The government’s latest attempt to tame the beast that is circular debt looks, on paper, like a genuine breakthrough: a cheaper pile of money, a clearer payment cascade, and – if all goes to plan – breathing room for the fuel suppliers and power producers that keep the lights on. Yet talk to anyone who has covered this saga over the past decade and a half, and you will hear a familiar refrain. The arithmetic that creates circular debt is still very much intact. The state is rearranging liabilities to buy time, not solving the pricing, collection, and cost‑recovery problem that causes arrears to spiral.
Below, we unpack the transaction now on the table, trace the origins and evolution of circular debt since 2008, and examine why – despite real near‑term relief – this fix will not end the cycle. We also explore how the energy transition at the consumer end, especially the rapid pivot to rooftop solar, may sharpen the challenge by eroding the utility revenue base even as capacity charges remain fixed.
What the new transaction actually does: cheaper money and a cleaner queue
The government has orchestrated a large refinancing of the power sector’s arrears, centred on a Rs1.225 trillion syndicated bank facility priced at KIBOR minus 0.9%. The facility will replace a medley of higher‑cost obligations that have accumulated over years: independent power producers’ (IPPs) penal late‑payment charges – often referenced to 3‑month KIBOR plus 200–450 basis points – and interest on loans parked at Power Holding (Pvt) Ltd (PHPL), historically levied around KIBOR + 2%. By swapping this stack of expensive liabilities for a single, cheaper instrument, the authorities expect to shave roughly 1.5–5% off the implied finance cost on the relevant portion of the debt.
A key design feature is how the refinancing is to be serviced. The plan channels Debt Service Surcharge (DSS) receipts – currently Rs3.23 per kWh under the PHPL surcharge – towards the annual interest and principal payments. Any excess collections against this surcharge are earmarked for accelerated principal retirement over six years. To reduce the risk that the surcharge breaches an administrative cap in a high‑rate environment, the FY26 budget removed the 10% DSS cap, creating headroom for collection targets that gradually decline to zero by FY31 as the loan amortises. A residual Rs~436 billion of circular debt not covered by the new bank facility is intended to be absorbed via the power‑sector subsidy line.
The starting point of the liability clean‑up is an existing power circular debt stock of Rs1.661 trillion. Within that number sit Rs908 billion of payables to power producers, Rs93 billion owed by power generation companies (GENCOs) to fuel suppliers, and Rs660 billion parked in PHPL. The Rs1.225 trillion bank facility is sized to retire all PHPL loans (Rs660 billion) and address Rs565 billion of interest‑bearing arrears to power producers. What remains – ~Rs436 billion – is meant to be financed by allocations under the ~Rs1 trillion power subsidy envelope.
Who benefits first? Cash will move from Central Power Purchasing Authority (CPPA‑G) to RLNG power plants (notably National Power Parks Management Company Ltd (NPPMCL), Quaid-e-Azam Thermal Power (Pvt) Ltd (QATPL) and Nandipur Power), flow through Sui Northern Gas Pipelines (SNGPL), and ultimately reach Pakistan State Oil (PSO) – albeit with some lag. Analysts expect PSO to be the primary beneficiary, with a conservative impact estimate of roughly Rs100 per share, underpinned by expected recoveries on RLNG fuel receivables. PSO will likely be able to clear receivables of ~Rs64–74 billion, equating to ~Rs136–157 per share depending on the accounting cut‑off.
That improvement is already visible: PSO recovered Rs75 billion from SNGPL and Rs14.8 billion from HUBC, used excess liquidity to trim FE‑25 borrowings by Rs89 billion to Rs356 billion as of June 2025, and saw finance costs fall to Rs34 billion in FY25 from Rs52 billion in FY24. The circular debt cash‑through should further improve PSO’s working capital and net finance costs.
It is not just PSO. The government also intends to settle outstanding dues of coal power plants, making HUBC, Lucky Cement (LUCK), Engro (ENGRO), Fauji Fertiliser Company (FFC), and Thal (THALL) clear secondary beneficiaries in the listed space. Stake‑adjusted numbers crunched by analysts suggest HUBC’s overdue receivables via China Power Hub Generation Company (CPHGC) (~Rs53 billion), Thar Energy Ltd (TEL) (~Rs12 billion), and ThalNova Power Thar (Pvt) Ltd (TNPTL) (~Rs11 billion) – about Rs28 per share on a stake‑adjusted basis – as well as Lucky Electric Power Company Limited (LEPCL)’s trade debts (~Rs19 billion, ~Rs13 per share) and Engro Powergen Thar Private Limited (EPTL)’s receivables (~Rs50 billion, ~Rs21 per share). For LUCK and ENGRO, the analysis prudently applies a 20% discount to reflect a potential LPS (late‑payment surcharge) waiver, though clarity is still pending, particularly for China-Pakistan Economic Corridor (CPEC) independent power producers (IPPs). The note flags that disbursements will follow a one‑month assessment, after which the government will have three months to draw and fully utilise the facility – timelines that could, in practice, accelerate.
Finally, look at the FY26 power subsidy lines. A consolidated view of Water and Power Development Authority (WAPDA), Pakistan Electric Power Company (PEPCO), and Karachi Electric Supply Company (KESC, or K-Electric) shows ~Rs1.036 trillion budgeted, including Rs249 billion for inter‑DISCO tariff differential, Rs125 billion for K‑Electric tariff differential, Rs95 billion to IPPs, and a Rs400 billion lump‑sum provision. This is the cushion meant to absorb the residue that the bank loan does not refinance – and to smooth tariff‑differential pressures across utilities and regions.
In financial‑engineering terms, the state is consolidating scattered arrears into a single, cheaper, time‑bound loan serviced by a dedicated surcharge, while using the budget to mop up the leftover. That should lower interest costs and improve liquidity across the sector’s cash‑starved nodes over the next 12–24 months. But the arithmetic that generates arrears remains in place.
Why circular debt happens in the first place: the tariff–cost gap the budget cannot fully fill
Circular debt does not start in bank ledgers; it starts in tariff policy and system performance.
At its core lies a differential between the weighted‑average price at which electricity (and now, increasingly, piped gas and regasified LNG) is sold to end‑users, and the full economic cost of generating, transporting, and delivering that energy. When the notified consumer tariff sits below cost recovery, the government promises to pay the difference via subsidies. That promise is honoured erratically, often in arrears and usually below the cost gap. The result is a cash shortfall that accumulates first at the distribution companies (DISCOs), then CPPA‑G, then at IPPs, fuel suppliers, and eventually banks – forming the now‑familiar chain of receivables and payables that define circular debt.
Three ingredients intensify this gap:
- Technical and commercial losses. High T&D losses, theft, poor metering, and delayed billing reduce the effective revenue collected for every unit generated. Even if tariffs are notionally cost‑reflective, a 1–2 percentage‑point slippage in loss targets can create tens of billions of rupees in annual shortfalls.
- FX and interest‑rate pass‑through. A large share of Pakistan’s generation cost – fuel, O&M, and capacity charges – have historically been indexed to the US dollar and domestic interest rates. And fuel price is still driven in large part by international markets. Depreciation and rate spikes drive the cost curve up faster than notified tariffs adjust, especially when regulator‑approved pass‑throughs lag political realities.
- Take‑or‑pay contracts and
seasonal demand. The post‑2013 build‑out of capacity (coal, RLNG, and other large plants) introduced substantial fixed capacity payments. These do not fall when demand weakens or shifts off‑grid; they are due regardless of actual dispatch in a given month. That creates a rising fixed‑cost floor that must be recovered from a consumer base straining under high tariffs.
On the gas side, a similar pattern is visible. Cross‑subsidies and delayed price adjustments create gaps between procurement costs (especially for RLNG) and tariffs charged to consumer categories. As with power, the state’s promise to budget the difference is often partial and late, pushing state‑owned gas utilities and suppliers into the same receivable spiral that haunts the power chain.
When the sums do not add up, arrears fester. Interest and late‑payment surcharges snowball. Liquidity stress prompts load curtailments and fuel supply interruptions – which, in turn, depress billable sales and collections. The circularity tightens.
How we got here: a brief history of creative fixes, 2008 to now
Circular debt in Pakistan’s power sector is not new. It surged in 2008–09, when oil prices spiked and the state struggled to reconcile subsidised consumer tariffs with escalating generation costs. The response was a series of ad‑hoc cash injections and the creation of Power Holding (Private) Limited (PHPL), a special‑purpose vehicle that could raise debt (TFCs/Sukuk, bank loans) to clear payables rapidly without showing the full fiscal hit upfront. The intent was always the same: park the liability, restore liquidity, and buy time for “structural reforms” that never quite materialised.
In 2013, the incoming government executed the most famous of these clearances, paying down roughly Rs480 billion of accumulated arrears to IPPs and fuel suppliers. Much of that was financed via government borrowing and PHPL instruments. The move delivered immediate relief and briefly reduced load‑shedding, but the underlying mismatch between tariffs, losses and costs reasserted itself. Within a couple of years, arrears rebuilt.
Between 2015 and 2018, as new capacity arrived, capacity payments ballooned. The policy objective – ending load‑shedding – was achieved, but the financing model relied heavily on take‑or‑pay contracts indexed to FX and interest rates, leaving the system more vulnerable to macro shocks. Periodic tariff hikes, surcharge layering, and renewed PHPL borrowing did the heavy lifting of liquidity, while DISCO losses and governance barely budged.
By 2019–21, another round of “circular debt management plans” was in vogue: partial settlements with IPPs, tweaks to payment priorities, and attempts to renegotiate the terms of some contracts. There were moments of progress – improvements in fuel mix, some regulatory pass‑throughs, and targeted subsidy rationalisation – but the impact was insufficient to reverse the underlying dynamics.
Then came 2022–23: a commodity‑price shock, currency depreciation, and a surge in local interest rates. The cost base exploded; tariff adjustments lagged; collections struggled under the weight of inflation; and circular debt swelled again. As liquidity tightened, the late‑payment surcharge (LPS) on IPPs rose, PHPL interest costs climbed, and the arrears chain lengthened – bringing us to today’s refinancing, in which Rs1.225 trillion of cheaper bank debt is being used to retire PHPL loans (Rs660 billion) and restructure arrears to power producers (Rs565 billion), with the residual funded via the subsidy line. The note’s exhibits on stock, financing, and the DSS path are explicit on these flows.
If the architecture sounds familiar, that is because it is. The instruments vary; the amounts get larger; the surcharge labels change; but the underlying logic – refinance, re‑sequence, and hope the runway is long enough for reforms to catch up – has not budged much since 2008.
Why this fix helps – but cannot solve – the problem
There is real value in the current transaction. It lowers funding costs, consolidates obligations into a clearer payment stream, and eases working capital stress for critical counterparties (fuel suppliers like PSO, coal IPPs, and certain RLNG‑based plants). That alone can reduce churn, cut LPS accrual, and stabilise dispatch. The structured use of the DSS at Rs3.23/kWh gives banks comfort that there is a dedicated revenue source for servicing the loan, while the FY26 removal of the 10% cap on the surcharge mutes a key implementation risk. And with ~Rs1.036 trillion of budgeted power subsidies across multiple heads, there is visible fiscal space (on paper) to absorb the remainder of the stock that the loan does not refinance.
But look past the cash‑flow relief and the contradictions come back into view:
• Tariff design remains politically constrained. The consumer price of energy is not set by a pure cost‑of‑service formula. It is mediated by social policy (lifeline slabs, cross‑subsidies), regional considerations, and macro management. As long as the weighted‑average notified tariff sits below the true economic cost, the budget must fill the gap. When fiscal space tightens – as it often does – the gap is only partially filled, and arrears regrow.
• DISCO performance is still the Achilles’ heel. High losses and low recoveries in some service areas obliterate the math of cost recovery. Year after year, circular debt management plans assume aggressive loss‑reduction targets; year after year, only modest gains materialise. Until collections and losses move decisively towards world‑norms – and are locked in through governance changes and enforcement – arrears will continue to seed themselves at the distribution level.
• Fixed capacity payments are inflexible. A growing share of the bill is contracted capacity, not energy. If demand is soft – or shifts to self‑generation – the system still owes the fixed charges. Those charges, indexed to FX and interest rates, climb whenever the rupee weakens or rates rise. A cheaper bank loan cannot offset a structural capacity‑payment overhang.
• Fuel‑mix and FX exposure persist. Imported fuels embed FX risk in the cost base. Unless domestic generation (hydel, local coal with sensible logistics, nuclear, wind, solar with storage) scales in a way that actually reduces the FX‑linked component without inflating capacity payments, the volatility will remain.
• Gas circular debt mirrors power. On the gas side, delayed price decisions, cross‑subsidies, and RLNG pricing misalignments keep recreating budget‑funding gaps. The current transaction mainly clears power‑sector arrears; it does not directly reform gas pricing or ring‑fence RLNG economics for power vs non‑power users.
• Legal and contractual complexities linger. The research note itself flags uncertainty on LPS waivers for CPEC IPPs and a staged disbursement timetable (one‑month assessment, three‑month draw window). If waivers stall – or if payment conditions are not met quickly – the liquidity relief may be slower than forecast.
In short, the deal treats the symptoms – high financing costs and jammed payables – but not the cause: an energy‑pricing regime misaligned with costs, exacerbated by weak distribution economics and an inflexible capacity stack.
Why tomorrow’s problem could be bigger: solar defection meets a costly post‑2013 capacity build‑out
There is a paradox at the heart of Pakistan’s power sector. Consumers – households and businesses – are doing the rational thing in response to high and volatile tariffs: installing solar (and, where affordable, batteries), trimming grid consumption, and smoothing their bills. But the system they are stepping away from is one in which fixed capacity charges have grown sharply since 2013, as a raft of capital‑intensive plants – coal, RLNG, and other large baseload units – came online under take‑or‑pay contracts.
The result is a classic utility “death‑spiral” risk:
- Tariffs rise to recover a large fixed‑cost base (capacity payments, FX‑linked O&M, debt service).
- Customers defect partially (or fully) to rooftop solar, especially for daylight loads.
- The remaining grid sales shrink, forcing higher per‑unit charges on those who stay.
- Higher charges encourage more defection, and the cycle repeats.
Pakistan’s post‑2013 generation expansion was a deliberate policy choice to end load‑shedding. It succeeded in adding capacity and reducing outages, but it also locked in dollar‑indexed capacity payments across several large plants – think RLNG combined‑cycles and imported‑coal units – and some newer units with limited dispatch flexibility. When demand growth falters (recession, energy efficiency, solar adoption) or shifts in shape (midday solar hollowing out the peak sunlight hours), those plants are dispatched less but still paid. That is precisely what makes the fixed cost hard to spread across a shrinking kilowatt‑hour base.
Now layer in the subsidy architecture. Much of the tariff cross‑subsidises lifeline and protected slabs by charging more to higher‑usage households and commercial/industrial users. But these are precisely the categories that move first to solar. Take a large residence or a medium‑sized shop: a 5–15 kW rooftop system can knock out most daylight consumption. For a factory, cheap daytime PV offsets part of the load even if the grid remains essential for nights and process stability. Each defection removes high‑tariff units from the sales mix, eroding the cross‑subsidy that supports lifeline and agricultural tariffs.
The current refinancing does not, and cannot, arrest this dynamic. It reduces the cost of carrying yesterday’s arrears; it does not change the fact that tomorrow’s capacity bill must be shared by fewer grid‑dependent consumers if off‑take keeps sagging. Unless the sector pivots towards tariff structures and market designs that (a) recognise the value of the grid as a network service, not just an energy commodity; (b) charge connection and capacity fairly; and (c) incentivise demand to show up when the system has surplus (e.g., dynamic pricing, flexible industrial loads), circular debt pressures will intensify.
A further complication is net metering. In its simplest form, net metering pays rooftop solar users the retail tariff for energy exported back to the grid. While that can accelerate adoption, it can also over‑reward exports relative to their avoided system cost (which may be low at midday when utility‑scale generation is available), shifting more fixed costs onto non‑solar customers. Many countries have moved towards “net billing” (paying a wholesale‑like rate for exports) or time‑of‑use structures. Pakistan’s policy here will be critical: get it wrong, and the cost‑shift becomes a political flashpoint; get it right, and the grid can integrate distributed solar without detonating its revenue base.
What does this mean for the 2013‑vintage fleet? Expect more attention to flexible dispatch, coal‑to‑local‑coal blending where feasible, improved fuel supply logistics, and, controversially, contract renegotiations that trade shorter tail payments for tariff rationalisation or conversion of some take‑or‑pay obligations into take‑and‑pay with floor. None of this is easy. But without some change in the capacity‑payment geometry, even perfect refinancing will only postpone the next arrears build‑up.
The uncomfortable conclusion
The new circular debt plan is, in a narrow sense, good policy: it cuts financing costs, consolidates liabilities, and unclogs the payment chain. PSO and several IPPs – including HUBC, LUCK, ENGRO, FFC and THALL exposures – should feel immediate relief as cash begins to move and the DSS‑backed amortisation kicks in. If LPS waivers for CPEC IPPs are clarified promptly and disbursements begin quickly after the one‑month assessment, the market will likely price in improved balance‑sheet strength for the obvious beneficiaries. The FY26 subsidy line – about Rs1.036 trillion across key heads – will do the rest of the firefighting that the bank loan does not cover.
But these are palliative measures. The structural disease is unchanged: tariff under‑recovery, DISCO losses, an import‑exposed cost base, and a capacity stack that demands fixed payments whether consumers buy from the grid or not. As solar adoption rises and daytime grid demand softens, the cost recovery challenge will only grow. The risk is that Pakistan finds itself back here in a few years – organising another round of refinancing, layering another surcharge, and assembling another budget provision to keep the system liquid.
Breaking that cycle requires politically hard choices: targeted cash subsidies instead of blunt tariff suppression; loss‑reduction with teeth (including privatisation or long‑term concessions for DISCOs); a credible multi‑year tariff path that stays ahead of costs; market designs that pay fairly for capacity, flexibility and network value; and contractual reforms that balance investor certainty with system sustainability. Those changes take time. The new loan buys some. It is welcome. It is not a cure.
The arithmetic is neat; the intentions are sound. But the name “circular debt” endures for a reason. Unless Pakistan changes the circular economics at the foundation, this is one more round – useful, necessary even – but not the final one.
