PFR Thermal Power Roundtable 2020
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PFR: Where are you all seeing opportunities for greenfield and brownfield CCGT development? Where is the smart money looking?
Keith Derman, Ares Management On the natural gas-fired side, we believe the greenfield opportunities today are fairly limited. The math for your run-of-the-mill PJM interconnected CCGT is less compelling than it was a few years ago.
The retirement story on coal and nuclear has been in play for years, and it was one of the many factors that drove new CCGTs in PJM and a few in New York and a few in New England. But with gas prices where they are, with the uncertainty of the capacity market in PJM, from a greenfield perspective it’s hard to get excited. As an industry, we’ve overbuilt yet again. We’ve done this before, and we’ve seemingly done it again, though maybe not as drastically as 20 years ago.
The Midwest, MISO, is a market that we’ve been following closely for years given its heavy dependence on coal, and we’ve been expecting it to pop, but it really hasn’t. That being said, we do have a late stage MISO development project that we’re pretty optimistic about, which we would be building under more of a traditional contractual framework as opposed to the quasi-merchant frameworks we have seen of late. But a lot of the Midwest – and we’ve seen this with NIPSCO as a good example – appears to be almost skipping the so-called gas bridge and going right from coal to renewables, which is pretty remarkable. So, again, on the greenfield side, there is not that much activity for the foreseeable future.
On the brownfield side, it becomes a question of an owner’s likely tolerance for a little bit of pain. We’ve seen pretty wide bid-ask spreads on transactions when something is in the market, but the capital structures are so conservative, with a few high-profile exceptions, that most owners don’t really have a gun to their head to sell. So, there are some select opportunities in the thermal brownfield M&A market, but not that much execution because people are, amongst other things, disagreeing over curves.
John Drake, Osaka Gas USA I would add that right now, the primary issue is the regulatory uncertainty and, of course, more recently, the bearish signals from the commodity markets, in particular in the Northeast.
It will be challenging. There’s still an oversupply situation in many regions in PJM, so there’s going to be limited opportunity for greenfield development. We might see another project or two coming online, but with gas netback arrangements that extend beyond the five years. The traditional revenue put is not going to cut it these days.
In MISO, obviously there’s still a lot of coal that needs to be retired, but it remains to be seen at this point whether there could be a smooth transition to renewables without incremental gas additions.
Nuclear, I think, is probably going to hang in there a bit longer. Folks are starting to appreciate the zero-emission aspect of it, as well as the fact that it is a major component of local economies. So by default, states are incentivized to keep nuclear units in the mix and potentially promote extensions.
Derman, Ares Maybe even more so now post – or I should say amidst – Covid.
Drake, Osaka Gas That’s right. Which raises the question as to whether this opens the door for some of the modular nuclear units that we have been hearing about. It remains to be seen, but coal is certainly on its last leg and the question is, how is this transition going to take place. With all this uncertainty, greenfield is going to be tough at this point.
Daniel Englander, Panamint Capital Keith’s comment about Midwestern utilities skipping the gas bridge and going straight from coal to renewables is endemic of what we’re seeing across the board. Previously, there were opportunities to work with utilities to provide assets to bridge the gap. What we’re seeing in the Midwest is utilities either skipping the gas bridge or sponsoring rate-based greenfield. I think there are a couple of combined-cycles in the upper Midwest, in Michigan, Wisconsin and Minnesota, where utilities are directly sponsoring those developments. That’s pretty relevant from the perspective of investing in greenfield assets.
What we focus on are opportunities that are insulated from the underlying impact of changes in commodities because they have a strong locational advantage or provide an essential service in a load pocket or in a congested area. The origination process and the analysis to identify these types of opportunities is more nuanced and rigorous than what we’ve had to do in the past.
PFR: One of the interesting trends that has caught our eye is what is happening in Texas, where we have seen some merchant peaker assets getting built and financed. What do you make of that? What do you think is driving that?
Englander, Panamint As ERCOT adds more renewables to the system with zero marginal cost, it begins to push baseload further and further to the right. So what you’ve got is a situation where your baseload is now being provided more and more by renewable power and the intermediate or mid-merit is being squeezed out, creating a need for more peaking capacity. So to the extent that these developers believe there are sufficient economics in running 100 hours a year, we understand why that makes sense. There’s not a lot of room in the middle for mid-merit assets. What had previously been baseload is now mid-merit, and the economics of that are thin.
Derman, Ares I agree, and I think you’ve got some folks that are trying to capture some of the volatility. In ERCOT, you’ve got a market where there has actually been load growth – we’ll put Covid aside. You’ve got no capacity market, and you have periodic weather, intermittency continuing to grow, substantial wind, solar maybe not growing quite as quickly as some people thought, but there’s an incredible amount of solar development activity and we think capacity will definitely get built. How much actually gets added and how quickly, I don’t think we know yet, but all of those attributes lead to volatility. So, they’re trying to capture that.
I am not entirely sure if that is a business plan or a physical trading strategy but regardless it isn’t our business model. Interestingly, a lot of the proposals we’ve seen on peakers in ERCOT have had one particular consistency, which is: how are they going to build these CTs, these simple-cycle projects, really inexpensively? Many of the proposals include grey market equipment and other angles where they can put steel in the ground quickly and below sticker cost.
Englander, Panamint The capex point is important. Certainly, it’s hard to model that volatility in a way that supports an underwriting case. I question whether a new-build peaker makes sense relative to taking over a steamer and doing some capex on that, and using that to capture the volatility. One thing I’m surprised that we haven’t seen more of in ERCOT are reciprocating engines because they have a lower capex on a new-build basis than a CT and are more modular. It’s a way of managing greenfield exposure that you mentioned, Keith.
Drake, Osaka Gas We don’t focus on ERCOT but we do have an asset there, which is contracted at this point. When you look at Texas relative to California, Texas is number one in wind, compared to California being number four. If my memory serves me right, it’s on the order of 29.5 GW, whereas California is maybe 6.5 GW.
When you look at the solar side, that gets flipped. California is number one in solar at a little over 14 GW, and Texas is number four with about 2.5 GW. In the current dynamics, we see a shift in Texas where a lot more solar is looking for a home there. Keep in mind that Texas is in the unique position of having both strong wind and solar resources, so it makes a lot of sense.
Considering the potential build-out of solar, which shaves off the peak, since the peak load occurs in the middle of the day, the handwriting is on the wall. When you look long-term, it’s very difficult to underwrite a base-loaded unit there. Today’s price signals may not be enduring.
As both Keith and Daniel pointed out, peaking units and, in particular, lower-cost peakers, is where the focus is right now. You can source them through the grey market or use recip engines to keep costs down. You can even incorporate the ability to relocate them if necessary to accommodate the renewables growth.
The thesis here is that you can make your money with a low cost-to-build peaking unit, if you have a strong summer in ERCOT. That’s the bet that we’re seeing.
PFR: You mentioned California. There have been a lot of contracts awarded to large energy storage projects there recently. Have we seen the end of new or brownfield gas-fired generation in California?
Englander, Panamint Greenfield development of thermal power in California is dead, and I think has been dead for a while, both because of the market and also because the overwhelming public policy that inveighs against developing new thermal assets.
But on the brownfield side, there was a good opportunity probably two, three, maybe four years ago to acquire peaking units in California on the basis that the dynamics that we’re talking about in Texas would also show up in California, which is that the market becomes peakier. The peaks become more stochastic and having a low capital base minimizes your exposure to the volatility.
Derman, Ares Well greenfield gas in California is certainly dead. I think that we may have developed and constructed the last true greenfield in California, with a project called Pio Pico down in San Diego. There were a few gas-fired projects that got built after that, but they were generally at existing generation sites. So, Pio Pico may have been the last pure greenfield or at least one of the very last. The project faced some high-profile regulatory challenges but ultimately settled into a 25-year tolling agreement with SDG&E. The project became a success, and Pio Pico provides important quick-start and flexible capacity to the region but I can promise you that I won’t be developing gas again in California anytime soon. As Daniel described, that ship has sailed.
In terms of existing CCGTs in California, the math is tricky. California has historically paid attractive pricing to incentivize new-build, but when you come off a contract and that pricing rolls off, then you land in the RA market, and whatever-you-can-get in the merchant energy or hedge market…it’s really hard to make that math work today.
As a result, we’ve seen some well before end-of-life CCGT retirements in California. The state is all-in, and has been for years, on decarbonization, the energy transition, 100% renewables, and they’ve been strongly incentivizing storage for many years.
So, what can survive? Certainly, assets that are under contract, but also probably some of the more efficient peaking plants with lower fixed costs. Some of the LMS100s, for example, that got built over the last 10 years – when they roll off contract, they’re going to continue to support intermittency, they’ll support the system as storage continues to grow and costs of batteries are coming down.
Englander, Panamint One thing that gives us pause in California and across the greater West – Arizona, Nevada, Oregon, and Washington – is the long-term regulatory risk of being a thermal asset owner.
The trends that we’ve seen in California are now being replicated across the other Western states, and we see utilities making 100% decarbonization commitments, over and above state RPS level. We’re also seeing commissions be much tougher on regulated utilities about what conventional assets are being put into the rate base.
As we look out five years or seven years from now, the question that we ask ourselves is whether in addition to having an uneconomic asset, you may end up with a fully stranded asset because of regulation or public policy.
We recently participated in the final round auction for a CCGT in the Desert Southwest. One of the break points for us was thinking about the contracting story in seven years when that toll rolls off with the IOU. While historically there has been some level of certainty around being able to recontract with a utility in the area, we aren’t sure that will be the case – or even need – with the substantial amounts of solar and storage coming online. As such, some of these conventional assets may become long-run uncompetitive.
[ArcLight Capital Partners was the winning bidder for Desert Southwest CCGT – the Griffith Energy project (PFR, 3/3).]
PFR: Let’s move on to financing. How has deal flow and debt pricing been impacted by Covid-19, from what you’ve seen, for thermal generation in the US?
Drake, Osaka Gas I think, right now, the impact of Covid has certainly delayed a lot of transactions that were in the works. In terms of greenfield financings, there haven’t been a whole lot in the market on the conventional side. Projects actively worked on will experience an increase in margins, probably on the order of 50 bp or more.
There are also a lot of lenders or credit committees reviewing their credit metrics, so there’s probably going to be a little tightening there, including the hold levels. I don’t think a lot of banks are going to be willing to hold the amounts that they were considering prior to Covid.
In the term loan B market, we haven’t really seen a lot of activity. It’s been a while since we’ve seen any action on the power side. I think the one deal that everybody is waiting for is the Carlyle financing that’s currently in the market. From what I’m hearing, it is proceeding well and soon we’ll see the results. In terms of margins, it’s not clear but I get the sense it will approach Libor plus 500.
[The deal – Hamilton Projects Acquiror – was priced at 475 bp over Libor on June 10, after this roundtable took place (PFR, 6/11)]
Of course, an emerging consideration for the conventional side is what’s going on with tax equity since it impacts carbon capture (Section 45Q). Tax equity, at least for the rest of the year, may be limited as some of the regional banks are pulling back, given the uncertainty of their appetite. In summary, banks appear to be more cautious in terms of lending while, so far, the term loan B market seems to be open and available.
Derman, Ares I think that’s right, and a lot of it depended on where you were in your deal when we all had our ‘Aha!’ Covid moment over a three or four day period in the second week of March. If you were advanced in your deal and you are a sponsor with banking relationships, those deals generally got done.
We saw this in the global financial crisis and you see it again today. This is the time when your tenure in the industry and your relationship with the banking community, as well as your relationships with the tax equity providers in the renewable market, all of this comes to roost and when it all matters. We closed a back leverage and tax equity financing in April with ING and US Bank on a residential solar portfolio and no pricing or terms were re-opened and there were no delays (PFR, 6/2). We believe that speaks volumes about all involved.
We saw ArcLight, another well-respected sponsor, get the Griffith deal done that Daniel mentioned and, you’re right, I think the term loan B market seems to be starting to open back up for these types of deals.
Generally, for newer deals starting to advance through the financing process, what we hear about is a reasonable trade-off in an increase in credit spreads for some savings in the base rate. The credit spread widening is a little bigger in gas than it is in renewables. In renewables, you’re probably in the 25 basis points, at most 50 basis points spread increase range, and gas is probably going to be more like 50 to 100 basis points right now.
But again, the key is what kind of relationships you have, who are you transacting with and where you were on your deal when conditions began to deteriorate.
PFR: Daniel, I’m sure you’re out there looking for acquisition financing as you go out and bid on assets. What are you seeing at the moment?
Englander, Panamint Our approach, traditionally, has been to finance assets on an equity basis and then to go back to the bank market to refi when we’ve completed some optimization work, to take out some of the acquisition equity. So we’ve been pretty insulated from that perspective. We did test the market in March or April for a small debt transaction and based on the feedback decided to hold off.
PFR: One of the themes that we hear from very enthusiastic investment bankers is that they’re going to find equity in Asia. Asian equity investors have been a strong force in the market. We have a representative of one here. Are they still in the market? Have the underlying dynamics that brought them in the first place changed?
Drake, Osaka Gas When we talk about Asian investors, it is important to differentiate the Japanese investors – who have been in this market for a long time, and in terms of the number of players and capital invested, they certainly break out from the pack. More recently, we have seen some new entry from Japan, as well as Korean money that participates more actively across the capital structure. We’re talking about the past, maybe three to four years. It is not clear, or at least I don’t have a good sense, if they have the staying power and what their ultimate behavior will be if the road gets more bumpy.
Going back to the Japanese investors, they obviously come in different flavors in terms of capacity, capability and strategy. You have the trading houses that tend to be more nimble and are able to refocus their efforts if they don’t like something they see, such as the regulatory uncertainty in PJM right now.
Of course, there are a number of committed Japanese investors with the ability to develop and the capacity to underwrite entire projects, as we have recently seen that with J-POWER. Perhaps, a common theme is that we invest in the sector by taking a long-term view as buy-and-hold players, looking to build a business. This way, we’re able to manage through some of the cyclical aspects of the business as well as able to get our arms around some uncertainties. So, I would say that most Asian capital will probably be more cautious but remain committed to the sector.
Englander, Panamint John, are you seeing a difference in the level of enthusiasm or participation if you divide up the Asian investor market between more active participants like Osaka Gas or J-POWER who are owners of assets versus the more passive investors such as asset managers or insurance companies, for example?
Drake, Osaka Gas I think what happens is that investors like us tend to develop a long-term strategy and part of that strategy includes expanding our capabilities and understanding of the markets. That becomes a process, whereas financial-type investors usually try to anticipate an exit at some point, and that’s what makes it more challenging, given the various moving pieces in these markets. Identifying an exit makes it very difficult.
I’m not sure 'enthusiasm' is the right word, but the commitment is still there. There’s just more thought in trying to understand and navigate some of these issues that we’re facing. Once we get over the next couple of BRAs, I think that they’ll provide much needed information. Right now, we’re starving for market signals.
Englander, Panamint The comment that you made is interesting, which is that for the financial investors, it’s becoming harder to define or identify an exit case for an asset.
Drake, Osaka Gas I think right now, when you look at the markets over the past year, we have not seen any real distress driving activity. Look at the term loan B market. Most of the activity last year was for dividend recapitalizations as opposed to acquisitions, and I believe last year was the first time that dividend recaps may have exceeded the other activities.
At the same time, I get the sense that the implied valuation for these dividend recaps surpasses those of buyer valuations in the market, so there is that disconnect. We talked earlier about the bid-ask spread which I think is driven by the expectation that at some point things are going to normalize. There is always the potential for some distress out there but, in general, this is not a good time to exit with a specific value in mind. That’s where you need more flexibility.
Derman, Ares I think with the Asian investors, it’s a little difficult to tell right now exactly where they are on greenfield, because the greenfield activity has slowed so considerably. There was one PJM project in the market leading up to Covid that was rumored to have an anchor Asian investor, but that deal was pulled. Now it may be back on, that process will be interesting to watch for a host of reasons.
I think it’s safe to say, though, that they’re cautious, or, certainly, they’ve pulled back to some degree. And not surprisingly, we have seen Japanese interest around renewables increase considerably.
And that makes sense, right? Because that’s where the market activity is, and the activity is driven by the cost profile, the competitiveness, the improved performance that we’re seeing out of wind and solar not to mention the decline in storage costs.
We have a highly attractive and efficient and well-located natural gas portfolio and, I think a very strong reputation for construction and operations in natural gas generation but many people don’t appreciate that we’ve invested meaningfully in renewables. Over $2.5 billion invested historically including about a billion dollars in renewables over the last two years or so.
PFR: As you’re looking at the debt markets and having conversations with your banking partners, have you seen any interesting new debt features or new debt instruments that are being offered to help mitigate some of the inherent challenges in the market?
Derman, Ares In our most recent term loan B refi at Birdsboro, we did utilize a hedge toggle. We had built the project and put in place a somewhat shorter-term revenue put at financing. When we reached COD, we refi'd the bank loan, but we didn’t extend the hedge. It only runs through the middle of 2022.
The new loan is priced with the existing hedge in place, but if we don’t add incremental hedges as time goes on, then the credit spread toggles up modestly so the banks get paid for a pure merchant (for energy) profile. Investec did a nice job structuring that for us. Beyond that, it is hard to say right now, what creativity is creeping into the financing markets because, as we discussed, activity has slowed to some degree
PFR: We have heard mezzanine investors say that they see an opportunity, especially on deals where there is a more merchant component. What have you seen in the mezzanine capital market? Is there a role for that?
Derman, Ares Definitely. Mezzanine offers flexible capital that can offset traditional senior debt or equity. Mezz lenders are willing to take certain risks, both market and structural, that the bank or term loan B market cannot take.
Mezz investors are usually able to play across virtually all transaction types including construction, acquisition, refinancing, recapitalization, and rescue financing.
Over the past few years, we saw capital-constrained developers utilize mezz to offset the equity capital needed to reach financial close on new construction assets; these processes have a high degree of complexity across debt, revenue offtake, and equity. Just on the debt side alone, a closing requires coordination among a club or syndicate of lenders. And so a mezz solution can offer execution certainty to achieve a closing; the solution may be a mezz bridge or mezz term loan. As it relates to M&A, large private equity sponsors did not require mezz as they primarily relied on traditional bank and term loan B debt.
Today, we are not seeing much new build and both the bank and term loan B market appear open for M&A transactions. As a result, we have not seen much mezz activity in thermal power. It is possible that mezz may offer attractive recapitalization solutions to asset owners who value creating some liquidity, but are reluctant to sell at today’s valuation – that bid/ask spread I referenced earlier. Of course, if we see dislocation in the credit markets as we did in March/April, then the direct lending community will likely offer a strong value proposition across both senior and mezzanine transactions.
PFR: The three letters that I think everyone has views on are, of course, PJM. How do you think the PJM capacity auction issue is going to play out? How are sponsors preparing?
Englander, Panamint We recently looked at a brownfield PJM asset. Where we came out on that asset was consistent with how we think about the value of both energy and capacity in competitive markets. Thermal assets become less and less valuable over time. So our view is that even to take a look at this asset, we would be pricing the capacity value at the bottom of the range.
PJM has overbuilt and the dynamic that we're starting to see there, similar to Texas and California, is that more renewables are coming on. It doesn’t necessarily play well for long-term capacity prices or baseload assets
The uncertainty around the structure and timing of the PJM auction certainly hasn’t been constructive from a financing standpoint. But, again, that uncertainly is indicative of regulators trying to cope with the energy transition, to make sure the rules incentivize the types of assets that public policy wants to see in the market. That’s having an impact on uncertainty for thermal financing. As such we’re not expecting to see prices where they were three, four, five years ago.
Derman, Ares As far as when the auction is going to be, right now sponsors are just praying there will be an auction.
I have no way of predicting what’s going to happen or not going to happen, but the conversation has escalated beyond the question of ‘when’ around some of the states taking a look at leaving PJM. Who knows but that is going to be a tough genie to put back in the bottle. Thankfully, PJM’s capacity is three years forward, so it hasn’t really come to roost from an existing-asset perspective. It impacts your financings and your new build, but if this was the NY-ISO that was caught in this morass, we’d have a really big problem.
But, what most folks are expecting is that the auction is going to happen and PJM is going to just do some catch-up, where you might have an auction every six months once there is some resolution around the issues that are being debated.
Englander, Panamint They’ve been chipping away at it for years with out-of-market subsidies for nuclear power, for example. We saw that in New York too. Look at the impact of that on capacity prices in New York. So I think you’re right, Keith. The more we see states beginning to act on their own outside of the constructs of PJM, the more risk there is that if the capacity market does return then it’s not going to look like it has previously.
Derman, Ares We own the Newark Energy Center in our funds, which was one of the three New Jersey [Long-Term Capacity Pilot Program Act] projects to receive a [Standard Offer Capacity Agreement] contract from back in 2012 or so. The LCAPP program, along with a corollary program in Maryland, were litigated all the way to the Supreme Court, where those contracts were ultimately invalidated on FERC pre-emption grounds. These issues have been fought for a long time and don’t seem to be going away.
Drake, Osaka Gas In general, ISOs are constantly undergoing structural changes and refinements as they attempt to create or develop governing rules which allow different resources to participate in the market. Right now, we’re seeing activity to accommodate storage and recognize the value it provides to the grid. Again, there are the immediate issues (BRAs) and then the question that was raised before, the [Fixed Resource Requirement] option. A number of states, including my home state – NJ, are examining actively FRR right now.
The question I have for Keith or Daniel is what are their views on the economic or fiscal condition of the various states, given the vast amounts of stimulus and support to address Covid-19, in terms of both their appetite to really push hard for subsidies and, in particular, things like offshore wind, as well as their ability to go down the path of FRR. I think these are big questions.
Derman, Ares I have no idea what you’re talking about. The economy is fine, just look at the stock market
Seriously though, we don’t really know yet. The can has been completely kicked down the road by unprecedented fiscal stimulus, but something has got to give, because there are small businesses that have failed and will fail, substantial unemployment, and all of this is going to have major implications for states and local balance sheets. It’s going to have an influence. We just don’t know the full impact yet.
PFR: On hedging, we have heard that the revenue put has basically been replaced by the gas netback. Tell us about the market for gas netbacks. Who is out there offering them? What are the terms? How have they evolved?
Derman, Ares We have a netback on one of our projects, which is currently under construction in Southwestern Pennsylvania. The netback’s tenor as well as some of the structural protections to the downside are pretty unique.
The strength of that agreement allowed the project to raise equity but, most notably, it allowed it to achieve an investment grade rating and bring a new-build combined-cycle in PJM to the bond market, which hadn’t been done in probably 20 years.
But new netback arrangements have tapered with the slow in new-build and the current credit profiles of the gas companies isn’t helping. Maybe, if gas prices do truly recover, as the forward suggests that they might, as a result of the reduction in the associated gas coming from oil production, maybe we’ll see a number of additional deals get financed by netbacks or maybe even another structure as hedges evolve that’s even more attractive to the bank and sponsor community.
Or if gas prices recover but credits do not, maybe that could even bring the revenue put back, because the reason the revenue put went away is the gas prices just kept getting lower, sparks were getting lower, and so the gross margin that you needed to guarantee the cost of that revenue put was just getting too high if you wanted to end up with a capital structure that was, give or take, 50:50 debt to equity. I just don’t think it’s there right now, but that could change.
Drake, Osaka Gas That absolutely makes sense. The issue, right now, is who is behind the netback. The financial condition of some of these producers, given where oil prices are now, is very challenging. There is a need for credit enhancement, and you have to weigh in the associated cost.
Clearly, through netbacks you get better deals because you have greater revenue visibility and you can extend them beyond the traditional five years of a revenue put; it’s a better structure for financing as well as for the sponsors. But at some point, you have to look at the economics and weigh your options.
Englander, Panamint We haven’t looked at any gas netbacks in probably the last six to nine months, so I couldn’t really comment on that. From a hedge perspective – both in ERCOT and the Desert Southwest – we’ve seen a movement, at least from HRCOs [heat rate call options], which is something we’re very comfortable with, to more spark spread swaps or swap options, which is something that we’ve started to get comfortable with and something that seems like the hedge providers that we work with are offering more, as opposed to straight HRCOs.
In terms of the pricings of the hedges that we’ve seen, though, there really hasn’t been much of an impact, as far as we can tell, from Covid. If anything, it seems as though the forward curves in ERCOT are becoming less backward-dated, which is certainly a benefit, and maybe that’s because the near-term prices are coming down this year and the back end of the curve is staying the same, so it could be a function of that. But, long-term, over the next two to three years as we’ve been pricing out, there hasn’t really been, as far as we’ve seen, any significant change in hedge pricing.
PFR: Are there new hedge counterparties that have come to market?
Englander, Panamint In the West, what we’ve been seeing on the thermal side, actually, is, yes, there are more wholesale C&I customers who are stepping out for slices of thermal, and I think those are customers that are procuring lots of renewable energy, that are doing so principally under virtual PPAs. The need that we’ve identified is from counterparties looking for a basic backstop or reserve capacity to sit behind those virtual PPAs. It’s a pretty small market right now but, certainly, we’ve seen some interest from folks that even two or three years ago wouldn’t have been considering buying thermal power on a wholesale basis.
Our thinking is what is driving that, really, is that as these large procurement entities are buying up more renewables, they’re also identifying a need to have a firm backstop for that capacity, just to underpin their operations and maybe as a way of reducing their exposure to utility costs.
PFR: Let's look at the impact of climate and ESG concerns on the availability of capital, both debt and equity. What has been the impact of that?
Derman, Ares ESG is a very significant focus both at Ares Management and our Infrastructure & Power business. To be clear, we aren’t just talking about the E, we take the S and G extremely seriously as well.
That is, in some respects, part of our firm’s shift towards greener pastures. It’s the economics as well as ESG as part of our shift towards climate infrastructure and renewables, and energy transition assets. But, I do believe that there’s absolutely, still, capital available, equity and debt, for natural gas generation. I don’t think that anything over the last few months has changed that. The interest level is driven by the math. Can you make the returns work? Are they compelling?
We talked earlier about greenfield gas generation and I think we all agreed that it’s going to be fairly modest for the foreseeable future. But I do think that events of especially the last two to three weeks, but also the events of the last three months, are going to heighten the focus on environmental justice as one of the elements of ESG, and one of the elements of permitting. It’s already a focus, but I think you’ll see potentially more around that. And that may further slow greenfield gas generation.
Then, of course, there’s coal. It’s a four-letter word. It has been a four-letter word. The bank market is clearly out of coal. The term loan B market, maybe, is out of coal. We saw one recent deal that couldn’t get done. Maybe it would have gotten done with much higher pricing, I don’t know. And, maybe there’s some equity out there that would buy coal, but I don’t think it’s in the infrastructure universe. It’s really more whether it’s in the PE or the distressed universe, but it’s pretty limited and that scarcity is driven by both economics and ESG.
Englander, Panamint We work in both conventional and renewable power, and for the conventional investments that we do the focus on putting to money to work is that the investment case has to have a climate-positive story.
That leads us to looking at assets on the thermal side that are supportive of the energy transition, such as providing balancing services to support the build out of renewables or bridging the gaps between conventional and renewable power to give consumers power that’s firm and clean.
At least from our perspective, and the perspective of our investors, it’s not sufficient just to do a thermal deal on the basis that it makes money. There has to be a climate-positive story associated with it.
Drake, Osaka Gas In general, we’re sensitive to ESG considerations, although I’m not aware of a specific target. When you look at any long-term projection, gas is going to be there for the next 25 to 30 years in a very meaningful way, so that’s what we’re focused on – capturing this opportunity.
At the same time, we are looking to build our renewables investments, as well. Up to now, it has been a bit of a challenge, given that pricing is not commensurate to risk for pure cash equity.
Beyond that, I was very encouraged by the section 45Q tax credits that are out there, putting carbon capture into play. I think that it could become a very important tool going forward in terms optimizing the portfolio of technologies that will solve the climate issue.
PFR: What are you seeing on that front in terms of opportunities to do carbon capture and storage? Are you looking at it as an investment opportunity?
Drake, Osaka Gas We haven’t looked at it yet. It’s still very early. I was at NRG when Petra Nova was still on the drawing board. At the time, the project was built assuming $75 oil prices, and when they dipped to $50 it was still okay, but not where it needed to be. Of course, this year, the project is facing some challenges. At the same time, I think the new tax credits provide a new path forward. Recently, Starwood announced a big project aimed at taking advantage of these tax credits.
It’s going to be interesting and challenging. When you look at the issues associated with carbon capture, use and sequestration, they extend beyond the use of new technologies. You have exposure to potential environmental liabilities, operating risk if you’re not meeting the minimum levels, as well as timing issues. To bring in tax equity, first of all, sponsors must address the risk allocation. At the same time, banks are not ready to finance a project like that, requiring different sources of funding. There are a lot of hurdles still to address, but it definitely opens up possibilities for the future.
Derman, Ares I remember looking at a bunch of IGCCs almost 15 years ago, but all pre-financial crisis and, again, John, to your point, oil being at $75, this was when gas was reliably five-six, post-Katrina, $14/MMBTU. Very little if any of it got built and that was because of cost, and technology risk as well as the development cost including just trying to finance the very expensive [Front-End Engineering Design] studies.
I know that things have come a long way and there are considerable tax incentives, but I’m not sure that the related issues plus subsurface questions have been completely resolved.
PFR: Daniel, your views on carbon capture opportunities, and also, can you actually finance coal phase-outs?
Englander, Panamint That’s a good question. First, on the carbon capture, the availability and existence of tax credits still doesn’t mitigate the operational issues with carbon capture. To the extent that we still can’t put together and underwrite a case for carbon capture makes the tax credits, at least at this point, fairly meaningless.
On the coal phase-out, again, there’s not a lot of data on these kind of transactions. My understanding is it’s mostly around remediation and reclamation companies taking over coal assets from vertically integrated utilities and the vertically integrated utilities using the depreciation benefit of those assets to underwrite the liability of the transfer.
It’s an interesting play but it requires a lot of specialized knowledge and most of the buyers of those assets, they’re not power generation firms. They’re in the business of taking these assets, taking them down and redeveloping them into Amazon warehouses. I think that’s a play, but I think what will happen eventually is that regulators will work out that these coal transfer deals aren’t really a great deal for ratepayers, because ratepayers are still footing the burden for these assets long after they’ve been transferred off the utility balance sheet.