On Inflation and Sustainable Energy

Inflation, inflation, inflation. Multiple high profile renewable energy projects have been cancelled recently largely due to high inflation rates. Examples include Ørsted’s 2.25 GW of off-shore wind in Ocean Wind 1 and 2 off the coast of New Jersey [1].

News and journal articles are documenting the effects of rising interest rates on capital intense and operationally light projects, such as renewable and sustainable energy projects [2,3]. The Federal Reserve has increased their interest rates from near-zero in 2020 to upwards of 5% in late 2023 to battle inflation rates that peaked near 8% [4]. All of this is increasing the cost of borrowing capital.

The Levelized Cost of Electricity (LCOE) is essentially the cost of delivering electricity over an energy project’s lifetime. The LCOEs for solar and wind projects have fallen precipitously over the past decade. Despite this, the LCOE for projects completed since 2021 are on average 67% higher for solar and 30% higher for wind than projects in 2021 [5]. In addition to high interest rates, supply chain challenges certainly contribute to these increased costs.

My job in the hydrogen economy involves developing conceptual and pre-feasibility studies of H2 projects for clients. Considering our desire to use wind and solar energy to power H2 production, what directly affects wind and solar, indirectly affects us. Additionally, many hydrogen technologies are also capital intense and operationally light (beyond electricity costs).

How energy costs scale with interest rates

It has been daunting to witness first hand how rising interest rates, and thus a rising cost of capital, are affecting project economics. Imagine a project who’s costs are based 100% on CAPEX (capital expenses); a change in the cost of capital from 5% to 10% nearly doubles the cost of the project, thus doubling the LCOE resulting from the project (figure below).

In contrast, a hypothetical project that has zero CAPEX, where 100% of costs are OPEX (operational expenses), would experience a zero percent increase in the LCOE as the cost of capital increases. This is assuming future operational costs are discounted at the same rate as the value of future electricity.

The below examples show that as the cost of capital increases, the CAPEX contribution to LCOE increases. Whereas, the OPEX contribution to LCOE remains stable. The different panels show the CAPEX and OPEX contributions to LCOE for different hypothetical projects. The values are normalized to projects with a 0% cost of capital.

While these figures are abstract, we can compare different real-world technologies to these curves. Based on NREL’s Annual Technology Baseline[6], the LCOE breakdown for utility-scale solar PV, if the cost of capital was 0%, would be approximately 70% CAPEX, 30% OPEX.

Utility-scale solar projects will approximately follow the scaling associated with the 70% CAPEX curve above (middle panel) that experiences an approximately 45% increases LCOE as the cost of capital increases from 5% to 10%.

In contrast, natural gas power plants have much higher operational costs than solar. If we take NREL’s latest values [7] and a cost of gas of $3/MMBtu, the LCOE breakdown for a combined-cycle natural gas plant, if the cost of capital was 0%, would be 20% CAPEX, 80% OPEX.

Thus, a natural gas plant will approximately follow the scaling associated with the 20% CAPEX curve above (right panel). This curve experiences close to a 15% increases LCOE as the cost of capital increases from 5% to 10%, a much smaller increase than the 45% increase for a solar project.

During these years with high interest rates, the disproportionate effect of high interest rates and cost of capital on capital intensive and operationally light renewable energy projects versus fossil fuel projects is an extra hurdle to overcome in realizing a sustainable energy future. While this is currently a challenge, as interest rates recede, renewable energy projects will disproportionately benefit. A return to the era of near-zero interest rates would be a boon for renewable energy and decarbonizing our energy systems.


The LCOE calculations used here are similar to those used in Schmidt et al. 2019 [8] and use a cash-flow perspective which does not account for depreciation. Values are taken from the NREL ATB when possible [6, 7].

  • Utility-scale PV 2023 Moderate scenario: CAPEX 1,331 $/kW, Fixed O&M $21 $/kW-yr, assume 30 year lifetime
  • Natural Gas Combined Cycle (F-Frame) 2023 Moderate scenario: CAPEX 1,237 $/kW, Fixed O&M $31 $/kW-yr, Variable O&M 1.94 $/MWh, assume 95% capacity factor, $3/MMBtu fuel, 50% efficient (LHV), 25 year lifetime


On the way Towards Sustainability and Resiliency

Two weeks ago, from March 22-25, FZJ (Forschungszentrum Jülich) hosted the National Academy of Engineering and the Alexander von Humboldt Foundation, for a symposium titled “On the way Towards Sustainability and Resiliency”. This was the 20th German-American Frontiers of Engineering (GAFOE) symposium.

GAFOE 2023 brought together four disciplines to share ideas, discuss overlaps, and build collaborations. The topic areas were: supply chain resiliency, sustainable production and circulation economy, neuromorphic computing (an approach to computing inspired by the brain), and the hydrogen economy.

Hydrogen for Grid Support

I was privileged to be invited as a US speaker and representative to discuss “Hydrogen for Grid Support.” I focused on two interconnected use cases for grid-tied hydrogen production. The first, using hydrogen for long-duration energy storage. The second, treating hydrogen production as a flexible electricity load on the grid which can adjust in real-time to support the needs of the grid.

Presenting at GAFOE 2023

The talk was intended to introduce a broad, yet technical, audience to possible uses of hydrogen in future low-carbon economies. I drew on research from colleagues studying the energy transition to illustrate the synergies between grid-tied hydrogen production and power systems with substantial wind and solar generation.

This talk led right into two of my past papers written while at Carnegie Science with Ken Caldeira and team: “Role of Long-Duration Energy Storage in Variable Renewable Electricity Systems” led by Jackie Dowling and “Opportunities for flexible electricity loads such as hydrogen production from curtailed generation” led by myself. A copy of my slides are here.

From coal towards sustainability

The location of the symposium set the tone. FZJ was founded in 1956 initially as a center for nuclear physics and energy research. Now, Germany is again re-imagining its energy future and looking towards sustainability and more resilient energy supplies.

Two nuclear reactors and a rainbow during our FZJ campus tour.

However, a push towards sustainability will be challenging. FZJ is tucked into the forests in the middle of Germany coal county just a few minute bike ride away from immense open-pit coal mines. In these pits Bucket Wheel Excavators, some of the world’s largest movable machines, rip away at the Earth to uncover the valuable coal.

Open-pit coal mine a few minute bike ride from FZJ. Note wind turbines and coal power plant on the horizon, left side and massive coal seam in the pit.

Yet, the region is trying to break free of its coal dependence. Wind turbines speckle the countryside and FZJ was proud to announce to us that they have grown their hydrogen research team for a handful two years ago to over 350 researchers today. This is amazing progress, but is set in contrast to the 20,000 coal industry jobs which will be disappearing in the coming years.

I hope that the German government can work with this region and it constituents to help usher in a successful and just transition towards a low-carbon economy.

Many thanks to Emily Grubert and Lars Lauterbach who co-chaired The Hydrogen Economy session at GAFOE 2023, Thomas Kurfess and Olivier Guillon who chaired the symposium. And, extra thanks to Bethany Frew who masterfully presented an introduction to energy system modeling and hydrogen production that graciously provided helpful context for my talk.

Joining the Hydrogen Economy

Image from: https://dge.carnegiescience.edu/news/2021/7/green-hydrogen-production-curtailed-wind-and-solar-power

I’m excited to announce my jump from academia to industry as I join LIFTE H2, a new company pushing the bounds of the emerging hydrogeneconomy and enabling companies to meet their decarbonization goals.

I am joining the Systems Analysis team as a Senior System Modeling Engineer where I look forward to collaborating with Marta Dueñas Díez and Co.  I will be using the skills and knowledge I gained working with Ken Caldeira and his great team of postdocs and colleagues to model, design, and understand the tradeoffs of technology choices in upcoming #hydrogen projects. My modeling will also help motivate and determine research pathways for key technologies.

I have spent my time with Ken Caldeira studying the dynamics and variability of #netzerocarbon energy systems focusing on questions such as “How much #hydrogen could potentially be made from otherwise curtailed wind and solar power in future energy systems?” [1].

I used this academic background considering the interplay between wind and solar generation and hydrogen production as a springboard for recent work with excellent folks within the Stanford Climate Ventures community.

Under the mentorship of David T. Danielson and David B. Rogers, Joseff Kolman and I were co-leads for a team that set out to model and understand business opportunities for flexible #hydrogen production, that is hydrogen production that could ramping down when economical to reduce electricity costs and reduce the burden on strained electricity systems.

We wanted to know where in the US hydrogen production could be most cost competitive against incumbent technologies and what use cases were the most promising in the near future. The skills I learned and network I grew from this crash course in business and entrepreneurship have already been invaluable in landing this job a LIFTE H2.

Thank you to everyone who has helped me get here. Among other things, I hope to be a #hydrogen resource to you in the future!

Abbreviated thank you list:
The academic side: Steve Davis, Nate Lewis, David Farnham, Jacqueline A. Dowling, Enrico Antonini, Lei Duan, Michael Dioha, PhD, Candise Henry, Edgar Virgüez, Ph.D.

The entrepreneurship side: Joel Moxley, Amy Zhao, Phuthi Tsatsi, Sishir Mohammed, Justin Bracci, Aksh Garg, Melissa Zhang, Thilo M. Braun, Karen Baert, Gunther Glenk

The particle physics side that launched me toward programming, data analysis, and modeling: Wesley Smith and Sridhara Dasu and the rest of the University of Wisconsin-Madison CMS group

And many others!

[1] https://lnkd.in/gic825zf

INFORMS Annual Conference

The annual INFORMS conference is a destination for scientists, researchers, and industry experts focused on operations research & analytics. The conference was recently held in Anaheim, CA, October 24-27, 2021.

I had the privilege of chairing a session titled “Macro Energy Systems: Energy and Climate.” Researchers shared presentations from the cutting edge of energy system modeling. Their work explored possible trajectories towards a low-carbon energy transition and the policies and technologies that could enable such transition.

  • Lei Duan of Carnegie Science presented an analysis of the potential for nuclear power combined with thermal energy storage to contribute to a low-carbon future.
  • Kenji Shiraishi of UC Berkeley shared an analysis of the possible role of hydrogen and policy choices in shaping Japan’s long-term energy future.
  • Charalampos Avraam of New York University presented a detailed study of the North American natural gas market and how renewable energy policy may affect it.
  • Tom Brown of the Technical University of Berlin presented a method of incorporating public acceptance of different technologies into a least-cost energy system model.
  • My presentation built on the work I shared at the MIT A+B 2021 Symposium and studied the improvements modelers can find when incorporating more years of weather data into their models with large fractions of wind and solar power.

The INFORMS community is increasing interest in energy system modeling from a low-carbon transition perspective. This can only lead to positive outcomes for energy systems modelers as more researchers with backgrounds in optimization and operations research become interested in our field.

I look forward to this conference and the connections I will make next year and hope to actually attend in-person.

Reducing Electricity System Variability with Solar Power

Solar power is often thought to increase the variability of electricity systems. In a recent paper (open access), Ken Caldeira and I show that adding solar to electricity systems, where solar power correlates with electricity demand, can actually reduce the variability in peak residual electricity load.

Residual Load

Residual load is electricity load (demand) minus generation from variable resources, such as wind and solar. Residual load represents the load that must be supplied by more controllable resources: firm generation (gas, nuclear, etc.), energy storage, and demand response.

Depiction of residual load (dashed line) and the peak residual load value

For a system operator, peak residual load indicates a lower bound on the quantity of firm generation, stored energy, and demand response that must be available in their system to supply all electricity loads.

As wind and solar are added to our electricity systems, system planners will likely rely on estimates of future peak residual load and how the peak values vary from year to year as crucial planning metrics.


We estimate the peak residual load and how much it varies from year to year as wind and solar generation are added to four example electricity systems. From this, we find that the variability in the peak values changes as more wind and solar are added.

The variability (spread) in the peak residual load values from year to year is depicted for systems as wind and solar generation increase. In PJM, for example, progressing vertically in the figure indicates adding solar generation. As solar generation is added, the variability decreases as indicated by the darker colors.

Interestingly, for the three modeled systems that experience their peak electricity usage in the summer months (ERCOT in Texas, PJM in the mid-Atlantic, and NYISO in New York state), adding solar statistically reduces the spread in the peak values from year to year.

These three summer peaking systems show a strong correlation between peak electricity usage and the hottest days. The hottest days are indicated by the largest “daily degree day” values in the below figure.

Thus, by adding generation that correlates with the most extreme peak load hours, electricity systems can become more predictable even if that generation is from a variable renewable resource like solar.

Reducing the spread in the peak values from year to year could possibly make system planning simpler by having more predictable peak residual load values.


We used historical electricity load data from the four studied systems: ERCOT, PJM, NYISO, and France.

Ten years of historical electricity load (demand) for the studied regions.

We used historical weather data to derive plausible wind and solar generation profiles concurrent with the load data.

We incrementally increased the contributions of wind and solar generation from zero to generation equivalent in quantity to providing 100% of annual load. For each residual load profile, we assessed the spread in the peak values from year to year.

To calculate the spread in the peak values, called the inter-annual variability (IAV), we take the mean of the 10 peak residual load values from each year of data and calculated the standard deviation of these 10 mean values.

Other links

Twitter discussions:

Emerging opportunities for hydrogen production as a flexible electricity load

Wind and solar generation are powering more and more of our electricity systems. Along with their zero-carbon electricity comes their variability and uncontrollable power output.

Utilities are increasingly tackling the variable nature of wind and solar power by building energy storage to shift available power from when it can be produced by nature to when it is most needed by the grid.

There is growing interest and possibilities in tackling the variability issue not by shifting available power to meet electricity demands, but by shifting electricity demands to meet available power.

One potential candidate flexible load candidate is producing hydrogen gas by splitting water using electrolysis. Producing low-cost hydrogen with minimal carbon emissions is currently viewed as a cornerstone of an energy transition away from carbon emitting sources.

Our new paper

We recently published a paper in Advances in Applied Energy considering producing hydrogen as a flexible electricity load (demand) in future low-carbon electricity systems.

We asked how the operations of future electricity systems would change if we introduced a small, flexible hydrogen producing load. Is there essentially “free” electricity available to a business who can choose to operate only when the sun is shining and wind is blowing? How much “free” electricity will there be?

Study results

We find that in systems with substantial wind and solar power, zero cost electricity is available sometimes and low-cost power is available almost always. In fact, in modeled systems powered exclusively by wind and solar power, zero-cost, zero-carbon power was available more than 95% of the time.

One enticing thing about flexible loads is when other electricity uses are pushing the grid to its maximum extent and power costs are high, flexible loads can simply throttle back or even turn off.  This would save them considerable money and could save the grid from needing to expand generation capacity, a win-win situation.

However, if we really push the envelope with vast amounts of flexible loads like electric vehicles and by producing hydrogen, the grid’s generation capacity will eventually need to expand. After all, there is only so much zero-cost and low-cost power available in the original electricity system.

Many more interesting results and all the details can be found in the paper.

I am looking forward to continuing this line of work and further exploring the integration of hydrogen production with low-carbon electricity systems and how both can enable a low-carbon energy transition.

Wind and solar resource droughts in California

I am glad to say that a paper led by Katherine Z. Rinaldi, which I helped contribute to, was recently published in Environmental Science and Technology. Like most places, California is susceptible to multi-day low wind or cloudy events. These events, if not properly planned for could have dire consequences for the electricity grid.

The paper studies the frequency and duration of severe weather events, specifically wind and solar resource droughts, and their impact on a 100% wind and solar powered electricity grid. We studied how the frequency and duration of these events changes when wind and solar generation resources are spread over larger or smaller geographic regions.

In short, a more geographically dispersed system has fewer resource droughts and those that happen as shorter. This suggests that integrating electricity systems over larger distances will be increasingly beneficial as the fraction of power supplied by wind and solar increases.

We hope this paper will aid policy makers, utilities, and others whom are building California’s clean energy transition towards a net-zero carbon system.

MIT A+B Symposium

During the last two years, MIT and Harvard have co-hosted the MIT A+B symposium on rapidly decarbonizing our society. These conferences have a unique approach that I really appreciate. The organizers call for presentations on A) mature, cost-effective technologies that are ready to deploy at scale, and B) potentially breakthrough technologies that may enable achieving a near-zero carbon emission society.

Unique conference structure

Splitting the presentations into these two categories or timelines does two things. It supports the urgency of the situation by emphasizing and exploring details of the abundant cost-effective, existing technologies that can be deployed now to make immediate impacts. These are the technologies that businesses can rely upon in the near-term and build into their business plans. They are also the technologies that policymakers should be looking towards to craft achievable near-term climate targets and policy.

The “potentially breakthrough technologies” category engages the research community and pushes the question of what is possible. Many studies have shown that achieving 80% carbon emission reductions is relatively simple. The last 20% of emissions that takes us to carbon neutral is by far the most difficult piece to solve in the carbon neutral puzzle. We need to cast a wide net to explore many possible technologies that could be available in a few decades to meet our final climate targets.

Electricity generation in systems with substantial wind- and solar-power

I submitted an abstract to the 2020 MIT A+B symposium focused on category A, deploying existing, cost-effective technologies. The abstract asked two questions: 1) how much traditional electricity generation capacity is needed to reliably meet society’s electricity demands as wind- and solar-power rapidly scale up? And, 2) how does the required traditional electricity generation capacity change year-to-year? This is an interesting question because the answer varies based on local industry and electricity use patterns and climate. A more detailed discussion of my presentation will follow.

For now, suffice to say, the abstract was accepted. A prerecorded virtual presentations is available online. Lastly, a short paper extending and refining the material in the presentation is now available in the conference proceedings.

I was invited to submit an extended version of the conference paper to the Applied Energy journal. The deadline for submission is Feb 1, 2021. Time to get moving.

Comparing FERC and EIA electricity demand data

The United States government coordinates the collection of hourly electricity demand data from regional entities for use in planning and decision making processes.  The Federal Energy Regulatory Commission (FERC) provides easily accessible data records spanning 2006-2018 for a mix of Balancing Authorities (BAs) and Planning Areas with Form 714.

While the Energy Information Administration (EIA) began their collection of hourly electricity demand data in July of 2015 for all BAs with Form 930. The EIA data are updated in near real-time and bring other benefits such as including hourly generation by resource type: coal, hydropower, natural gas, nuclear, wind, solar, petroleum, and other.

An interesting question for the energy modeling community is, does the 2017 data gathered by FERC align with the 2017 data gathered by EIA?  Can these records be used almost interchangeably?  Additionally, benefits will be realized by stitching together the longer historical FERC data records with the EIA records that contain more details of the current system.

One of our collaborators, Zane Selvans (@ZaneSelvans) of the Catalyst Cooperative (@CatalystCoop), mapped the ~200 FERC respondents to the ~70 EIA BAs and arranged the FERC data into a more usable format.  With this, we compared the hourly demand values for the successfully mapped BAs for 2017.  Details of the comparison methods are at the end of this post.


We compare the ratio of FERC hourly values to EIA hourly values and calculate the ratio of mean, minimum, and maximum values for each region.

California Independent System Operator (CISO)

Midwest Independent System Operator

The two examples here show hourly comparisons for CISO, with most values nearly identical and nearly all within 10%, and MISO, with most values agreeing within 10% and overall agreement based on the ratio of mean values of 1.01.

ISO New England (ISNE)

PJM Interconnection (PJM)

Some regions show a mean value close to 1 yet have non-uniform features in their distributions, such as ISNE (ratio of mean values = 0.99) and PJM (ratio of mean values = 0.98).

Furthermore, other regions have substantial discrepancies in the ratio of their mean values.  A histogram of the ratios of the mean values for each compared BA shows agreement within a few percent for over 30 BAs (a csv file is attached at the bottom showing the ratio of their mean, minimum, and maximum values). Additionally, we compare the minimum and maximum values and see a distribution similar to the mean value comparison.

Ratio of the mean of demand values for each mapped BA (FERC mean value/EIA mean value)

Ratio of the minimum and maximum demand values for each mapped BA


There are a considerable number of Balancing Authorities that have reasonably similar FERC and EIA hourly demand records based on agreement within a few percent of the ratios of mean, minimum, and maximum values.  This indicates that the FERC and EIA records may be approximately interchangeable for these BAs if the exact hourly profile is not a concern (see excel file for list).  The fact that many histograms contain a spread about 1.0 is worth exploring for anyone considering using these profiles as replacements for each other while modeling. Are there biases in which hours are misaligned?

In the future, this could also allow analysts to stitch together the longer FERC records with the more current and detailed EIA records.  The Catalyst Cooperative and Zane are pursuing work along these lines.  We wish them the best of luck!


The FERC data contains records from both Balancing Authorities and Planning Areas, while the EIA records are only for Balancing Authorities.  Therefore, many of the FERC records do not have EIA equivalents.  We only compare records that we think should align.

Both the FERC and EIA data records are imperfect, containing zero values, missing values, and the occasional outlier value.  For the EIA data, we use the EIA records after removing outlier values based on the details in this paper.  For the FERC data, we use the FERC records arranged by Zane with all zero values removed.  Hours are only included in the comparison if the corresponding hourly value in each record was present and was not removed by these two cleaning methods.

  • Summary csv file: comparing the mean, minimum, and maximum values in the FERC 714 and EIA 930 hourly demand data for year 2017 for the matched BAs.
  • FERC to EIA mapping: the mapping of FERC respondents to their EIA codes and acronyms provided by Zane.

More realistic data leads to more realistic models

There are many quirks of being an ex-high energy particle physicist who completed their PhD with the CMS experiment. For one, waking up in the middle of the night for an upset child doesn’t seem too bad compared to the many nights when I was “on-call” and woken up at 3am to help debug data collection issues with our experiment. I would much rather be “on-call” for my son than for a 14,000 tonne inanimate object.

Another quirk is that I am a year into my Postdoc at Carnegie Science and only now am I publishing my first ever first author paper. It is hard, in fact nearly impossible, to get to the front of the 3,000 person author list for the papers published by the CMS experiment. Needless to say, I did not make it to the front while I was part of the CMS team.

Now, I have the pleasure of being the first of only four authors on a paper discussing data cleaning and preparation for use in our energy models. While not the most glorious of papers, we hope this paper and the data we cleaned can be used by the energy modeling community. After all, more realistic data leads to more realistic models.

See this friendly blog post about the paper.