioning.

Problem

The developer built the connection infrastructure that delivers power to the off-taker and then is charged rent for the substation bays that enable the off-taker to receive it. The principle is commercially perverse: a supplier building delivery infrastructure to a buyer’s premises should not pay the buyer for the connection point. While the quantum is modest, it represents an ongoing drain from a party that has already borne the full capital cost.

▶  RECOMMENDED RENEGOTIATION POSITION Eliminate rental and operation charges for connection infrastructure constructed entirely at the developer’s cost. If off-taker staff are genuinely required for relay panel operation, reimburse at actual documented cost through the Coordination Committee – not as a fixed pre-agreed annual charge.

G.2  The Illusory Financial Protection Promise (MOU vs PPA Conflict)

Relevant Provisions: MOU Clause 15 vs PPA Article 4.4

What is the MOU in context of this PPA?  The Grid Connection MOU (Memorandum of Understanding) is a bilateral technical and commercial agreement between NEA’s Grid Operation Department (as Grid Owner) and the developer (as Grid User) that governs the physical and operational terms of connecting the project to the national grid. It covers the delivery point specification, transmission line construction obligations, metering arrangements, bay charges, and synchronisation requirements. Originally executed separately from the PPA, it is incorporated as Annex 6. Under Article 1.4 of the PPA, the Connection Agreement forms an integral part of the overall agreement – but where any MOU provision conflicts with the PPA body, the PPA body prevails. This hierarchy is precisely the mechanism through which the MOU’s financial protection promise is neutralised by the PPA’s own provisions.

MOU Clause 15 explicitly states that ‘the financial impacts related to Non/Late commissioning of transmission line and associated Substations… shall be specified in the Power Purchase Agreement.’ This clause creates a reasonable expectation that the PPA will contain financial protections for transmission delay risk. In practice, Article 4.4’s 5% penalty formula is the only such protection – wholly inadequate for covering the developer’s actual losses and debt service obligations during a prolonged NEA delay.

Problem

The MOU creates an expectation of meaningful protection that the PPA body then delivers only in token form. A developer relying on MOU Clause 15 in good faith during negotiations would have had a reasonable expectation that its transmission delay risk was substantively addressed. This inconsistency strengthens the basis for a renegotiation demand and could support an arbitration claim on the grounds of frustrated expectations.

▶  RECOMMENDED RENEGOTIATION POSITION Amend the PPA to substantively fulfill MOU Clause 15’s promise by inserting the Deemed COD and Deemed Generation protections recommended under Theme B.1, with express cross-reference to MOU Clause 15 as the founding contractual obligation. The MOU’s promise must be redeemed in substance, not merely acknowledged in form.

G.3  Transmission Line Loss Absorption by Developer

Relevant Clause: Article 11.6

Article 11.6 mandates that Line Loss from the generation point to the Connection Point is deducted from metered energy; the off-taker is billed only for the net energy arriving at the LILO point. Since the developer owns and constructed the 1.4 km transmission line, all its electrical losses are borne by the developer.

ANNUAL COST OF TRANSMISSION LOSS ABSORPTION 1.4 km 220kV line typical losses: ~0.21% of total energy transmitted Annual Energy Lost: 418,078,634 kWh × 0.21% = 877,965 kWh Revenue Value (NPR 5.90 blended): 877,965 × 5.90 = NPR 5,180,001 / year Present Value (30 years, 10%): ≈ NPR 49 million

▶  RECOMMENDED RENEGOTIATION POSITION Meter at the generation bus (powerhouse transformer LV terminals). The off-taker should absorb transmission line losses beyond the powerhouse fence, consistent with the standard international principle: seller pays for generation, buyer pays for delivery.

THEME H – SECURITY PACKAGE AND TERMINATION ASYMMETRY

H.1  The Unconditional Performance Guarantee

Relevant Clauses: Articles 38.15, 38.2, 38.3

Article 38.15 requires the developer to submit an unconditional, irrevocable Performance Guarantee of NPR 5 crore, valid until 90 days after RCOD. The clause operates on a physical progress trigger – not simply on whether COD has been achieved:

• Condition for Release: If physical construction progress at site reaches 50% or more by RCOD, NEA is obligated to release the guarantee – even if COD has not yet been achieved. The developer’s entitlement to guarantee release is therefore tied to construction progress, not commercial operation.
• Condition for Forfeiture: If physical progress at RCOD is below 50%, the guarantee is forfeited. The guarantee is also forfeited if the PPA is terminated before COD due to the developer’s fault, or if the conditions in Articles 38.2 or 38.3 arise.

Problem

While the 50% physical progress trigger is more nuanced than a simple forfeiture-on-delay provision, three asymmetries remain. First, the forfeiture conditions do not distinguish between developer-caused underperformance and delays attributable to external factors or NEA’s own actions – a developer who falls below 50% progress because of NEA-caused site access denials or approval delays faces the same forfeiture as one who simply failed to mobilise. Second, there is no equivalent financial security posted by NEA for its own obligations under the PPA. Third, the NPR 5 crore guarantee represents only approximately 0.3% of the NPR 16.58 billion TPC – too small to deter developer default meaningfully relative to the project’s scale, yet large enough to represent a significant burden on a developer in financial difficulty.

Chapter 17 governs off-taker default. If the off-taker fails its take-or-pay obligations, the developer must issue a Notice of Default, allow a 90-day cure period, and if uncured, seek arbitration. The off-taker posts no equivalent cash bond; no sum is unconditionally available to the developer upon off-taker default.

THEME I – ADDITIONAL STRUCTURAL RISKS

I.1  Test Generation – Zero Revenue for Energy Delivered to Grid

Relevant Clauses: Articles 5.3 and 4.1(Ka)

Article 5.3 explicitly states that during the Test Generation period (between first power production and formal COD declaration), the off-taker is not obligated to pay any amount for electricity supplied. Article 4.1(क) sets a 30-day notice requirement before testing begins. The test period can last 15–30 days depending on satisfactory completion.

TEST GENERATION REVENUE FOREGONE Test period: 15–30 days  |  Capacity: 70,442 kW  |  50% average output   Energy delivered (15 days): 70,442 × 0.50 × 15 × 24 = 12,679,560 kWh Revenue value (NPR 5.90):   12,679,560 × 5.90 = NPR 74,809,404   For 30-day test period: ≈ NPR 149.6 million (~NPR 15 crore) delivered free to grid.

▶  RECOMMENDED RENEGOTIATION POSITION Test generation energy should be compensated at 50% of the applicable purchase rate, reflecting partial commercial value delivered and developer’s O&M costs during the period. This is standard in bilateral RoR PPAs across South Asia.

I.2  Hydrology Revision – Asymmetric Adjustment Mechanism

Relevant Clause: Article 35.18

Article 35.18 provides that every 5 years post-COD, the developer may request a Contract Energy review against actual gauged river discharge. Any revision requires mutual agreement between the parties. There is no obligation on the off-taker to agree to any revision.

Problem

If actual long-term hydrology proves chronically lower than design assumptions – a material risk for any Himalayan RoR project – the off-taker can simply decline revision. The developer then faces a permanent 80% monthly minimum penalty mechanism calibrated against a Contract Energy figure that the river cannot physically support. Conversely, if hydrology is higher than planned, the off-taker has every incentive to agree to an upward revision (more energy at regulated rates), while the developer cannot monetise the upside through third-party sales.

▶  RECOMMENDED RENEGOTIATION POSITION Make hydrology revision mandatory (not optional) every 5 years, based on gauged discharge data from the Department of Hydrology and Meteorology. Revisions must apply symmetrically – both upward and downward – and must adjust Contract Energy, the 30% dry season threshold, and the 80% monthly minimum in proportion.

I.3  Informational Asymmetry – Off-Taker Inspection Rights Without Reciprocity

Relevant Clause: Article 36

Article 36 grants the off-taker unilateral inspection rights over the project’s construction, production, and operational arrangements at any time, with prior notice. The off-taker’s inspectors can review operational data that may inform its dispute strategy. No equivalent right exists for the developer to access the off-taker’s Load Dispatch Centre records, grid availability reports, or transmission infrastructure status logs.

▶  RECOMMENDED RENEGOTIATION POSITION Establish mutual audit rights: the developer should have the right (10 days’ notice) to inspect LDC records pertaining to dispatch instructions, grid availability, and forced outage logs for the connection infrastructure. Informational parity supports the developer’s ability to challenge unjustified Schedule 3 compensation waivers and billing disputes.

I.4  Force Majeure – Design Flood Trigger and 30-Year Occurrence Risk

Relevant Clause: Article 15

Article 15 defines Force Majeure to include floods exceeding the design flood discharge specified in Schedule 1 (6,000 m³/sec). For a Himalayan run-of-river project designed to a 1-in-100-year flood standard, there is a 1% annual probability of a Force Majeure flood – and a near-certainty of at least one such event occurring over a 30-year project life. Every Force Majeure event suspends the off-taker’s compensation obligations under Schedule 3.

Practical example: 
Consider the Melamchi river event of June 2021, in which a glacial lake outburst flood sent debris-laden torrents far exceeding design discharge, causing widespread infrastructure damage. If a comparable event occurred on the Tamakoshi – sending flows above 6,000 m³/sec – the following would occur under Article 15: (a) Force Majeure is declared; (b) NEA’s Schedule 3 compensation obligations are suspended for the duration; (c) even if the plant’s civil structures survive undamaged and the river returns to design flow within 48 hours, the developer earns zero compensation for any dispatch failures or non-generation during the declared period. Over a 30-year life, statistical expectation is that at least one event – potentially multiple – will exceed the 1-in-100-year threshold, each time creating a window of zero NEA liability regardless of actual plant status.

▶  RECOMMENDED RENEGOTIATION POSITION Redefine Force Majeure flood events relative to a probability of exceedance standard (e.g., floods with less than 0.5% annual exceedance probability – 1-in-200-year events) rather than the design flood level. For events below this threshold, a reduced-rate compensation should apply, acknowledging both the developer’s inability to control river flow and the off-taker’s obligation to plan for reasonably foreseeable hydrology.

SECTION III  CONSOLIDATED BANKABILITY RISK MATRIX

The following matrix consolidates findings across all themes and assesses individual and cumulative financial impact on project bankability.

Issue	Clause	Financial Impact (Illustrative)	Lender Concern	Priority
Absence of Deemed COD	4.4	NPR 3.58B unrecovered – 18mo delay	Critical	1
30% Dry Season Rule	10.3	NPR 114–669M/yr (drought severity)	High – P90 risk	1
5% RCOD Penalty (vs 100% Revenue)	4.4	NPR 2.34B gap per delay year	Critical	1
Tariff Escalation Loss	12.1	NPR 1.57B PV – 12–18mo delay	High – permanent	1
80% Monthly Minimum Reverse Penalty	10.2	NPR ~131.7M in single failure month	High – DSCR cliff	2
100% Monthly Nullification	Schedule 3	Retroactive compensation voidance	High	2
10% Reserve Margin – Uncompensated	10.1	NPR 87M/yr; NPR 820M PV	High	2
Excess Energy 50% Discount	12.2	NPR 49–98M / yr	Medium–High	2
Third-Party Sales Ban	5.2	NPR 903M PV lost premium	High	2
72-Hour Free Outage	Schedule 3	NPR 30M/yr; NPR 282M PV	Medium	3
Disputed Bill Unilateral Deduction	13	Liquidity risk – no ceiling	Medium	3
Termination Compensation Gap	20.3	Debt + equity recoupment uncertain	High	2
Performance Guarantee Asymmetry	38.15	NPR 50M at risk; no off-taker equiv.	Medium	3
Black Start Compensation Exemption	7.2	Unpredictable litigation trigger	Medium	3
Test Generation – Zero Revenue	5.3	NPR 75–150M at commissioning	Low–Medium	3
Hydrology Revision Asymmetry	35.18	Chronic penalty if flow below design	Medium	3
TL Loss Absorption	11.6	NPR 5.2M/yr; NPR 49M PV	Low	4
MOU vs PPA Conflict	MOU Cl.15 / 4.4	Basis for renegotiation claim	Medium	1
Rental/Shutdown Charges	MOU Cl.13–14	NPR 1.1M/yr – principle issue	Low	4
Force Majeure Design Flood Trigger	15	Near-certain over 30-year life	Medium	3

Cumulative Revenue Erosion – Conservative Base Case

EFFECTIVE ANNUAL REVENUE UNDER OPERATIONAL CONDITIONS (Year 1) Normal Annual Revenue at Full Contract:                   NPR 2,466,877,192   Operational deductions from PPA provisions (annual):   Reserve Margin (10%, 5 wet months):               −  NPR    87,000,000   Excess Energy Discount (5% wet season, 50% rate): −  NPR    35,000,000   72-Hour Free Outage (average year):               −  NPR    30,000,000   Transmission Line Loss:                           −  NPR     5,200,000   Rental Charges (MOU):                             −  NPR     1,100,000   Sub-total operational deductions:                 −  NPR   158,300,000   Effective Revenue (average operational year):              NPR 2,308,577,192   Additional – P90 Hydrology (25% dry season shortfall):   30% Dry Season Rule Penalty:                      −  NPR   307,000,000   Effective Revenue in P90 Year:                          NPR 2,001,577,192 Revenue Reduction from Theoretical Maximum:                      −18.9%   → Up to 18.9% revenue reduction driven by contractual design,   not genuine hydrological underperformance.

SECTION IV  RENEGOTIATION POSITIONS – CONSOLIDATED PRIORITY AGENDA

The following table consolidates all recommended contractual amendments, structured as a negotiation agenda. Priority 1 issues must be resolved for the PPA to meet standard bankability criteria. Priorities 2–4 represent commercially important improvements that strengthen the project’s long-term viability.

Priority 1 – Must-Resolve for Bankability

1. Deemed COD Clause (Clause 4.4 + gap): If plant achieves Test Generation but COD cannot be declared solely due to off-taker grid unavailability, COD is deemed to occur 15 days after Test Generation completion. Full take-or-pay obligations commence from Deemed COD.
2. Clause 4.4 RCOD Penalty Reform: Replace 5% formula with a minimum guaranteed monthly payment covering scheduled monthly debt service (agreed at Financial Closure). Deemed Generation at 100% of Contract Energy from Deemed COD.
3. Article 4.4 and Deemed COD Post-RCOD Protection: Where COD cannot be achieved after RCOD solely due to off-taker grid unavailability, the RCOD must be deemed automatically extended day-for-day. The Article 12.1 escalation schedule must be similarly extended, ensuring no escalation is lost due to an off-taker-caused delay. Article 12.4’s optional pre-RCOD arrangement must be explicitly clarified so it cannot be invoked as a basis to deny Deemed COD protection once the RCOD has passed. MOU Clause 15’s financial protection promise must be redeemed substantively in the PPA body.
4. Article 10.3 Dry Season Rule Reform: Move to 3-year rolling average threshold. Limit penalty to dry season tariff reduction only (not wet season recalculation). Insert DHM-certified drought Force Majeure carve-out.

Priority 2 – Strongly Recommended

• Article 12.1 Tariff Escalation Penalty: Limit to developer-caused delays only. Replace escalation-stripping with capped daily cash penalty. Protect all escalations against Force Majeure and off-taker-caused delays.
• Article 10.2 Reverse Penalty Removal: Replace cash penalty mechanism with proportionate revenue reduction only. No positive outgoing cash flow from developer to off-taker for operational underperformance.
• Schedule 3 Override Conditions: Delete both the 72-hour free window and the 100% monthly nullification clause.
• Article 5.2 Third-Party Sales: Insert Right of First Refusal: off-taker retains priority; approval deemed granted for any energy the off-taker declines, discounts, or withholds.
• Articles 38.15 / 20 Security and Termination: Require reciprocal off-taker bank guarantee (12 months projected revenue). Define post-COD termination compensation as debt book value + equity IRR + costs, payable in 90 days.

Priority 3 – Important Commercial Improvements

1. Article 10.1 Reserve Margin: Convert to paid Capacity Reservation Fee at minimum 50% of applicable tariff.
2. Article 12.2 Excess Energy: Tiered secondary energy tariff at 80%/70% of applicable tariff. Eliminate off-taker’s right to refuse payment.
3. Article 13 Billing: Escrow for disputed amounts within 10 days; interest at commercial rate + 3%; unilateral deduction limited to metering errors only.
4. Article 7.2 Black Start: Remove compensation exemption. Separate Technical Services Agreement for emergency grid services.
5. Article 15 Force Majeure Flood: Redefine trigger as 1-in-200-year exceedance event, not design flood level.
6. Article 36 Audit Rights: Establish mutual audit rights including LDC dispatch records and grid availability logs.

Priority 4 – Operational Improvements

1. Article 9.5 Availability Declaration: 48-hour final declaration as compensation reference. 30-day horizon indicative only.
2. Article 11.6 Metering Point: Move to generation bus. Off-taker absorbs transmission losses.
3. Article 35.18 Hydrology Review: Mandatory 5-year review, symmetric both ways, adjusting all dependent thresholds.
4. Article 5.3 Test Generation: 50% tariff payment during test period.
5. MOU Clauses 13–14 Rental Charges: Eliminate charges on developer-funded infrastructure.

APPENDIX – References

Standard / Source	Relevant Principle
IFC Model PPA	Deemed COD + Deemed Generation mandatory for bankability
World Bank Renewable Energy Procurement Guide (2019)	Absence of Deemed COD = bankability-preventing clause
ADB Energy Policy	Secondary energy tariff minimum 70% of primary tariff
IFC Performance Standards 3	Bidirectional resource efficiency; operational penalty limits
EBRD Power Sector Guidelines	Symmetric termination compensation; prompt payment
Nepal–India Power Trade Agreement (2014)	Cross-border sale framework applicable to third-party sales
Nepal Electricity Grid Code, 2080	Grid reliability and forced outage standards for compensation
Model Project Development Agreement	Model PDA