Latest news with #LCOE
Business Recorder
10-07-2025
- Business
- Business Recorder
IGCEP and illusion of long-term planning
In a recent session of Parliament, the Minister for Power, while responding to a question about the energy sector planning, quoted an old Chinese saying: 'You cannot discuss the ocean with a well frog.' It was meant to dismiss the criticism by opposition; suggesting that those raising concerns do not see the bigger picture. But sometimes, the frog inside the well genuinely believes that the well is the ocean, or he might have jumped into a swimming pool considering it as an ocean. And that is exactly our problem. We think we are planning, seeing the full energy landscape, making data-driven decisions. But the truth is, we are still stuck inside the same old planning mindset. And the well we have mistaken for the ocean is built around one comfortable but misleading idea: the Levelized Cost of Electricity (LCOE). The IGCEP 2025-35 is an approval away to be submitted to NEPRA and as per publicly available information, it is coming with the same old methodology i.e., LCOE. Every time a new IGCEP is announced, the hope returns that maybe this time it will be different. That it will be based on better data, sharper modelling, and a more realistic understanding of demand and generation needs. But the same core mistake keeps repeating itself. In this article we shall discuss why this IGCEP is also likely to misguide investment decisions, and what are simplistic workable solutions which can make this document an accurate and reliable planning tool. LCOE looks neat on paper. One number that tells you the cost of electricity from any project, no matter the technology. It feels scientific. But that is the problem, it only feels that way. In reality, LCOE ignores the most critical parts of our power system. It does not care when electricity is produced, whether it is during peak summer hours or chilly winter nights. It does not care where the plant is located, whether near a load centre or hundreds of kilometres away, where expensive transmission lines will be needed. And it does not care how the plant contributes, whether it is flexible, dispatchable, seasonal, or completely dependent on weather. It treats all kilowatt-hours as equal, even when the grid does not. On top of that, it hides the real impact of financing terms. A slight change in interest rate can make a project appear cheap or expensive overnight. So, when we say LCOE is misleading, it is not an overstatement, it simply was not designed to answer the kinds of questions we need to ask today. Yet it remains at the centre of our planning documents, giving a false sense of clarity where thoughtful analysis is needed. One of the biggest flaws in using LCOE is that it ignores the timing of generation. In a country with growing reliance on solar generation, where demand can swing sharply between hours, days, and seasons, timing is everything. A project that generates reliably during peak summer afternoons has a much higher value than one that delivers most of its energy at night or during the winter. But LCOE treats them the same. It averages everything out without asking when that electricity will be needed. A simple fix exists: instead of counting all units equally, we should assign weights to generation based on monthly or even hourly demand profiles. A unit delivered during peak summer should count more than one in low-demand winter months. This is not complex modelling; it is just a more honest way to value electricity. Another critical blind spot is location. LCOE does not include the cost of transmitting electricity from the project site to where the demand is. A project with a low LCOE built in a remote valley may end up being far more expensive once transmission lines, grid losses, and system upgrades are added in. But none of this shows up in the LCOE figure. As a result, such projects look attractive in planning documents, until transmission costs and losses make those savings vanish. The solution is again straightforward: calculate the delivered cost of electricity, not just the generation cost. If NEPRA can assess the full tariff of each project, including transmission and net delivered energy, during planning, the IGCEP will automatically become more accurate and aligned with system needs. Then there is the question of function. Not all power plants serve the same role. Some are base-load, designed to run around the clock. Others are peaking plants, called in only during the highest demand hours. Some are flexible, adjusting output based on real-time grid conditions. Comparing all of them on one flat metric like LCOE is fundamentally wrong. A base-load plant cannot be expected to perform the job of a peaking plant, and vice versa. What is needed is clear segmentation. Projects should be grouped according to their operational role, base-load, load-following, or peaking, and only compared within those categories. This simple adjustment would prevent apples-to-oranges comparisons and allow planners to select the most suitable technology for each type of grid requirement. LCOE also fails to account for flexibility and system value. A project that can ramp up or down quickly, respond to frequency changes, or provide backup support during grid stress has a quite different value than a project that just injects fixed power into the system. But LCOE does not see that. It assumes all generation is equal, regardless of system services provided. To fix this, we need to introduce system-adjusted evaluation tools. These do not need to be overly technical, simply basic metrics that reflect a project's ability to support grid stability. Even assigning flexibility scores or adding a simple adjustment factor in tariff calculations would go a long way in capturing this missing piece. There is another issue that often goes unnoticed. It is the quality and validity of the data being used to calculate LCOE. For the IGCEP 2025–35, project sponsors were asked to submit their cost and generation details back in 2023. That data, already outdated by now, is still being used to decide which projects are considered 'affordable.' In some cases, especially for public sector projects, updated numbers from 2025 have quietly been accepted. Meanwhile, all other projects, mostly from the private sector, are still being evaluated based on the original data submitted back in 2023. They were not allowed to revisit their assumptions or submit revised costs. Instead, an arbitrary inflation index was applied to update their figures, which does not truly reflect market conditions or financing realities. This selective flexibility creates a clear bias in favour of a few while sidelining others. The fair and transparent approach would be for NEPRA to first determine tariffs based on verified and current data, across the board. Only then should projects be shortlisted as candidates for inclusion in IGCEP. That is the only way to ensure equal treatment and build confidence in the planning process. Lastly, LCOE is overly sensitive to financing assumptions, especially the discount rate. A slight change in interest rate can dramatically shift the final number, making one project look cheaper than another purely because of how it is financed, not how it performs. In Pakistan, where financing terms vary widely and risks are high, this creates a distorted picture. The better approach is to standardise tariff calculations using real, project-specific financing structures. If a project expects concessional financing, reflect that. If it carries risk premiums, add them in. Avoid hiding those differences behind one average discount rate. Only then can we get a real sense of what each project will cost the country. We do not need to follow the world blindly. We have our own grid realities, demand patterns, financial limitations, and seasonal challenges. The idea that only foreign consultants or global models can guide our planning has already caused enough damage. It is time we start listening to our own experts, people who have worked within this system, who understand the practical issues, and who can offer grounded solutions. The continued reliance on outdated metrics like LCOE is not just a technical oversight, it is a habit. Even the U.S. Energy Information Administration, in its 2025 Annual Energy Outlook, clearly states that using LCOE individually is not suitable for system planning. If they are acknowledging the limitations, why are we still using it as the backbone of our national planning? We have the talent, the institutions, and the data to do better. The only thing missing is the willingness to move beyond shortcuts and start planning like a country that actually wants to fix its energy future. It is time to acknowledge that LCOE has served its purpose but is no longer fit to lead our investment planning. The cost of repeating the same mistake is too high. If we want a power system that is affordable, reliable, and aligned with actual national needs, then our planning methodology must evolve. And that begins by asking more from the models we use, and more from those who design them. Copyright Business Recorder, 2025
Daily Maverick
17-06-2025
- Business
- Daily Maverick
Modern generation planning — understanding the Levelised Cost of Energy
The Levelised Cost of Energy is the industry's go-to benchmark for comparing the cost-effectiveness of different electricity generation technologies. The Levelised Cost of Energy (LCOE) represents the average cost to build and operate a power-generating facility over its lifetime, divided by the total energy it produces. Expressed in $/MWh or ZAR/MWh, it offers a standardised basis for comparing solar farms, wind turbines, battery storage facilities, gas-to-power plants and nuclear reactors. LCOE includes capital costs, financing, operations and maintenance, fuel (where applicable), and end-of-life costs. Crucially, it excludes market price fluctuations and environmental externalities. LCOE = Total Lifetime Costs ÷ Total Lifetime Energy Production Taking into account the time value of money through a discounted cash flow analysis, this can be expressed more correctly as: Where: I t = Investment expenditures in year t (typically upfront capital cost in year 0, and reinvestments over time) O t = Operation and maintenance costs in year t F t = Fuel costs in year t (zero for renewables like solar and wind) E t = Electricity generated in year t (usually in MWh) r = Discount rate (reflecting the cost of capital) N = System lifetime (typically 20 to 40 years, depending on technology) This formula allows stakeholders to compare technologies on an equal footing – whether they rely on coal, sunlight, wind, coal, gas or steam. Why LCOE matters LCOE is central to energy investment, planning and procurement. Project developers use it to assess economic viability. Utilities and regulators use it to shape long-term power system plans. Governments refer to it when crafting renewable energy auctions and climate policy. And investors rely on it to evaluate return-on-investment potential. In an age of surging energy demand, carbon targets and technology disruption, LCOE plays a defining role in shaping what gets built, where and why. Insights from Lazard's 2025 LCOE+ report The June 2025 LCOE+ report by Lazard – now in its 18th edition – confirms that renewables remain the lowest-cost sources of new electricity in the United States and elsewhere, even without subsidies. In the US, unsubsidised costs for utility-scale solar PV range from $37 to $44/MWh, while onshore wind spans $37 to $66/MWh. In contrast, gas combined-cycle plants come in at $48 to $109/MWh, and coal is significantly higher at $109 to $157/MWh. Nuclear power remains the costliest, ranging from $141 to $251/MWh. When current US tax incentives – like the Investment Tax Credit (ITC) and Production Tax Credit (PTC) – are factored in, these costs reduce significantly. Utility-scale solar with full incentives can fall to just $15 to $24/MWh. However, under the Trump administration, the US tax incentive regime is experiencing some uncertainty and change. This price competitiveness, coupled with speed to deploy, explains why renewables continue to dominate new-build generation – even as supply chain volatility and inflation have slightly pushed prices upward. LCOE in integrated energy planning In Integrated Resource Planning (IRP), utilities project decades into the future to identify the least-cost mix of generation. Here, LCOE provides a financial lens for choosing between technologies – balancing cost, emissions and reliability, while also considering the time value of money. For example, planners might weigh the LCOE of a solar + battery hybrid system against that of a new gas peaker. This helps determine not only cost-optimal investments but also implications for transmission needs, grid stability and carbon goals. LCOE also supports policy decisions, such as structuring auctions, determining feed-in tariffs or prioritising transmission expansion. LCOE has its limits Despite its popularity, LCOE has well-known blind spots – especially as energy systems evolve. Most critically, LCOE does not account for unplanned intermittency of coal and nuclear, or the variability of renewable energy. It assumes all kilowatt-hours are equal, regardless of when they are generated. This obscures the grid value – or lack thereof – of resources like solar and wind that don't generate on demand. It also ignores the cost of integrating renewables: firming capacity, curtailment, congestion and storage. Nor does it capture locational constraints, grid upgrade needs or emissions externalities. LCOE also overlooks market value. Two resources with identical LCOEs might deliver vastly different profits or emissions benefits depending on when and where their electricity is delivered into the grid. In Lazard's own words, LCOE 'is not a forecasting tool' and does not reflect 'the complexities of our evolving grid and resource needs.' Lazard's broader view: LCOE+ Recognising these challenges, Lazard has expanded its 2025 report beyond traditional LCOE to include system-level costs and sensitivities. One key addition is the Cost of Firming Intermittency – a measure of the extra cost to ensure reliability when using solar, wind or hybrid systems. For instance, in California (CAISO), firming a standalone solar plant with a four-hour battery raises the total system cost from around $43/MWh to over $70/MWh. Lazard also quantifies the impact of fuel and carbon pricing. A $40 to $60 per ton carbon price adds up to $60/MWh to coal and gas costs, further improving the competitiveness of zero-carbon technologies. The report goes further to examine how LCOE is affected by capital cost assumptions. At higher interest rates, LCOEs for capital-intensive renewables rise more than for fuel-intensive gas plants – highlighting the financial exposure of clean energy projects. What about energy storage? Lazard's Levelised Cost of Storage (LCOS), now in its 10th edition, shows declining costs across the board. A 100 MW, 4-hour battery system has an unsubsidised LCOS of $132/MWh, dropping to $83/MWh with full tax incentives. Smaller commercial and residential systems cost more, but are also falling due to oversupply of battery cells and improvements in energy density. The role of storage in balancing renewables, providing grid services and avoiding curtailment makes it a growing complement to LCOE-based planning. LCOS adds a critical dimension to understanding long-term grid economics. So, how is LCOE used? One can think of LCOE as the foundation, but not the roof, nor the totality of energy analysis. In markets with modest renewable penetration, LCOE still serves as a strong guidepost. But as systems mature and require greater flexibility, LCOE must be integrated with broader metrics – firming costs, ELCC (Effective Load Carrying Capability), locational value, emissions intensity, and market signals. Lazard's 2025 analysis reaffirms that a diverse portfolio – renewables, storage, flexible gas, with the possibility of future emerging technologies like small modular reactors and geothermal – offers the best hedge against volatility and aligns with both affordability and resilience goals. Conclusions The energy sector is navigating a major transformation. In this environment, LCOE remains an essential compass – but it cannot navigate the journey alone. Used wisely, LCOE helps identify least-cost technologies. But to truly guide the energy transition, it must be paired with real-world operational insights and system-wide thinking. The key is not to discard LCOE, but to expand the toolkit. Lazard's 2025 report does exactly that, providing a more integrated, actionable view of what it takes to build the power system of the future. DM Chris Yelland is managing director of EE Business Intelligence
