Power Prices (Hub, Node, All Hours, Dispatch Weighted)
I have got some reports from Leidos (a technical consultant) that I am trying to decipher.
Could someone please explain to me what is an "all hours" power price, what is a "dispatch-weighted" power price?
I work at an IPP in their development team and we have a project located in a certain zone in NY. The end goal is trying to figure out what price can our project's generation (MWh) get. I am at complete loss on what's the difference between all these prices they've given me.
Anyone here knowledgeable who can give a basic primer?
ChatGPT
the problem with using chatGPT, if you dont know about something, is knowing whether it is providing you the correct or wrong info!!
Did you just start at the IPP? Surprising the development teams wouldn't know these terms. Makes me wonder about value creation at the project level.
"All-hours" / around-the-clock / baseload prices represent the market average across all market participants, i.e. it's the closes to the zonal "price" of electricity you're going to get.
Dispatch-weighted takes into account the technology (or more specifically, dispatch timing) of your project. Big problem with solar is the duck curve / cannibalization. All solar produces at the same time (midday), which leads to lower / negative prices as solar penetration increases. Hence, the "dispatch-weighted" average price for any given solar project in a market with material solar penetration is lower than the "all-hours" price as solar is dispatching at the times with the lowest prices. Same concept applies for wind albeit to a lesser extent as wind is more sporadic than sun; not all wind farms in the PJM are dispatching at the same time (unlike solar).
Long story short: use dispatch-weighted. Also use consultant forecasts with a heavy grain of salt. Odds are your realized power price will be lower than what they forecast absent any exogenous shocks (e.g. Russia / Ukraine driving up the prices of marginal fuels gas) given the perverse incentives in the renewables industry (development pace trumps unit economics).
Source: jaded PE investor in renewables.
Really appreciate it dude, very helpful, thank you. I have a quick question for you on your last sentence when you say "unit economics".
I have done consumer/business services/industrials before transitioning into renewables, and while am familiar with the concept of unit economics, I dont know how one defines unit econ with respect to renewables, which is my follow-up question to you.
By unit econ, did you mean unlevered project returns, EBITDA margin, or something else? And if you are referring to unlevered, do you generally factor in PTCs or ITCs into those calculations, or try to get a sense of unleverd returns on an unsubsidized basis?
Also, since smaller power plants (<50MW?) are generally not economically feasible to begin with, i.e. to say the revenue (Energy, capacity) you can make on them would not be enough to offset the opex/capex (on a MWh basis), is there a minimum defined nameplate-capacity while calculating unit econ?
When we diligence a platform, we care about the all-in levered IRR, including PTCs and project leverage, a developer targets. If you're developing 1 GW/year at 8% IRRs, that's not going to cut it in this rate environment, and you're likely destroying shareholder value relative to their cost of equity. Would rather own a smaller developer with a moat in a certain market enabling 13%+ IRRs vs. a whack-a-mole approach of develop everything you can at questionable economics.
Unlevered returns are a helpful benchmark but we care about levered.
No, there is no minimum capacity when calculating unit economics. The fact that smaller projects are not as attractive will be reflected in the resulting calculation. Your CapEx/kW will be too high to make a decent return without believing in unrealistic power prices.
There is really no one internally that you can ask this question to? Your company literally owns a bunch of power plants, and these are extremely basic terms...
All-hours power price is the average power price over a 24 hour period. Dispatch-weighted price is the actual realized price of a plant based on when they sell power into the market.
Hub price is the price at a central hub, typically one that has liquid trading. Node price is a more fine gradation that gives you a price in a smaller area (so there will be a bunch of nodes around a hub), which should more closely track the price of a plant in that node.
My manager sucks. His English is so bad that when I try asking him something, his explanations go over my head, and there is no one else in my team I can turn to. Also, if he finds out, I am going to others, he'll be pissed.
I joined 9 months ago...so it is now embarassing to ask such basis questions. But the explanation that you gave as well as the poster above made total sense to me.
Since joining, I have read a few primers from 2007/2005 published by some equity research analysts, but there are still gaps in my knowledge. Anything (report, publication, book) that you think one should read?
Also, can I ask you two more questions please if you don't mind?
1. What's your thought process for trying to forecast what the power prices are going to be 10/15/20 years from now? I know this industry used Pterra and Leidos as consultants for forecast power prices, but I can't critically dissect them yet.
2. If someone was to ask you a very broad question that which market/country you'd invest in with respect to renewables, how would you go about framing an answer? Allow me to take a stab on the second one.
a. Attractive unit econ (unlevered returns; levered returns), which are a function of:
- Demand (high load growth expected, GDP growth, population growth)
- Supply (low renewables penetration but a commitment to renewables development and by retiring off hydrocarbon generation)
b. Internal capabilities (know-how of market or relationships with consultants/advisers/offtakers to be able to execute)
My answer to the second question is not comprehensive, but would love to hear your perspective. Thanks!!
I would try to read equity research reports on companies in the space, go through their 10-Ks, etc... Do you have any relationships in banking power groups? If so, you could benefit from reaching out to someone and asking if they could do a walkthrough / primer on the markets with you. Someone at roughly your level (so Analyst or Associate).
Well typically, on the buyside, we would employ our own market consultants, not just use the seller's consultants. Do you guys not have an internal forecast team? It's surprising that they would just be asking you to stick your finger in the air and make a prediction. It's extremely multifaceted to predict power prices and no one ever gets them right. The general considerations you listed lower in your comment are the right ideas - it's a mixture of demand growth, transmission growth, supply growth, planned retirements, length of the interconnection queue - all of those things go into it, and having never been a market consultant I would never claim to be able to predict power price forecasts with any level of precision. At most, I would perhaps be willing to take a view that prices "should" go up if there is a major planned retirement in the next few years and the queue doesn't seem to have enough replacement projects in that time frame, but that wouldn't really hunt more than a few years out, and it's also way too simplistic to actually be valid. I guess one thing I'm confused by - are you looking at an uncontracted project? Or early stage development? The reason I ask is because if you don't have a contract in place, that's quite unusual for renewables right now (people aren't really building these projects merchant).
If I was looking at a market to invest in, it would be a function of renewable policy (subsidies, RPS targets, etc...), land scarcity (is there enough real estate to meet the targets), transmission constraints and required buildouts), demand (as you said), and interconnection queue. I'd also read the actual content of the market consultant reports with a critical eye and see if the arguments they make sounds credible (they're going to try and put their most bullish ideas in there).
One helpful exercise is benchmarking consultant forecasts by calculating the marginal fuel price and/or heat rate implied by their power prices.
Say you get a Leidos forecast of $50/MWh by 2035. Say you then roll forward the generation stack for whatever ISO you're in and find out natural gas sets prices [70%] of the time. This implies power prices should largely track the short-run marginal cost of CCGTs. Say the average CCGT in the given ISO has a [7,500] heat rate, and the variable O&M cost of the CCGT is [$5/MWh].
Hence, a $50/MWh power price implies (50 - 5) / 7.5 = $6/MMBtu long-term gas prices. Compare to current gas forwards / Henry Hub forecasts + basis to your market. Make a decision on whether this is reasonable. The research Principal above mentioned helps you get the market context to make this determination.
The math breaks down in markets where renewables become the price-setting technology as they have 0 marginal cost (or in some markets it can be negative due to the presence of green certificates (LGCs), i.e. you're incentivized to produce even at negative prices as the LGC will make you whole). In markets with majority of generation coming from renewables, the long-run trended LCOE should be a better proxy for the market price.
However, all in all this is what I view to be the main problem with renewables. Even for contracted projects there's a duration mismatch between a 10-15 year PPA and 30-40 year useful life; your first PPA will never make you whole on your return and you need to belie vein the merchant tail. Nobody knows how to forecast this stuff and the consultants are just trying to get paid and get deals done. It's all very finger-in-the-air. Renewables are the new upstream imo.
You mentioned NYISO so if you google how NYISO works as a “capacity market” they explain it on their website.
Based on these questions major topics in general you want to brush up on. Essentially how power is dispatched so first you need to get an idea of what is a “capacity vs energy” market. Then you need to understand how transmission works (this where your question around nodes comes in).
Per the responses from PE experts here; they are discussing two situations that basically renewables result in. 1) duck curve 2) wind ramp, now all energy ramps as demand ramps through the day but sometimes the capacity factor of wind can fail or shift making it harder to ramp, duck curve is created by over saturation of renewables. CAISO for duck curve, I know other poster mentioned PJM but MISO for sure has written more about their wind issues.
Some thoughts to your other question historically renewables penetration focused mainly on technology/capacity factor. More continuous sun you get the easier to implement solar, OK/WTX is super windy lets build a ton of wind farms. Over time the learning has been (like batteries will be) the actual way the grid works is key and this is where ideas like congestion/how-iso-pays-you is more key.
Thank you! The way I think about energy/capacity revenue is that energy revenue is you actually selling an output/product (MWh) to someone, while capacity revenue refers to you being paid just for being on standby. To draw a paralell, someone just paying you for being on the roster without having to do any work.
Still trying to get around transmission. I have an extremely big picture idea of how transmission works, which is how I was able to get through interviews, but there are some concepts related to transmission that I have come across, but I can't sensibly articulate how they interrelate.
For instance, as you know, there are financial transmission rights, which take a long time to obtain. If you get those, does that mean the ISO will not be curtailing your electricity any more? I understand there are two types of curtailment (technical, economic). Technical is due to the system issues, but here I am referring to not being economically curtailed by the ISO. I also read somewhere that it's also advantageous if the transmission / interconnection cables connected to your project are high voltage to minimize electricity losses, and I think most lines that I've seen mentioned in the CIM are 340Kv. But I am not sure if you come across a project, which has a 500Kv connection, whether that is materially better than a 340Kv or if it's just a nice addition (if I was to draw a parallel, going from Wharton to HBS/Stanford GSB is not a massively big upgrade)
There is definitely a lot of material out there, but most of it I find to be confusing / haven't come across something written to cater to someone who has very rudimentary knowledge
Seems have a good handle on the cost side of the equation and less so on the revenue side. To start FTRs work differently in each market and the auctions are short-term versus PE investment timelines. Not sure its a good idea to build a power plant in a congested area and then add other kinds of risks by buying FTRs on top or if the optics even look good. What if prices suck and there is no congestion? As one random example.
To your other question that is something expert panels on engineer side will help you solve.
I agree with your thoughts on Capacity vs Energy. So maybe you just feel overwhelmed cause you clearly get some of it.
Lol at the OP asking questions he should be asking his employer
what a clown
This is one of the best threads on WSO! Thank you immensely to the three posters
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