Deals include concessions by both the government and independent power producers (IPPs), but the process needs to be transparent and mutually palatable.
In a bid to save the country’s foreign exchange and conserve scarce economic resources, Pakistan recently terminated the power purchase agreements (PPAs) of five independent power producers (IPPs), claiming savings worth Rs411 billion.
The move comes amid increasing pressure from the International Monetary Fund (IMF) to enact cost-side reforms — expense cuts to fix the country’s budget — as part of the country’s $3 billion Stand-by Arrangement (SBA). Consequently, the government has undertaken extensive power sector reforms including suspending gas supply to captive power plants, fast-tracking the Competitive Trading Bilateral Contract Markets (CTBCM), and renegotiating contracts with IPPs. These steps aim to curb the growth of circular debt in the power sector and reduce the burden of capacity payments on the government and consumers.
After months of speculation, five IPPs had their PPAs terminated prematurely in exchange for a lump sum compensation for foregone capacity payments and receivables owed by the government. It is expected that 18 other IPPs will similarly have their PPAs converted from a take-or-pay to a take-and-pay basis. Negotiations are already underway and are expected to conclude in a few weeks, although, if reports are to be believed, around a dozen of these IPPs may have already signed revised deals. Furthermore, contracts with eight other bagasse-based IPPs have also been amended. Together ,these measures could deliver a relief of Rs5 per KWh to electricity tariffs, according to the federal minister for energy Sardar Awais Ahmad Khan Leghari.
Take-or-pay clauses, common in PPAs worldwide, guarantee payment to developers even if the buyer underutilises the product. These clauses protect project developers from off-take risks and ensure steady cash flow for debt repayment. However, such provisions have become problematic for developing economies across Asia and Africa, where dollar-indexed returns and a weak currency have led to ballooning capacity payments (escalating costs for reserving power generation capacity, even if it’s not used) and burgeoning power sector debt.
Pakistan’s burden of capacity payments grew to a staggering Rs2.1 trillion in the fiscal year (FY) 2024, with a 33 per cent projected increase for FY2025. Since capacity payments constitute 65pc of the national average power purchase price, an increase directly impacts retail electricity tariffs — prices consumers pay for the electricity they use.
High electricity tariffs, coupled with an increasing adoption of distributed/rooftop solar photovoltaic (PV) technology across the country are leading to reduced industrial output and shrinking industrial and residential consumption from the grid.
The burden of capacity payments is expected to grow further unless the government succeeds in renegotiating contracts with IPPs.
Haircuts and discounted deals
Contract reviews and renegotiations require all parties to compromise. The Institute for Energy Economics and Financial Analysis (IEEFA) has analysed the five IPPs with terminated contracts and found that two publicly listed companies may have waived some receivables while taking the government’s offered settlement.
Lalpir Power Plant, a 362MW furnace oil-based plant located in Muzaffargarh, had net receivables (the money the power plant is owed by others) worth Rs14.85 billion and short-term liabilities (the money the power plant needs to pay within a short period) worth Rs6.55bn at the time of termination. According to JS Bank data, the power plant would receive a cash settlement of Rs12.8bn, effectively taking a haircut (a reduction in the amount the power plant receives) of Rs7bn.
HubCo’s 1292MW furnace oil-based power plant, Pakistan’s first and largest IPP, was offered Rs36.5bn in compensation, almost RsR20bn less than the total valuation, as at the time of contract termination, its net receivables and debt liabilities Rs56bn.
2. Rousch Power, Atlas Power, and Saba Power are not publicly listed companies, so financial information could not be obtained for these companies. Source: JS Bank; Nepra State of the Industry Report 2023; Author Analysis.
For the 18 IPPs being considered for conversion to a take-and-pay contract, the government has proposed reducing capacity payments to 70-75pc of the annual average fixed power generation costs over the last five years.
Renegotiation details remain unclear, including whether returns would remain dollar-indexed or how the revised tariffs would be determined. A take-and-pay contract usually stipulates fixed offtake or dispatch. If the buyer (the government in this case) is unable to take the minimum contracted quantity in each period, it would breach the contract and be liable to pay for the seller’s incurred damages.
To address this risk, the government proposes expediting the establishment of CTBCM reforms, allowing power plants to sell power directly to clients through private markets.
Recurring historical patterns
The IPPs and their investors have criticised the allegedly unfair deals and coercive tactics used for contract termination. The German sponsors of Roush Power Plant, facing an imminent transfer to the Government of Pakistan, expressed concern about the pressure tactics used to force the deal and highlighted that constant renegotiation over the years had hurt plant profitability.
When the first IPP policy was introduced in 1994, Pakistan had a power supply deficit and needed quick solutions to meet its growing demands. Attractive PPA terms such as guaranteed returns (up to 25pc) for 20 years, US dollar indexation (payments tied to the US dollar to avoid local currency fluctuations), exemption from various taxes and customs duties, pass-through fuel costs, an appealing tariff ceiling (a maximum price set for electricity to ensure profits), and government guarantees were offered, which allowed an influx of almost 3.5 gigawatts (GW) of capacity and FDI worth $5bn.
The policy’s initial success quickly turned into a significant challenge for the government as it resulted in over-capacity. The government accused the IPPs of corruption and technical manipulation, and by 1998, two-thirds of the contracted capacity had been issued notices of intent to terminate. After three years of discussions, most contracts were eventually forcibly renegotiated. The country’s weak fiscal position, limited exports, shrinking energy demand, and mishandling of the renegotiation process led to new investment in the power sector shrinking for almost 10 years.
According to a World Bank document from 2005:
“Perceptions by the project sponsors of excessive coercion, harassment and heavy-handed legal and other actions initiated by the Government to renegotiate tariffs or cancel contracts contributed to Pakistan’s fall from grace in the eyes of the international private sector community.”
The current situation resembles that of 20 years ago. The same renegotiation tactics are being used with IPPs. The country is slowly recovering from a two-year foreign exchange crisis. The grid is in surplus as consumer demand rapidly falls due to high energy prices. Exports are stagnant, and investor confidence is low due to widespread macroeconomic instability.
Shared responsibility for economic instability
IPPs in Pakistan have legally binding contracts with the government that permit inflated returns due to dollar indexation and take-or-pay provisions. Therefore, an increase in the generation cost due to currency depreciation cannot be labelled as malpractice.
Simultaneously, while the government erred in allowing these provisions, PPA terms have been overly generous, resulting in lucrative returns and high profit margins over the long term. However, these incentives have not been gradually phased out. Instead, since 1994, power generation policies have offered the same incentives.
The rapidly evolving economics of the power sector and fuel price volatility in international markets have led to an uncontrolled increase in electricity tariffs. Renegotiation efforts recently expanded to eight bagasse-based IPPs, which had been allowed to index locally produced bagasse prices to South African imported coal with adjustments for exchange rate fluctuations. This resulted in a 110pc increase in the fuel cost component (FCC) for bagasse-based power from Rs5.98 per kilowatt hour (kWh) to Rs12.48 per kWh.
Therefore, renegotiation is reasonable, provided all parties reach a mutually acceptable agreement. For instance, Ghana has also been undergoing power sector reforms as it pays up to $500 million in excess capacity payments annually. The government began renegotiating in 2019 and successfully mediated with five IPPs to restructure debt and convert to a take-and-pay basis. The government also secured a haircut of $400m by restructuring the financial arrears owed to these plants through overdue capacity payments.
Potential benefits for the government and IPPs
Many plants scheduled for premature PPA termination and conversion to take-and-pay contracts have had low capacity factors over the years. Some were in the middle of their PPAs or close to retirement, while others were undergoing a PPA extension and had paid off all long-term debts. Furthermore, these plants operate on furnace oil or imported liquified natural gas, resulting in a high generation cost and low dispatch.
One of the five furnace oil-based power plants whose PPAs were prematurely terminated had a capacity factor below 2pc for three of the five years between 2018-2023 while receiving between Rs20-30bn annually in capacity payments. The plant also had unpaid dues by the Central Power Purchase Agency (CPPA-G) worth Rs65bn as of March 2024, 86pc of which were overdue. Thus, for plants with just 2-5 years left on their PPAs, this could be an opportunity to get quick compensation for unpaid dues and a possible re-investment of funds into new ventures.
Note: A negative remaining life indicates an extension in the power purchase agreement. Source: JS Bank; NEPRA State of the Industry Report 2023; Author Analysis.
Many of these IPPs are owned by local conglomerates with diverse business portfolios. These could serve as secondary markets for power off-take — the purchase of electricity from a power producer — once the government fully implements its wheeling regulations and operationalises bilateral markets. The government has even offered this as a concession to the IPPs in its renegotiation package.
For instance, the Hub Power Plant, owned by the Hub Power Company, is establishing electric vehicle (EV) and lithium-ion battery manufacturing facilities in collaboration with Chinese EV giant BYD.
There could be a post-retirement scenario where the compensation package offered by the government is used to repurpose existing plant sites into off-grid renewable energy and storage assets to power other industries nearby.
The same could apply to the 18 IPPs facing conversion to take-and-pay contracts. Figure 2 above highlights the remaining contract life and plant capacity factor for each — a measure of actual plant dispatch over the plant’s theoretical annual output (a low capacity factor would mean underutilisation of the plant). Power plants with low-capacity factors and 2-5 years remaining on their PPAs offer little benefit to the grid because of their low output. Therefore, immediate retirement could be an option unless they are critical for grid support.
Power plants with moderate to low capacity factors and a 10-15 year remaining contracted lifetime would have also earned reasonable investment returns. They could agree to take-and-pay agreements or early retirement. However, since many of these plants provide ancillary services such as frequency control and reactive power compensation, the latter would require investment in related devices and upgrading the grid infrastructure.
Any arrangement would be an achievement for the government in terms of saving foreign exchange and reducing energy costs. However, take-and-pay contracts usually stipulate minimum guaranteed dispatch, as in Ghana. Therefore, demand forecasting should be accurate.
The government also loses the ability to demand liquidated damages — pre-agreed penalties a producer pays if they fail to meet contract terms — for unavailable capacity and would be liable to pay the producer if it is unable to meet the guaranteed dispatch condition. Consequently, a robust mechanism for auditing plant performance and availability should be developed to ensure that NEPRA and CPPA-G can check the performance of all thermal IPPs and verify invoices.
Another option could be introducing PPA price reviews to ensure electricity prices reflect evolving market trends. Additionally, compensation clauses could be included that establish an obligation on the buyer to pay any differential in price if a higher cost is agreed upon or for the seller to offset any overpaid dues by the buyer if a lower price is determined.
Transparent renegotiations key to energy reform
Renegotiating contractual agreements is not unusual in the private sector if precipitated by changing economic conditions, such as the significant macroeconomic shocks experienced by Pakistan. However, negotiations need to be commercial and transparent to ensure optimal outcomes.
The IPPs under review contribute a smaller share to the overall capacity payments than government-owned re-gasified liquefied natural gas plants or the China-Pakistan Economic Corridor (CPEC) plants under government-to-government (G2G) agreements. Expanding the scope of renegotiations to these plants could provide an additional economic advantage for the country.
Pakistan’s continued emphasis on generation addition without consideration of the principle of least-cost expansion (adding new power generation at the lowest possible cost to meet demand efficiently), led to the entrenchment of unsustainable incentives, which are challenging to modify. Contract renegotiations and early terminations can deliver monetary benefits for the government in the short term.
However, the inflexible PPA model should be revised in the long term, adopting a staggered approach for phasing out incentives. While competitive procurement may provide the ultimate solution, transitioning to a fully liberalised market will take years. Until that happens, PPAs will likely govern a significant share of the power market.
Robust auditing processes should be established, and future IPP solicitation should be through competitive bidding aligned with the country’s socio-economic development and budgetary constraints to prevent recurrences of the current situation.
