By: Albert Neenyi Ayirebi-Acquah Ghana’s energy sector has been assessed by the IMF as posing the greatest fiscal risk to the economy given the significant debt buildup and the impact of supply disruptions to growth and revenue projections for the budget. This is not new. Ghana’s energy sector has an item on our economic to-do list since 2012 and been caught up in many heated political debates since 2014. The debate persists following the NPP’s departure on January 7, after eight years in charge of the sector. This article examines the policy alternatives proposed by the Minority, who urge the new government to refrain from implementing the D-levy – intended to enhance liquidity for electricity supply – and instead continue with the renegotiation of Power Purchase Agreements (PPAs) that they previously initiated among other measures. 1.    What has been the Minority’s track record? During their tenure, the Minority announced several successful PPA renegotiations with savings to the budget which are summarised in the table (Fig. 1) below. With these successful renegotiations, and their announced savings, one wonders which specific contracts remain to be renegotiated which the Minority expects the current government to complete and why these are not being mentioned. 2. Energy subsidies have continued to rise despite past government claims of PPA savings. Second, below is a summary of the cost of subsidies to the budget between 2022 and 2029. One wonders why the announced savings by the then NPP government are not reflecting in the costs of subsidy to the budget, especially the doubling of subsidies in 2023, the year in which the parliamentary committee on energy announced significant savings on excess capacity and renegotiation of PPAs to Take and Pay. For example, in 2021, in a press briefing by the former Energy Minister, Dr. Mathew Opoku-Prempeh, he claimed savings of $1.4 billion per annum following renegotiated PPA contracts. Based on this, what accounts for the quadrupling of energy sector subsidies in 2023 compared to 2022 and which stay significant until 2028 when they begin to reduce? Where is the impact of these savings? 3. What alternative proposals have been presented by the Minority, according to these sources? Based on the above, the Minority NPP have proposed the following:

1. Renegotiating Power Purchase Agreements
2. Making ECG more operationally efficient
3. Financing the cost of power through the PURC tariff
4. Increasing the contribution of Renewable Energy in our generation mix

I proceed to interrogate these in the face of the urgent need to keep the lights on to safeguard the economy and keep our efforts to make our debts sustainable on track. 4. Renegotiating Power Purchase Agreements from Take or Pay to Take and Pay A key distinction between Take or Pay and Take and Pay agreements involves which party assumes the risk associated with electricity demand. Under a Take or Pay structure, the offtaker—such as the Electricity Company of Ghana (ECG)—is responsible for forecasting electricity demand, enabling an Independent Power Producer (IPP) to secure financing for constructing a power plant. In contrast, under a Take and Pay arrangement, the IPP bears the demand forecasting risk. The type of Power Purchase Agreement (PPA) selected is influenced by the creditworthiness of the offtaker. This decision represents a trade-off between the off taker’s financial reliability and the dependability of electricity demand projections. When the offtaker is considered creditworthy, IPPs are more likely to accept the demand risk; conversely, if the offtaker has lower creditworthiness, IPPs may be reluctant to do so. The process is therefore determined not by unilateral decisions from the ECG or government, but by the level of risk that IPP financiers, primarily lenders, are prepared to support, and the bankability of the PPA contract. 5.  ECG’s Creditworthiness and Operational Efficiency The Minority has suggested ECG’s operational turnaround as an alternative to the d-levy, but it is this same Minority that failed to successfully implement Ghana’s first attempt at ECG privatisation in 2019. How come this was never resolved until they left office? According to the Energy Sector Recovery Program 2 report, additional costs of $811 million was incurred due to distribution losses, a direct result of PDS’s failure. Fortunately, attempts are being made to get back on track in terms of privatising (some key aspects) of ECG’s operations to reduce distribution losses from 32% to something significantly lower over time. However, this will take some time to bear fruit. In the meantime, how does the NPP Minority propose we do to keep the lights on? 6. Funding the Cost of Fuel Fuel represents the single largest expense in Ghana’s power value chain. As in many oil-and-gas producing countries, a robust gas-to-power strategy is essential to capture the full economic benefit of domestic resources. This rationale underpinned the previous NDC administration’s development of the Atuabo Gas Plant—projected to save Ghana approximately $300 million annually in fuel costs—and plans for a second facility. Regrettably, when the NPP Minority assumed office, it did not pursue a follow-on gas processing project, leaving the sector increasingly exposed to gas supply disruptions. Consequently, Ghana has had to resort to purchasing light crude oil to bridge intermittent shortfalls and keep the lights on, placing additional pressure on the national budget. While I support the government’s interim measure of levying fuel taxes to finance liquid-fuel purchases for our power plants, I concur with those who argue that, over the medium to long term, fuel costs should be fully internalized through the PURC’s tariff-setting mechanism rather than through ad-hoc levies. My expectation is that, once gas supply reliability is restored and a clear repayment plan for outstanding energy-sector debts is in place, government will shift fuel-price risk back to the generators. At that point, both capacity and fuel costs can be transparently and sustainably recovered within the bulk-generation tariff via the PURC tariff adjustment process. 7.  Funding the sector’s fuel needs through the PURC tariff The Minority has argued that excess capacity and fuel costs should be incorporated into electricity tariffs—an approach that promotes transparency under normal circumstances. Yet the high cost of power, especially for industry, remains a major burden: the Q1 2025 AGI Business Sentiment Survey ranks it as the second-largest operational challenge, ahead of taxes, high inflation, and cedi depreciation. Implementing the D-levy against this backdrop would exclude a critical economic stakeholder and risk undermining our recovery by further raising manufacturing costs. In contrast, leveraging today’s lower fuel prices to fund liquid-fuel purchases is a less disruptive, more targeted interim measure.   8.  Finally, Increasing Renewable Energy in our Generation Mix Increasing the contribution of renewable energy in our generation mix will greatly ease the pressure to increase tariffs—particularly those intended to cover fuel costs for gas or light crude oil generation—because renewables eliminate the need for ongoing fuel purchases. However, any additional renewables beyond the volumes projected in the Integrated Power System Master Plan (IPSMP) will require displacement of existing capacity, meaning the true cost includes not only the renewables themselves but also the capacity value of the displaced plant. Moreover, significant transmission upgrades will be needed to accommodate higher shares of variable renewables—a process that cannot occur overnight—while the timing of our peak demand profile means that solar generation will only be fully effective when paired with adequate storage solutions. Finally, the same challenges confronting IPPs—ECG’s operational inefficiencies, liquidity constraints, and weak balance sheets— will also affect renewable energy producers if left unaddressed. Thus, although renewables are a vital lever for reducing power costs to both consumers and the budget, they will deliver the greatest impact in the medium term, once the sector’s structural issues have been sustainably resolved. Concluding Thoughts Although the Minority’s emphasis on Take-or-Pay PPA renegotiations speaks to valid concerns about contract discipline, their own record casts doubt on how quickly and comprehensively such savings can materialize. Past announcements failed to curb the surge in subsidies—in 2023 alone, energy sector transfers quadrupled— indicating that renegotiation without parallel operational reforms and balance-sheet strengthening at ECG will fall short. In the near term, the new administration should prioritize transparent fuel-cost pass-through mechanisms and fast-track additional gas-to-power infrastructure—building on the Atuabo precedent—to stabilize liquidity and protect industrial competitiveness. Concurrently, targeted measures to reduce distribution losses and shore up ECG’s creditworthiness will set the stage for more bankable PPA structures, but these will only bear fruit over the medium term. Looking further ahead, scaling renewables remains indispensable to break Ghana’s dependence on volatile fuel markets. However, any additions beyond IPSMP projections must account for the capacity value of displaced plants, the need for transmission upgrades, and Solar’s storage requirements. A phased renewables roadmap—sequenced after shoring up ECG’s balance sheet and demand forecasting capabilities—will ensure that solar, wind, and hydro can reliably replace fuel-based generation and deliver sustainable, lower-cost power. By sequencing policy measures—immediate liquidity support through fuel pricing, medium-term operational and PPA optimization, and strategic renewable deployment—the new government can both keep the lights on today and chart a credible path toward a more resilient, fiscally sustainable energy sector.   Source: Albert Neenyi Ayirebi-Acquah, FCCA The author writes on energy policy, macroeconomics, and public finance