Rising Costs’ Impact on Renewable Power Generation


Rising Costs’ Impact on Renewable Power Generation

By Brad Handler and Mason Shandy

June 27, 2023

The inflationary pressures that have gripped the global economy over the last 18 months, along with central banks’ efforts to lessen them, are weighing on the economics of building new power generation. Despite recent evidence of some moderation in these inflationary pressures, it is reasonable to expect that they will persist for some time.

These higher costs disproportionately impact development of variable renewable energy (VRE), such as wind and solar, and in emerging market (EM) economies. Particularly now that natural gas prices have fallen back to pre-covid levels, the impact in EMs is a significant erosion of the cost advantage that solar and wind power had achieved vis-à-vis fossil fuel plants over the last decade.


The inflationary impact manifests in both higher construction and borrowing costs. In construction, there are indications that the average capital expenditure (capex) for a wind turbine may be up as much as 38% from mid-2021, while the capex for solar panel installations are up ~8% (and natural gas plant capex is up ~10-11%). And as incentive policies, like the Inflation Reduction Act in the U.S., spurs more demand for VRE, it risks raising their costs further over the medium term until global materials availability and manufacturing capacity can expand.

As for borrowing costs, EM government finances have been stressed by additional spending to help their countries navigate Covid-19. Spreads between the yields on EM bonds and U.S. Treasuries, which is a measure of how investors calibrate the risk of borrowing in EMs, have expanded dramatically from pre-Covid 19 levels. See Exhibit 1. This is the most pronounced in Africa, where average spreads rose to over 9 percentage points from ~5 in 2019. Including the increased rate on U.S. Treasuries, it suggests long term interest rates in Africa on average have risen over 6 percentage points from 2019 to 13+%.

Exhibit 1: Yield Spreads Between Emerging Market Bonds and U.S. Treasuries

Source: Reuters, via Refinitiv Datastream


To illustrate the impact of these inflationary pressures as well as to compare the power costs across plant types, a levelized cost of energy (LCOE) analysis is useful. In this analysis, a LCOE is calculated by “back-solving” for the unit revenue required for an equity investment in each plant type to earn a 12% internal rate of return (IRR).

To focus on just three plant types for the purposes of this discussion, in the base (pre-inflation) case, the LCOE for onshore solar and wind plants is ~$25 per megawatt hour (MWh) while it is $34/MWh for a combined cycle natural gas plant (CCGP)[1]. See Exhibit 2. (Note, the CCGP LCOE is not directly comparable to the VRE plants because the VRE’s LCOEs do not include costs to address VRE’s intermittency[2]. However, the LCOEs do support current conventional wisdom that VRE-based electricity costs have fallen below fossil fuel-based costs in recent years.)

Further analysis can then demonstrate the sensitivity to changes in various inputs. For example, with a 4 percentage point increase in borrowing cost, the LCOE rises the most for the solar plant (+$5.21/MWh, 20.9%), followed by the onshore wind plant (+$3.66/MWh, 14.2%) and the CCGP (+$1.42/MWh, 4.1%). In a separate sensitivity case, a 10% increase in capex, yields LCOE increases of $2.14/MWh (8.6%) for solar, $2.06/MWh (8.0%) for onshore wind, and $0.83/MWh (2.4%) for CCGP.

Putting these two sensitivities together yields a $7.91/MWH (31.7%) increase in solar generation cost, followed by a $6.12/MWh (23.8%) increase in wind and a $2.38/MWH (7.0%) increase in natural gas. See Exhibit 2.

Exhibit 2: Base Case and Borrowing Cost/Capex Sensitivity LCOEs by Plant Type












Source: Lazard Asset Management, Payne Institute

This disproportionate impact on VREs in the above sensitivities stems from the fact that far more of their cost structure is tied to the upfront capex (i.e., building the plant), and thus also associated borrowing costs to fund that capex, vs. ongoing expenses. To wit:

  • Fuel costs. Fuel costs are 62% of total assumed annual costs for CCGPs (including financing costs) vs. 0% for onshore wind and solar. This makes CCGPs less sensitive to changes in borrowing cost (as well as capex).
  • Operating & Maintenance costs. CCGP’s O&M costs are 51% of LCOE vs. 4% for solar and 14% for onshore wind. Like fuel cost, this O&M cost makes CCGPs relatively less sensitive to higher borrowing costs and capex.
  • Capital intensity. The Lazard’s solar plant’s capex per annual electricity generation is highest for solar ($.27/KWh), followed by onshore wind ($0.21/KWh) and CCGP ($0.08/MWh). Thus, higher borrowing and plant costs affect the cost of a larger proportion of the cost structure for solar and, to modestly less extent, wind.
  • Asset longevity. The Lazard analysis assumes that solar plants last 30 years while it assumes onshore wind and CCGPs last 20 years. This longer life dampens the return impact of the higher financing cost and acts to partially offset solar’s higher capital intensity.

It is worth noting that the relative advantages for CCGPs of these capex and borrowing cost trends has been partially offset by the historic run-up in natural gas prices. See Exhibit 3. Global gas prices have fallen back to near pre-Covid levels, but the recent extreme volatility arguably should raise expectations for long-run natural gas costs (hedging future gas prices is likely to be more expensive, e.g.). For perspective, a $0.25/MMBtu long-term increase in gas cost drives up the LCOE of a CCGP by $1.52/MWh (+4.5%).

Exhibit 3: Platt’s Japan-Korea Marker (JKM) Futures Price Trend, April 2018 – Present












Source: Investing.com, S&P Global Platts

The risks that higher cost for VRE plants presents is clear. It likely slows development, as it is politically less palatable to add to power grids since the higher required power costs place a higher burden on consumers or on already strained government or state-owned utilities’ finances (if electricity tariffs are subsidized). From a climate perspective, even a temporary slowing in renewable energy construction to replace fossil fuel plant generation is problematic given the aggressive transition pace required to hit climate mitigation targets. Developed economies’ governments and development institutions can act to lessen this cost impact — for example by deploying risk mitigation mechanisms at various levels (government debt forgiveness, greater use of project-specific political/counterparty risk guarantees, etc.) to help lower borrowing costs. But realistically, the energy transition simply has gotten that much more challenging as a result.


[1] Lazard Asset Management’s annual LCOE report provides the assumptions behind each plant type’s LCOE. Lazard has established a position in this area as it has performed this LCOE analysis for 16 years.

[2] For additional considerations (and limitations) of LCOE analysis, the memo “LCOE and Its Limitations” is a useful explainer.


Brad Handler
Payne Institute Program Manager, Sustainable Finance Lab, and Researcher

Brad Handler is a researcher and heads the Payne Institute’s Sustainable Finance Lab. He is also the Principal and Founder of Energy Transition Research LLC. He has recently had articles published in the Financial Times, Washington Post, Nasdaq.com, Petroleum Economist, Transition Economist, WorldOil, POWER Magazine, The Conversation and The Hill. Brad is a former Wall Street Equity Research Analyst with 20 years’ experience covering the Oilfield Services & Drilling (OFS) sector at firms including Jefferies and Credit Suisse. He has an M.B.A from the Kellogg School of Management at Northwestern University and a B.A. in Economics from Johns Hopkins University.

Mason Shandy
BS Computer Science, Colorado School of Mines

Mason Shandy is an undergraduate at the Colorado School of Mines majoring in Computer Science with a focus in Business.


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