A combination of recovering electricity demand and warmer spring weather helped drive fuel prices to multi-year highs, pushing wholesale electricity prices further up. The unusual price growth during spring takes place against a backdrop of tighter summer conditions in California and Texas, even as capacity markets come under bearish pressure in the Eastern Independent System Operator markets of New England, New York, and Pennsylvania, New Jersey, and Maryland (PJM).
Considering the follow-on impacts to electricity markets, carbon markets, and green markets, price expansion may change the valuation dynamics of conventional and green power. In this webinar, analysts from S&P Global Market Intelligence reviewed the company’s power forecast findings for the second quarter of 2021 to identify key changes in generator valuation, assess market dynamics, and examine merchant natural gas, solar, and wind assets in PJM, Electric Reliability Council of Texas (ERCOT),[1] and the California Independent System Operator (CAISO).[2]
These and other questions were addressed in the Q2'21 Power Forecast: Overheated Power Markets are Here – Who Wins, Who Loses, and Why? webinar and the post-webinar (Talk to the Experts) held in August 2021. This blog summarizes some of the key discussion points.
Presenters from S&P Global Market Intelligence:
Karishma Bhimani, Moderator, Product Manager, Commodities
Kristin Larson PhD, Senior Analyst, Energy
Steve Piper, Director of Energy Research
Adam Wilson, Research Analyst, Regulatory Research Team
Questions and Answers:
Q: Where do you see electric vehicle (EV) charging using up all the oversupply? How much will EV electricity compute to the total supply requirements by 2030?
Kristin Larson: We use the load forecast from the ISOs. As we know, President Biden has announced some aggressive targets for increasing EVs so, as the ISOs take that into account in their load forecast, we'll take that into account too. We update quarterly.
I looked at the EV issue for PJM, CAISO, and ERCOT. In PJM, they are just predicting how much the EV load will increase from the summer peak. That forecast is for approximately 260 megawatts in 2021, and then 1,054 by 2028 and 1,279 by 2030. The PJM total demand is around 150 gigawatts, so EV charging is about 1% of that value. It's not a very large percentage and is not taking up much of the oversupply. CAISO definitely takes the EV forecast into account, although I couldn't find how much of the electricity generation was specifically attributed to EVs. In ERCOT, they're currently assuming that whatever the EV charging was during the last five years will apply throughout the rest of the forecast. They're also planning to have an independent EV forecast coming out later this year, which hopefully will take into account these new targets by President Biden.
Q: How does the solar build-out reflect closure or repowering of older units reaching their end of life? The same question for solar and wind.
When we forecast solar and renewable build to meet renewable portfolio standard requirements, resource adequacy, and overall load requirements, we build the near-term real projects that are in development into the forecast and those that are reaching their life end. For the latter, the forecast doesn't specifically shut down projects based on some cycle, but keeps them running unless there is a specific announced closing.
We also look at some of the economic returns as they stand currently. For example, the Klondike III project located in Oregon has generated energy revenue returns that are below its expected debt threshold. It does have a current contract in place, however, that is right at full equity return of about $59 per megawatt hour, although it’s set to expire by mid-2027. At that point, the project has a decision to make, assuming it doesn't want to just shut down. If the contract wants to continue operating, it can either refinance with a new contract and a new settlement structure and debt payment or, it may be an opportunity for repowering if the technology is a bit out of date.
There was another question about whether storage is going to be the main driver for a ramp down of natural gas, or will it be renewable generation. At a high level, we expect that renewable build-out in California and in the other parts of the country will undercut baseload gas, in particular. We're starting to see that in some areas of the country where renewable development has been particularly aggressive, such as New Jersey and New York. We expect storage to undercut peaking generation, so the combination of solar and storage is expected to affect the base load generation of gas. As storage build-out increases, especially long-duration storage, it will increasingly compound the economic pressure on natural gas projects in California.
Q: What's your view on the potential impact of the suggested National Archives and Records Administration (NARA) minimum offer price rule (MOPR) submitted to FERC? There was an article that was titled "Critics, PJM's minimum offer price rule overhaul will crater the capacity market."
Steve Piper: The asset owners managing conventional generation in PJM will be concerned about the lack of upside. If we revert to a prior auction structure, the mitigation rules imply that capacity prices would trend much higher, something that our forecast finds. That potential was still there despite the very low price we saw in the May auction. But we do think that reverting to something closer to the prior rule structure will probably promote a degree of stability. It just won't be as strongly priced as a lot of stakeholders may prefer. So we do see prices recovering rather than staying at current crater levels, but perhaps sacrificing some of that long-term upside.
Q: There's another question on the impact of global warming used in the forecast.
Kristen Larson: We are seeing large heat waves impacting demand, and we had that big cold wave in Texas earlier this year. We use the normal forecast from the ISOs, so we don't use our extreme high or low forecast. That will come on into our forecast to the extent the ISOs are looking at the effects of climate change.
Q: Given recent wind improvements, or things like rotor diameter increase, do you think they're significant for enhancing the economic value of wind generation facilities?
Adam Wilson: Yes, I certainly think those are playing a big factor in the increasing value proposition for wind. Solar development in CAISO is far and away outpacing wind. But, according to our model projections, in order to meet resource adequacy requirements, we expect wind to get reignited by the end of the forecast period, with a lot more wind generation being developed to meet requirements.
The technology improvements that we're seeing will play a big role in two ways. First, turbine manufacturers are creating more turbines with a specific megawatt capacity rating, but with three, four, or five different rotor diameters that are better suited for different types of wind environments. These are more tailored wind turbines that make it easier for developers to pick one that can maximize generation in a given region. Importantly, the cost of these turbines is going down. It used to be a bit more expensive to create bigger turbines on a per megawatt basis, but we're seeing those gaps close.
Q: Steve, previously you mentioned that higher natural gas prices will have an impact on southern wind energy generation. What is the price sensitivity for that to happen?
Steve Piper: The surge in natural gas prices has a lot of consequences that can be hard to tease out. One that's fairly clear is the pressure that puts on wholesale electricity prices, which really changes the economic equation for renewables. In our assessment, an average annual price north of $3.75 per MMBtu really starts to put hybrid economics in play, makes the returns to both solar and wind look better, and actually gives wind a bit of an advantage. More expensive natural gas may hasten the movement to these resources.
Q: With parts of the country starting to open back up, can you foresee an uptick in demand as large energy using commercial and industrial companies get back into full swing?
We use the load forecast provided by the ISOs, so we'll see what they incorporate into their forecasts. We did see a dip in demand during the pandemic, and we see most of the forecast increasing to pre-pandemic levels this year and going forward. In general, the pandemic effects haven't been very large. For example, in some places last year, you wouldn't be able to see the effects of the pandemic if the weather was unusually hot earlier in the year. So, we do use the weather normal forecast in these assessments.
Q: What is equity return?
Steve Piper: It refers to the price expressed in dollars per megawatt hour, where both the debt and equity holders are satisfied. Basically, it's the annualized price for those resources. For those familiar with the Lazard levelized cost of energy (LCOE) studies, this would be our estimate of the annualized value for LCOE. If you were to levelize that value, you would basically get our LCOE for that resource at a 12% equity return and 7% debt return.
Q: Kristin, a two-part question for you. First, would you highlight any zones that you could see as potential breakouts in the base residual auction (BRA) or PJM capacity market auction that are scheduled for December of this year? Second, what do you think will happen to these PJM gas assets if the auctions continue to clear lower than we forecast and closer to the 2022 and 2023 BRA?
Kristin Larson: So, what's going to happen to these projects if the capacity revenue is not as high as we forecast. The debt requirement and equity returns are forecast and based on a plant built in 2022. Depending on the actual contracts and the finances of these exact plants, they might have different financials. If the capacity revenue isn't as high, they will not make as much profit. That could put some of the gas plants into financial stress, and they would have to consider how to finance things or consider if it was economical to go forward. Other assets are having that issue in PJM with the lower capacity market prices.
In our forecast for the auction in December, we are predicting that the EMAC and MAC regions in the east coast states will break out of the renewable purchase obligation (RPO) general prices of PJM. So both regions will be slightly higher than the rest of the market clearing price.
Q: Since solar and wind are considered mature technologies, why are subsidies still necessary?
Adam Wilson: Probably the main reason is to help drive the continued growth of wind and solar at a scale that would push the energy transition at a rate desired by the current administration. To have carbon-free generation by 2035, we really need an aggressive build-out of these resources, along with multiple other factors.
Q: Are we putting the cart before the horse regarding our continuance to push more variable generation on the vertically integrated grid that's in need of serious upgrades, both in terms of hardware and digitization?
Steve Piper: Through the few decades of experimentation with electric restructuring, there's been a very strong lean towards incentivizing private investment in generation. There hasn't been a corresponding incentive provided for having price signals that incentivize transmission investment and grid upgrades, relief of congestion, and things of that nature. I don't think it's unique to renewable and intermittent generation versus conventional generation, but there has been less evolution of policy as regards grid investment, and it's something that needs to be addressed.
Q: So if the projects aren't economic, why do you show projects getting built?
Steve Piper: I assume that question is referring to wind projects, which goes back to this resource adequacy requirement that CAISO has in place. We expect that energy storage, battery storage will play a significant role in meeting that requirement, but it can't do that completely on its own. We need to continue to build other resources. At the moment, we are limited to wind or solar, and we expect wind to be in a better place, certainly by the end of the decade with peak demand being later in the day when solar isn’t generating as much. Wind is more reliable in terms of resource adequacy.
Learn about our U.S. Power Forecast solution.