KARACHI: A power plant on the Pakistan Stock Exchange does not make money the way most businesses do. It does not find its own customers, set its own prices, or worry much whether you switch on a fan tonight. Instead, most large generators sell their entire output to a single state buyer under a long contract that pays them in two distinct ways — one for being available, one for actually generating. Those two payments, and the chronic national difficulty in paying bills on time, explain almost everything about listed power stocks: their steady-looking profits, their sudden dividend droughts, their periodic renegotiations with the government, and their bursts of enthusiasm whenever the state clears old dues.
The single-buyer system and the power purchase agreement
Pakistan’s grid was unbundled on paper into generation, transmission and distribution, but in practice most independent power producers, or IPPs, sell electricity to a central purchasing agency on behalf of the distribution companies, which sell onward to households, farms, shops and factories. The contract governing a plant is its power purchase agreement, signed before construction, usually for a term measured in decades. Alongside it sit an implementation agreement with the state and a fuel supply agreement. Together these documents allocate every major risk: who bears fuel prices, exchange-rate moves, demand shortfalls and political change.
The listed sector spans several generations of policy. Older plants were contracted under the power policies of the 1990s and 2000s, many burning furnace oil or gas. Later waves added coal plants, including large projects built under China-Pakistan Economic Corridor arrangements, plus LNG-based, hydro, wind and solar producers. Some listed companies, such as the Hub Power Company, grew from a single large plant into diversified energy groups; others are essentially one plant with a stock-market listing. Our company explainer on how Hubco makes money follows one such evolution in detail, while this guide stays with the sector machinery that all of them share.
Investors should picture the contract, not the turbines, as the asset. Two physically identical plants under different contracts can have entirely different profits, because tariffs, indexations, fuel arrangements and remaining contract life differ. When a plant’s original term approaches expiry or renewal, its economics can change fundamentally — a fact that periodically reprices older IPPs as expiry dates move from abstract to near.
Capacity payments: being paid to exist
The first revenue stream is the capacity payment. The buyer pays the plant a largely fixed amount for making its dependable capacity available to the grid, whether or not a single unit is dispatched. This payment is designed to cover the plant’s fixed costs: debt service on the loans that built it, insurance, staffing, maintenance, and a return on the equity investors put in, which in classic Pakistani IPP contracts was set in dollar-linked terms at the time of signing.
Capacity payments are why IPP profits look unusually stable compared with other industries. Demand can fall, the plant can sit idle for weeks because cheaper plants are dispatched first, and the capacity revenue still accrues, provided the plant was genuinely available and passes availability tests. Availability is the key discipline: a plant that cannot produce when called forfeits payments and can face penalties, which is why maintenance scheduling and reliability dominate operational management.
They are also why capacity payments are politically contentious. Pakistan contracted more capacity in the 2010s than demand growth ultimately required, partly because forecasts assumed faster economic growth. Households then face tariffs carrying the fixed costs of idle plants — the famous “capacity trap” of public debate. Successive governments have renegotiated IPP terms, converting some dollar-linked returns to rupees, trimming returns or extending tenors in exchange for settlements. For investors, the lesson is structural: the contract is strong, but it exists inside politics, and its terms have been reopened before and can be again.
Energy payments and the merit order
The second stream is the energy payment: a per-unit charge paid only when the plant actually generates and delivers electricity. It primarily passes through variable costs, above all fuel — which is why you will hear energy payments described as largely a pass-through with limited margin. The plant buys gas, LNG, coal or oil, converts it to electricity at its contracted efficiency (its heat rate), and the energy charge reimburses that fuel cost subject to the contract’s efficiency benchmarks. Run inefficiently, and the plant can lose on the spread; run well, and it keeps operations near neutral while the real return sits in the capacity stream.
Which plants run, and how much, is decided by the merit order: the system operator dispatches the cheapest available generation first. Hydro and nuclear typically sit low in variable cost, then efficient gas and coal plants, with old furnace-oil plants near the top, dispatched only when demand or shortages require. This explains a pattern beginners find confusing — a plant’s generation can collapse while its profit barely moves, because dispatch affects mostly the pass-through energy stream while capacity payments continue. Generation volumes still matter for fuel suppliers upstream, including the explorers in our guide to exploration and production stocks, whose gas sales depend on plants actually burning.
An illustrative example helps. Imagine a plant entitled to Rs 1,000 million a year in capacity payments if fully available, and energy payments that exactly reimburse fuel. Whether it generates at 20 percent or 80 percent of capacity, its core profit changes little; what changes is fuel throughput and wear. Now imagine the buyer pays six months late. Profit on paper is unchanged, but cash is trapped, the company borrows to pay its own suppliers and dividends wait. That second scenario is not hypothetical colour — it is the sector’s recurring reality, with a name of its own.
Circular debt: the loop that swallows the cash
Circular debt arises because the money collected from electricity consumers — after theft, non-payment and below-cost regulated tariffs — has repeatedly fallen short of the money owed across the chain. Distribution companies under-recover; the central buyer delays paying generators; generators delay paying fuel suppliers; fuel suppliers, including state-linked gas and oil companies, accumulate receivables; and the state periodically injects loans or settlements that shrink the stock of arrears before it builds again. Total arrears have at times reached into the trillions of rupees across the chain; readers should check SBP, finance ministry and regulator publications for the current stock, which moves with each settlement and season.
For listed generators, circular debt shows up as ballooning trade receivables, finance costs on working-capital borrowing, and dividends that depend less on profit than on collections. When governments arrange a settlement — historically through bank borrowing by holding companies, tariff adjustments, or budget support, sometimes alongside IMF programme commitments — IPP shares often react strongly, because expected cash finally moves. Learning to read a power company therefore means reading its receivables ageing and cash conversion before its earnings per share, exactly as with its upstream cousins.
The long-term fixes debated by every energy minister are structural: reducing distribution losses and theft, aligning tariffs with costs while protecting poor consumers through targeted subsidies, privatising or reforming distribution companies, and moving towards a competitive market where generators contract with multiple buyers. Each reform shifts risk among consumers, the state and shareholders, which is why reform announcements matter to this sector more than to almost any other on the exchange.
New directions: coal, renewables and diversification
The listed sector is not frozen in its 1990s shape. Large coal plants using Thar coal changed the fuel mix and linked generation economics to a domestic resource; hydro projects offer long lives and no fuel cost but hydrological and construction risk; wind and solar plants sell under their own tariff structures with no fuel pass-through and different availability logic. Some generators have diversified into mining, electric vehicles, energy services or overseas projects — moves that blur the pure IPP model and require investors to value a portfolio of unlike assets rather than one contract.
Fuel transition also cuts the other way. Old oil-fired plants face shrinking dispatch, environmental pressure and expiry risk. Gas-fired plants depend on Pakistan’s depleting domestic gas and imported LNG pricing. When reading a generator’s annual report, map each plant’s fuel, remaining contract life, and share of profit; then ask what replaces that profit when the contract ends — a question as important for this sector as the crushing season is for sugar stocks.
How to read a power stock, honestly
A sensible checklist: contract and tariff structure per plant; availability and dispatch levels; receivables and days outstanding; debt currency and repayment schedule; dividend history against collections, not just profits; exposure to renegotiation; and diversification plans. Steady earnings per share can conceal deteriorating cash, while a dull year with a big settlement can transform the balance sheet. This is educational content, not financial advice; the sector rewards readers who follow the cash and the contract, and it punishes those who follow only the headline yield. The broader context sits in our energy sector overview and the learning library.
Tariffs, indexation and the fine print that moves profits
Between the two headline payments sits a layer of contractual fine print that determines how a plant’s economics age. Tariffs are typically built from components — a capacity price and an energy price, each with sub-components for fuel, operations, insurance and return — and many components are indexed: to the rupee-dollar exchange rate, to local or foreign inflation, or to interest-rate benchmarks for the debt portion. Indexation is why two plants with identical operations can report different profit growth in a depreciation year, and why the conversion of some contracts from dollar-indexed to rupee terms, in the renegotiations of recent years, materially changed those plants’ futures at a stroke.
The regulator, NEPRA, determines and reviews tariffs under the generation licences, and its determinations, true-up decisions and indexation notices are primary documents for anyone following a listed generator seriously — they are public, technical and far more informative than market rumour. True-ups deserve a plain explanation: because some costs are estimated in advance and corrected later against actuals, a single determination can release or claw back several periods of revenue at once, producing the sudden profit jumps or drops that baffle headline readers. When a power company’s quarterly result looks inexplicable, the answer is usually sitting in a NEPRA determination or a tariff note in the accounts.
Fuel arrangements complete the picture. Plants hold fuel supply agreements with gas utilities, oil marketers or coal suppliers — in the Thar case, with an affiliated mine — and fuel shortages translate directly into availability and dispatch outcomes the plant may or may not be compensated for, depending on contract wording tested in real disputes over the years. Reading a generator, in short, means reading a stack of contracts summarised in its annual report’s first twenty pages. Investors unwilling to do that work are, knowingly or not, simply trusting that the stack is benign.
What privatisation and a competitive market would change
Reform proposals return to this sector with each government, and investors should understand their mechanics rather than cheer or fear them in the abstract. Privatising distribution companies attacks the collection losses at circular debt’s source; if it works, generators get paid faster and receivables shrink, at the price of a harder-nosed counterparty. A competitive trading market, in which generators contract with multiple buyers instead of one central purchaser, would reward cheap, reliable plants and strand expensive ones whose contracts were written for the single-buyer world — which is why transition arrangements for existing contracts dominate the design debate.
Either path reprices the listed sector plant by plant rather than uniformly: newer, efficient, well-located assets gain strategic value; older oil-fired plants near contract expiry face their endgame sooner. The direction of policy travel is visible in regulator and ministry publications, and following it is not optional homework for this sector — it is the difference between owning a contract and owning a power plant, two assets that look identical until the rules change around them.
Key takeaway: IPPs earn capacity payments for availability and energy payments that mostly pass fuel costs through — profitability is contractual, but dividends depend on whether circular debt lets the cash arrive.
