Storage versus gas
Developers are pushing ahead with more gas-fired power projects, and lenders stand ready to finance them, but equity may be in short supply. What is the outlook for further development? What about gas peakers? Energy storage can provide the same service more cheaply and is already eating the lunch of gas peakers in California. Will it do the same in other parts of the country? A group debated these issues at the 30th annual global energy and finance conference in California in June. The following is an edited transcript.
The panelists are Ross Ain, president of Caithness Energy, Randolph Mann, president of esVolta, Rob Morgan, CEO of GE Energy Storage, and Joe Tondu, president of Tondu Corporation. The moderator is Caileen Kateri ("Kat") Gamache with Norton Rose Fulbright in Washington.
MS. GAMACHE: Ross Ain, what reception are you getting from financiers for new gas-fired power plants?
MR. AIN: Caithness is in the market with two very large gas plants. One is an 1,850-megawatt combined-cycle plant, three units in Guernsey County, Ohio, and the other is a 620-megawatt combined-cycle plant in Harrison County, West Virginia.
There are ways to attract all levels of the capital structure with a properly structured project. We have been able to achieve that by making innovative use of gas-electric hedges.
The plant we brought on line in September last year, an 1,050-megawatt project called the Caithness Freedom project, used a gas-electric hedge over 10 years that assures us of always being in the money on our energy sales. That takes a lot of risk out of the project and made it possible to attract both the debt and equity needed to move forward.
MS. GAMACHE: There are concerns about the long-term viability of natural gas as a fuel in New England because of constraints on pipeline capacity. That said, Seth Shortlidge, CEO of NTE Energy, who was scheduled to join us today, was called to New England in connection with a natural gas plant in New England. Are there particular regions that are better for natural gas and better for storage, and why?
MR. TONDU: Definitely. Obviously if you are in Texas, natural gas is a different game than if you are in New York. The drivers ultimately are going to be economic. There is lots of opposition to construction of new gas pipelines because there are people in this world who think they can predict weather a hundred years from now within two degrees. Well, okay.
I believe you are going to find there are gas reserves just about everywhere that can serve a lateral market. You have upstate New York, Ohio, Pennsylvania, and a grid system that covers the entire eastern half of the country.
It is difficult to find a place where we can't put a lot of gas on the ground right now.
I drilled gas wells in the late 1970s when we were selling gas for $6 a million Btus. We had no thought that it would ever go down.
Today you can see the future for 15 to 20 years at sub-$3 gas. When somebody starts to get competitive on price, those Aggie engineers will drive it down another 25¢. It is unbelievable what they have done in the last 10 years in the industry.
MR. AIN: Location is critical in the gas market, but there are a couple factors that come into play. Number one, there is a lot of gas. The producers say, "We are not discovering gas, we are just manufacturing gas. We know it's there. We are just moving the rig over when the rig finishes the spot it's in." They are doing three-mile laterals now under the ground.
The amount of gas in the Utica and Marcellus region, where I'm most familiar, is enormous. The critical thing is pipelines. And what you want to do as a developer of an electric generating project is locate where the gas producer will avoid significant pipeline costs to move the gas to market.
So these projects become, in a sense, mine-mouth gas plants. They avoid the new cost of 75¢ to $1.50 that we saw yesterday in new fixed charges on interstate pipelines moving the gas to Henry Hub or moving the gas up to New York City or some other place like Chicago.
Our Freedom project is located next to three Transco lines. Our project in Ohio is located right on top of the Rocky Express 42-inch 1,000-psi line. There is a lot of gas in those lines, and there will be a lot of gas for a long time.
Our company and our investors are very confident that we have a long-term gas supply available to the project.
MR. MORGAN: Sometimes that conversation is like having the system operator run the unconstrained dispatch model.
If we had no constraints, we would do "x." We have constraints in the system. We can call them policy. We can call them carbon. We can call them other things. Those constraints, say, "Maybe we should do something different." That's where I think battery energy storage comes in. Right now, batteries have won the race.
Just like the old Betamax-VHS discussion. Lithium-ion batteries are good enough for all the things the system is asking us to do right now. If you run the constraint-dispatch model, you do things differently. So policy matters, too.
MS. GAMACHE: Are you battery storage companies focusing on transmission systems that have a lot of congestion?
MR. MORGAN: Transmission is one. You have distribution. You have markets like California that say, "We have a mandate." And then you start to look at where the market rules and the compensation mechanisms are moving toward paying for the service that a fast response, safe non-polluting asset provides.
MR. MANN: As a storage developer, I spend a lot of time trolling the internet, looking for click-bait, and it is not "Keeping Up With the Kardashians," it is usually "Keeping Up With Retirements." We are looking for places where renewable penetration is increasing, where fossil fuel and nuclear plants are retiring, and where new capacity will have value.
Storage is a perfect technology for that type of situation. It is why California has been a very interesting market because we are seeing a very high penetration of photovoltaic solar. You are seeing nuclear retire. You are seeing fossil fuel have a tough time competing, and so storage is really coming to the fore and becoming a critical part of the grid here.
MR. AIN: In southern California, you have a unique convergence of events that has pushed storage to the fore. Number one, you had no air credits available in the LA basin, so no new fossil fuel units could be built. The only ones that could be built were repowers of old ones where they already had the air credits.
Number two, new transmission lines were practically impossible to site in the dense LA basin.
Number three, you have the duck curve and essentially the free charging of batteries in the afternoon.
Those three factors are critical to why batteries have had a very good jump start to all of our benefit in southern California.
The question as we move to other parts of the country, is whether there is enough of an advantage from the cost savings and the experience with batteries to make them competitive with other forms of energy.
MR. MANN: You are absolutely right. There are certain advantages in California that made storage grow rapidly here.
One slide stood out in the opening presentation yesterday morning: the wholesale power market price in three or four markets is in the $20-a-megawatt hour range and operating costs of coal, gas and nuclear are in the $30s, $40s and $50s.
Then you realize that the cost of wind and solar is going to keep falling, and the cost of storage will keep falling, too. We talked for an hour yesterday about the growth of the electric vehicle market. That market is really driving big manufacturing into battery cell manufacturing, which is driving down the cost of grid storage. So to me, the trends are headed inexorably in that direction.
I agree that some markets will get there much more slowly than others, but I think the long-term trend is toward zero-marginal-cost renewable energy setting the marginal cost. You still need capacity, and batteries can make money even when power prices are negative.
MR. MORGAN: You make a great point. If you think about the grid business, we are a small portion of what batteries are doing across the world.
Look just at China. Last year China sold a million electric vehicles, the first time a market has reached a million. If you do a million electric vehicles times a 50-kilowatt-hour battery per vehicle, that is 50 gigawatt hours. A big storage project is one gigawatt hour.
We are the tail of the dog. We get to have all the benefits of that, but sometimes we don't get the attention we deserve because we are trying to drive cost down for wholesale rather than retail prices.
For a sense of scale, the electric utility industry worldwide will probably only be 10% of the battery market worldwide.
MR. TONDU: Let me ask one thing. I don't really understand the battery business. I don't know the economics. My concept of a battery I think is wrong. And I don't know how many people here really understand it.
The fact that they are being used in California tells me nothing about the economics. And when somebody says it will be free, the red flags go off in all directions for me.
It seems to me that batteries have a unique spot in the market. When I think of a battery, I think we will run the power plant all night long to charge it, and it will discharge the stored electricity to the grid all day long the next day, and we do that back and forth.
But in reality, they are really unique little spotty moments in time when you fire them up to give yourself ancillary services or you give yourself quick start-ups.
What is the market for batteries? What is the optimum looking little spot for which they fill a niche?
MR. MANN: Fair question. The answer is it really depends. There are a lot of different use cases. Our typical customer is a utility. Sometimes the utility is looking for help with its transmission and distribution system, so it adds storage to a feeder line or a substation in order to manage load growth at that location. Other times it is looking for peaking capacity inside of a load pocket in an area where you cannot site a gas plant or transmission, but it wants to bolster the area with peaking capacity. Other times, storage is really a tool for integrating renewable energy.
Our biggest project to date was for a utility that was trying to retire a natural gas plant and replace the capacity.
The way we are getting paid is a capacity payment, plus an ancillary service value plus an energy arbitrage value.
The storage facility that we operate in California essentially operates 24-7 in one of those modes. Sometimes it is providing regulation-up services, and sometimes it is providing reg-down, depending on what solar and gas are doing in the state. Sometimes we are trading on the margin to earn an arbitrage return. We can sell one type of capability to a utility customer and another type into the wholesale market.
MR. MORGAN: I want to challenge the notion of little spotty moments.
It really depends on the market. The kinds of services that energy storage provides have been embedded in the utility system forever; you have spinning machinery, you have generators, etc.
As we have restructured and de-structured markets, we are getting to a resolution on the different services that is really interesting. It is kind of all of the above. You can provide three services at once as opposed to one at a time.
The whole conversation today about whether storage will displace gas peakers: well, sure. In California, storage is displacing peakers. Elsewhere, in Texas, not yet. In Australia, we are doing solar-plus-storage, and in New York, we are doing solar-plus-storage because that is what the market is asking for. I just challenge that notion that is has a little spot. No, it has a big spot in the market.
Spotty Little Moments
MR. TONDU: How unique of a circumstance do you need to have to make it work?
For example, in Texas, one of the ideas that we talked about earlier was that you can put storage on a gas turbine project so that you can have instantaneous output during the four to seven minutes it takes the turbine to ramp up.
Well, that is interesting in an environment where you have big swings in power where, all of the sudden, you need 60 megawatts or you need 10 megawatts. In Texas, you have that problem non-stop because you have so much wind that you are on and off, on and off, on and off. So in an environment where you need to do that more than a couple times a day, you are up against a wall. You really do need to keep the spinning reserve going in the gas turbine to keep it running in order to be able to respond quickly.
In a market where your primary use is an instantaneous drop of load because you lost a turbine somewhere else in the system, then you need to have that thing banging right now.
I can see that, but how often does that situation exist in reality, and how much are you willing to pay to be able to have power support for a few minutes while you get the turbine running? In a grid like Texas where you have 60,000 megawatts, a 60-megawatt power plant is insignificant.
MR. AIN: Let's not lose sight of developments in the last 20 years that allow gas combined-cycle units to be load following and operate at different levels. When we put our Long Island project into service in 2009, a 350-megawatt combined-cycle unit, we were allowed to go down to 75% of peak load and still be in emission compliance. So we could swing between 75% and 100% with duct firing on top of that. We had, in a sense, a baseload plant with a peaking unit on top at a very efficient heat rate.
In the new plant we just put online in Pennsylvania, we can be in emission compliance on 40% of our full load. So now we have 60% of the plant that can swing and meet those challenges very efficiently and cleanly from an environmental point of view. That really came out of what was going on in Italy and other parts of Europe when they realized they really needed to have swing and fossil generation to meet this kind of change in load.
The second point is the commercial aspect. We are working with GE on a wind project, and we are excited to back up our wind project with storage which we think has great value. Who is going to guarantee the performance of the batteries over 20 years? What balance sheet is going to be behind performance?
MR. TONDU: General Electric's balance sheet?
MR. AIN: We are delighted. That is a very important aspect of the battery industry to ensure we can get the financing we need efficiently for these projects.
MR. MORGAN: Ross Ain made a critical point about the operating profile.
Given our installed base of gas turbines at GE, we have been working to hybridize gas turbines with batteries. We have a couple of projects in southern California where we have now taken that P-Min from 40% down to zero. So you can actually run your gas turbine at zero and get full credit for spinning reserve because the battery picks up the first four or five minutes, and then the turbine can start. You are saving emissions. You are saving fuel, but the system operator looks at it and says that it is a single asset. And you can recharge that five minutes many times a day and still have a lot of cycles to it.
It is making the gas fleet run more efficiently, and we are adding life to the gas fleet, while we have all the renewables coming in. The intermittency of renewables needs that support of the gas fleet.
MS. GAMACHE: How important are subsidies for storage to get traction in the US market?
MR. MANN: First, let's talk about what the subsidies are. There is an investment tax credit for adding storage to solar, but for a standalone utility-facing storage asset, there are not any direct subsidies.
I'm a pretty simple guy. I don't look at lots of metrics, but one metric I look at is whether we are winning or losing RFPs. The second metric I look at is who won the RFP if we lost.
Looking at states outside of California over the last year, we have participated in probably a dozen RFPs that were all open-source RFPs looking for capacity. They were open to gas, storage, solar-plus-storage, demand response and whatever other ideas bidders could come up with.
I can't think of a single one that we have lost to a new gas asset. We have lost to existing gas. Storage is competing in utility RFPs in unsubsidized form.
We talked during the electric vehicle panel yesterday about baseball. What inning are we in? We are probably in the bottom of the first inning as far as reaching the potential for storage in the United States. There are a lot of places where we need to improve: whether it is financing or technology or warranties or 20 years of proven performance. But all of that is coming because we are finding that storage is, in fact, competitive against other types of capacity assets.
MR. AIN: I am a little bit more familiar, for instance, with New York, where the governor and NYSERDA announced, I think, a 1,500-megawatt mandated storage program. Is that a subsidy?
MR. MANN: It is mandated in New York. I agree with you, but storage is mandated in only three states.
MR. AIN: I'm just saying, how do you define subsidy if you have exclusive programs set up for batteries. I am not saying they are wrong, but mandates create their own mini-market or maxi-market as it may be.
MR. TONDU: Do you have a feel for what the percentage is between solar subsidized support versus open-market competition in the storage business today?
MR. MANN: Everything we have done so far is pure standalone utility-facing storage, so nothing we have done is subsidized, and some of it is in mandated markets. I agree that a mandate is a subsidy.
What has really surprised me over the last two years of doing this business is that we are able to compete in markets across the country where utilities are looking for capacity without a mandate. I spend time reading utility integrated resource plans — for fun. It is hard to find a utility IRP that does not anticipate a meaningful amount of storage to be added to its grid over the next, say, five years. And I would say that almost every one of those IRPs is wrong in terms of the cost of storage by an order of magnitude. They are overstating the cost because they are looking at two-year-old price data instead of two-year forward price data.
Threat to Gas?
MS. GAMACHE: Do you think that the battery energy storage industry is a threat to the natural gas industry long term?
MR. AIN: No. I think they perform different roles, and they have different qualitative benefits and drawbacks, and they will both be in the market over time. Certainly utilities have put batteries in to avoid new substations and other costs. That happened in New York City, in Astoria. And there are other unique uses of storage.
But I am a little bit skeptical of a rapid market penetration of batteries outside of government mandates over the next five years. I think a longer-term view of that would see a pretty significant market penetration of batteries.
MR. MORGAN: I agree with that. It depends on your time frame because, right now, gas and batteries are going to co-exist in a very happy relationship for a long time. But the existential threat is where gas prices will be over time. Where will coal and nuclear plants be over time? My view is that, if you look at a 30-year timeframe, it is absolutely the case that batteries are going to replace big gas peaking capacity and the peaking capacity of grids around the world.
MR. TONDU: I agree, but I think you are missing that gas is going to be — if it is not already — the baseload capacity in the country. Coal is toast, and so is nuclear. I don't think they will build another nuclear plant after Vogtle. I operate a coal plant; those operating cost numbers are right on, if not conservative. I can't run my plant for less than about $60 a megawatt hour, and I can buy gas all day long for $35. That game is over.
Batteries are going to augment or support baseload where it is possible to do whatever you can to make baseload a little bit better. But gas is going to dominate. It will be the only source of baseload here in another 10 or 15 years.
MR. AIN: Let me offer just one statistic. The last generation of gas, Frame 6 units, were about 55% efficient: let's say heat rate of around 7,100 Btus per kilowatt hour. The new H class machines are about 6,300 Btus per kilowatt hour. They are around 62% to 63% efficient. If you multiply that by a $2.50 gas price, you can sell power at about $16 to $17 a megawatt hour and break even. And anything above that, you are starting to make money.
As much as we talk about technological development, it is very interesting, as one who has been a student of the gas power industry for last 30 years, to see what unbelievable strides the manufacturers have made in terms of efficiency, emissions, etc. We are about to reap the benefits of that in the heartland of America where we are going to replace a lot of the older generation.
MR. TONDU: One last comment; you just reminded me of something. This is unbelievable what has happened in the industry, but it is also one of the greatest opportunities for the United States for economic advantage because we are sitting on the gas. We are sitting on the resource. We have developed the shale, and with these 6,300 heat-rate machines, our cost of energy is going to be the lowest on the planet.
MR. MANN: I think we have to distinguish between combined-cycle gas turbines versus peaking applications. Each market is different.
There is a role for gas long term in the industry. I am not trying to drive anyone out of business in any sense of the word. What I would say, though, is that some of the best days of operation for our CAISO-grid-connected energy storage asset 10 miles from here are days when solar is providing essentially 100% of the load in California, gas is not running because power prices are zero or sometimes negative, and we are providing essential service of reg-down and then reg-up to help the market work.
The future of the electric industry is zero-marginal-cost renewables. So you are right, the duck curve is a big deal in California, but guess what: the duck curve is coming to Arizona and Nevada and Colorado and Australia. Someday it is going to come to Maine and New York, as well. I think when you have an asset that can provide capacity and be paid both when markets are good and when they are bad, that is an asset and technology that you should deploy.
MS. GAMACHE: Are there any audience questions?
MR. HOWES. Walter Howes with Verdigris Capital. This has been a very interesting discussion, but it is missing one critical variable which is that in the next three to five years, you are going to start to find deployed small modular advance reactors and micro-mini reactors that will have baseload implications at the 100- to 300-megawatt scale.
MS. GAMACHE: So next year we should have a wrestling match with all of the different technologies.
MR. TONDU: I would take the other side of that position.
MR. MARTIN: Let me ask a couple questions quickly. You talked about 20-year warranties for storage. My understanding is that the standard is a two-year warranty and that you can buy an extended warranty, but can you actually buy a 20-year extended warranty for storage? Don't you have to replace too much of the battery at year 10?
MR. MORGAN: You can buy an extended warranty. It's pretty expensive.
MR. MARTIN: But you are basically replacing the whole battery?
MR. MORGAN: Really what we offer is a performance guarantee, and so we are saying you are going to get this much capacity, this much degradation, this much round-trip efficiency, but we are not going to warrant the manufacturer's product. The manufacturer will sell you an extended warranty for a long time, but it is very expensive because it is planning for that five, 10- or 15-year replacement.
MR. MANN: It is part of the economics. You plan for degradation, and you plan for augmentation. It is probably akin to major maintenance on a gas plant.
MR. MARTIN: The other question, Ross Ain, is do you agree with what was said yesterday that you really can't build another gas-fired power plant in New England because of pipeline capacity constraints?
MR. AIN: I have not been developing plants up in New England for a number of reasons. They are back-hauling gas out of Canada back into New England now because we can't get pipes through New York state. I think the jury is still out on what will happen there. I don't think, as Trump would say, they are going to wait for the wind to blow to turn on their TVs. They will want to have reliable energy over the next 20 years. So we will see what happens. I'm not sure.
MS. GAMACHE: We have time for one more.
MR. BUTTGENBACH: Tom Buttgenbach with 8minute Solar Energy. I would like to make a bit of a controversial point.
We are replacing gas plants today in California with solar. We can do a replacement of a gas plant with solar-plus-storage for somewhere between $30 and $40, depending on how big the battery is. There will be an announcement in the next two weeks about these projects. We guarantee an up-time of 99%. Your gas plant cannot do that. We are replacing an aging gas fleet that has an up-time of less than 80%, mostly driven by unscheduled maintenance. So in terms of reliability, we are certainly cheaper than a gas plant in California.
If you add in all of the emission charges, etc., we are certainly cheaper than a newly built gas plant. The battery is roughly on about a gigawatt-hour scale with a 20- to 25-year performance guarantee from the manufacturer. That is all financeable, and 20- to 25-year matches the PPA term. This technology is here today.
You are absolutely right that we cannot do that in the northeast, in Michigan or other places because we don't have the sunshine to run the power plant that efficiently. But we are going to be moving the Mason Dixon line up north over time as solar becomes more and more cost effective in other regions. This is coming. It is not going to happen in the next five years. Nothing happens in the utility world in five years. But in 30 years you will see solar with massive amounts of storage being the dominant form of generation.
MR. TONDU: Are you guaranteeing it through the night? Is your solar plant running at 3 o'clock in the morning?
MR. BUTTGENBACH: Yes it is.
MR. TONDU: Around the clock?
MR. BUTTGENBACH: It is around the clock. Matches the load curve.
MR. TONDU: For $30, around the clock, including storage?
MR. BUTTGENBACH: Mid 30's. We even run it very early in the morning before the sun comes up because the utilities have in California, at least some of them, what they call the morning peak, which is the load goes up before massive amounts of solar in California hit the grid. That is very expensive peak to fill with gas. You have to run the machines for an hour and a half to pay for all the emissions, etc. We keep capacity in the battery for that. The batteries are designed to match the load.
MR. TONDU: You have to have a gas turbine in the background to back up that entire system. You are not running that around the clock in isolation. You are using that to fill in the blanks.
MR. MORGAN: It is just like any asset. The grid is full of assets, and they are all running at various load levels. If you focus on the marginal assets, then you are missing the system point. There is coal, nuclear, hydro — there are all of those things.
MR. BUTTGENBACH: There is hydro and wind at night, so you can design the system around solar. It works. Does it rely currently on gas generation? Yes. I can make the battery bigger. My battery cost the last five years has gone down 18% per year. Will it continue to go down? Probably not that steeply, but costs will continue to decline. It is not a question of "if" storage will replace peaking capacity; it is only "when" and in "what market."
MR. MORGAN: I just have to say we need to add the "Buttgenbach line" to our vocabulary — it will be somewhere north of the Mason Dixon line.