Mark Finley: It seems like whenever you're talking about big strategic developments around the world, you go back far enough and you find Winston Churchill talking about it. Over 100 years ago, when he was the First Lord of the Admiralty before he was the Prime Minister, Britain faced the question of, do we run our navy off of homegrown coal or imported oil… And Churchill decided to switch the navy over to oil-based fuel because it gave better performance for the war-fighting capabilities. And his answer to the security was, "Yes, it's important, but security lies in diversity and diversity alone," was his concept.
Teri Viswanath: That’s Mark Finley, a fellow in energy and global oil at the Baker Institute and formerly BP’s U.S. energy economist. It’s been over nine months since Russia’s invasion of Ukraine. This event set off a hard scramble in Europe to replace lost natural gas supplies and the ripple effects are being felt in the U.S. I’m Teri Viswanath, the energy economist at CoBank and I want to explore the developments in the U.S. natural gas market and, in particular, how co-ops might be handling the increased fuel costs resulting from the European energy crisis. I’m joined by my co-host and managing director, Tamra Reynolds. Hello Tamra.
Tamra Reynolds: Hey Teri. The start of the winter seems like the right time to have this conversation…especially since natural gas prices already broke through $10 per MMBtu this summer. We haven’t seen this level of pricing in more than a decade. And while prices have come down, it’s too early to write off the possibility of revisiting those levels. So to understand where our energy bills might be headed this winter, we talked to Charlie Blanchard, head of research for Mercuria Energy Group, one of the world’s largest independent energy and commodity groups. Charlie is author of the book “The Extraction State: A History of Natural Gas in America.” Here’s what he had to say...
Charlie Blanchard: The story this year, I really like when I say this year, probably the last 14 months or 15 months, has been a commodity bull market, a broad commodity bull market that certainly included U.S. natural gas. We hit, not record prices, but prices that we hadn't hit since 13 years ago. We almost traded to $10 but we spent a lot of time in the 8s and 9s and that compares to a long period when we were in the 2s and 3s.
If you're very short on storage, you're not going to trade that much lower just because it's the summer. Even though the issue isn't acute in the summer, the possibility of an acute issue in the winter will filter back into high prices in the summer. That's what we saw, basically, this entire summer.
This year, we basically ended the summer, so ended the injection season with about 3.6 trillion cubic feet in storage. So what does that mean? Is that high or low? Well, in November, or rather in late October 2018, we only had 3.2 billion cubic feet in storage.
Why were prices so much higher now than they were in 2018? The main thing that’s different is that we export a lot of LNG, and therefore, we need to take into account the price of gas in Europe, which is much higher, so that's the biggest difference. We essentially are tied to and not necessarily directly, but in this indirect way, we're tied to the price of gas globally and that makes us tied to events in Russia.
If we cut off exports, we need those prices to converge in order to incentivize exporters or disincentivize exporters from exporting. We keep the gas here, that's fine but in order to keep the gas here, we need to go to European prices. But that wasn't always the case. It wasn't the case because we didn't have LNG exports. It also wasn't the case because we had coal. Not only do we not have the coal plants that burn coal and make electricity, we don't have the coal itself even for those plants that are still around. That means that the only lever we have left if we had a cold winter would be to stop exports because otherwise, we're just pushing on a string.
Tamra: So, Charlie highlights that in the absence of being able to massively shift electric generation from natural gas to coal, the only option is for domestic prices to rise high enough to divert those U.S. supplies that would otherwise be bound to Europe or Asia.
Teri: That’s exactly the point he is making. Over the summer, the U.S. emerged as the largest LNG exporting nation-- basically exporting the same amount of natural gas that is burned in the residential sector, natural gas that is used to heat homes. Does this mean that we’re linked to higher global prices? Having had responsibility for developing the annual BP Statistical Review, I thought Mark Finley might be just the right person to ask about this. Here’s our conversation…
Teri: Mark, what do you think about natural gas globalization. Are we truly experiencing a market that is clearly connected with Europe and Asia?
Mark: I think we're heading in that direction but we're not there yet. The real story for connecting the world is liquefied natural gas. The reason is simple, a pipeline can only go to where the pipeline ends, a liquefied natural gas tanker can literally stop in the middle of the ocean and turn around and go anywhere in the world that has the capacity to receive it, and so that's the channel by which there is the potential to connect. The reason why I say we're not there yet is because essentially the U.S. LNG export system is running flat out. And so there is a base load of LNG exports, but beyond that, it's still dependent-- the domestic price of natural gas really depends on how domestic supply and demand balance.
Teri: We're only as connected as long as the LNG capacity here at home is not tapped out. And we have the ability to actually put more product into the marketplace when it’s needed.
Mark: Yes. In terms of the domestic price setting, what really matters is, as you said, is there a spare in the system that can be used to ramp up and down depending on how the situation here compares with the situation globally. When the capacity is running flat out as it is now, then it doesn't matter what happens in the rest of the world on the upside. It limits the upside risk because you can't force any more gas into the export system.
One of the reasons why Saudi Arabia is so influential and so important in the oil market, yes, it's a big producer but uniquely in the history of the world's oil market, the country has invested to maintain a buffer of spare production capacity that it can tap into in times of crisis. Now, and when the oil market gets into trouble is when Saudi Arabia and the other members of the so-called OPEC Plus group run out of that spare capacity.
Teri: It's interesting especially because the U.S. has become the largest exporting nation at a same time that we're seeing this global conflict in Europe with Russia. So Russia is stepping back from the table, and the U.S. is stepping in. But I’m not sure that those positions are perfectly aligned.
Mark: United States may be the biggest exporter of liquefied natural gas in the world, it is not the biggest exporter of natural gas in the world. Russia is by far a bigger exporter, but again, its exports are predominantly in the form of pipeline gas and predominantly to Europe.
What we're seeing now with the crisis is that as Europe has been struggling to find new sources of natural gas, and as Russia has been squeezing Europe to exert geopolitical leverage, the United States has tried to help but constrained by the fact that our capacity to export more liquefied natural gas is exhausted and that we have existing contracts to service other countries with those exports, including big markets in Asia like China and Japan. The flexibility of the system doesn't match what we have on the oil side.
Tamra: Teri, in my mind, the conversation with Mark begs the question on when this moment of globalization might occur. When will events in either Europe or Asia directly translate to price signals for the U.S. domestic market?
Teri: Well, Charlie Blanchard gave an excellent response to this “are we there yet” question. Here’s what he said...
Charlie: We are basically not increasing exports until late 2024, and really, it's not until late '25 and '26 when we go and basically double the amount of exports we have now. No change for a while and then boom, we're doubling.
Right now, we are at capacity out of LNG exports. That is why we are trading, essentially $6, whereas Europe is trading maybe $35 and the rest of the world is maybe trading $30. That's a big, and the variable costs aren't that much. The variable costs are maybe $2 to ship it. Right now, the spreads are massively wide and that's because we're doing as much as we can. We can't close the gap. We can't export more to bring their prices down, which would also bring our prices up.
My thought, and I think a lot of the market would agree in 2026 and '27, '28, and beyond, when we have all this new capacity, it's very hard to imagine that we have the gas here at home to fill it. And what that means is it's going to cause the spread between global gas prices and U.S. gas prices to come in and come probably screaming in. The next questions is, does that mean our prices go up more or does it mean global and European prices come down more? Frankly, I don't think anyone has the answer to it, but what we can say with relative confidence is that the spreads will come in quite dramatically.
Teri: Let's pick up on that point, are we overbuilding? In the long run, you actually see higher domestic natural gas prices, especially as we look beyond 2025 say. And why is that?
Charlie: It's because of the exports being, again, built primarily in 2025 and 2026. It's also because of the rate of change. Because a lot of these LNG projects are coming online in a quite rapid succession. Can you bring on even 3, 4, or 5 BCF a day of production within a 6-month period? It's happened before. But, we're not in that world anymore. I don't think. Why aren't we in that world? Some of it is the fact that we are running out of the best locations in shale. If you were able to somehow change that situation and build 10 billion cubic feet a day of new pipelines from Appalachia to the Gulf Coast, I think our prices are fine what they are. We basically have walled off Appalachia and further Appalachian production from getting to the market. Most of the reasons essentially are people don't want to build more fossil fuel infrastructure.
Teri: I feel like we have had a lot of consumers, a lot of power plant owners that have not had to hedge their fuel exposure because it's been prevalent, abundant, and cheap. Has that narrative changed?
Charlie: It's still prevalent and it's still mostly abundant, but it's just not cheap. It's just that we have to take into account now this insurance premium that if it's cold enough, which it probably won't be, but if it is, we need to price out that risk of going to a very, very high global level.
Tamra: There seems to be a clear message that we are quickly moving towards a structurally higher-priced fuel environment. The stalled process of building more pipelines, refineries, etc. means that we have to consider the physical limitations of the iron in the ground.
Teri: Absolutely, that’s my take as well. This feedback has really important and has strong implications on how our electric cooperatives hedge their commodity risk — both the financial risk and the physical risk of getting gas to their members.
Tamra: Following our conversations with these well-respected energy economists, I thought it would be helpful to get a tactical framework for hedging for our co-ops. I reached out to Charley Harrell, the director of finance at CoServ Gas, and Gary Franzen, the director of energy services at CoServ Electric. CoServ Electric has been around since 1937, serving about 275,000 members in six counties around the DFW metroplex. And it’s actually my hometown co-op from where I grew up. The gas company was formed in 1998, serving 150,000 customers with annual demand of roughly 12 BCF.
Teri: That was a terrific conversation, with two experts who have weathered the ups and downs of natural gas price cycles here in the U.S. And most importantly, they understand physical operational risk for procuring the fuel.. Here’s the conversation we had with them. The first response you will hear comes from Charley Harrell, followed by Gary Franzen.
Teri: I want to understand as you both consider the landscape in the market, how have your views changed with regard to energy procurement?
Charley Harrell: It's been a long two years. I'm not sure I can go through a Uri again. It's had some very definitive effect on us such as now we're carrying much larger during the winter months, much larger baseload than we were in the past. The main thing during the period is to mitigate the risk for the gas prices.
Gary Franzen: If I can elaborate when Charley says baseload, what he is referring to is the amount of gas that we purchase a month in advance such that that amount of gas gets delivered every single day of the following month. We're purchasing a higher quantity of gas to be delivered every single day of the upcoming month going forward. We used to try to minimize the need to inject during the heating season, during the winter months.
Charley: Inject storage.
Gary: Inject into storage, correct. Now, we have accepted that we're better off having a higher volume of baseload as Charley referred it. When we have milder days in the winter and warmer day in the winter and don't need as much gas used by our customers, then we inject more of that into storage. That allows us a little more flexibility when on the days when it does get really cold to not have to purchase so much or pull so much from storage on a daily basis.
Teri: Basically, having a larger buffer?
Gary: A larger buffer.
Charley: Yes. I think that's been one of the big changes. We've looked at some financial hedging, but that is very difficult. Where we're located is very difficult to find a good hedge financially, a financial hedge because it's just not that liquid of a market for the hedging in this area.
I think what we've come back to in hedging is that it's actually storage. Storage is the true hedge you need. You need the physical hedge of it. Until Uri happened, nobody really wanted additional storage.
The prices were stable, yeah, you had volatility there's always been some in gas, but not the volatility we're seeing today, and so it's become a bigger commodity. Even some companies that I knew weren't going to increase their storage are now doing that, and we're the recipient of some of that.
Teri: Charley, you had mentioned the difference between looking for a financial product that could best hedge and getting back to the fact that when you need the gas, you need to make sure that you have it in place where you need it. It sounds like the physical playbook that maybe you had possibly in the early 2000s is seeing a new fresh chapter?
Charley: It really is. That's what it came back to is that you got to have the gas to get it, and you have to have a way to transport it into there. Going into the storm, we had maximum capacity of 2.2 BCF, and by the end of 2024, hopefully going into 2025, we'll have somewhere around 4 BCF storage.
That's a lot of gas you can pull out given that we're in Texas, we're not going to have an Alaskan winter hopefully. It's not going to last all winter. It's going to last for 4, 5, 6 days at the worst usually, and that gives us the ability to have that gas coming into the system when you really need it. That's really what our idea of protecting our customers, mitigating that price risk is.
Gary: Another thing that we have done as we negotiate these new storage agreements is we've put more emphasis on the daily withdrawals, the maximum amount that we can withdraw in an individual day. Typically for a storage unit, that's a relatively small percentage of the overall amount of gas that you have in storage that you are allowed to withdraw in a day, because they don't want to disrupt the storage but we have been negotiating for higher daily withdrawal rates, again, to give us more flexibility for the extreme weather days such as a Uri when we've got a tremendous amount of heating demand to supply.
Charley: Technically if you did the calculation, we have six turns a year, which is very quick, but we don't have withdrawal rights during the summer, only during the winter, and we don't have injection rights during the winter, only during the summer. Now I'm sure you can get some gas in there, but now we're looking at other ways to supplement that. We've talked to other gas marketing companies and one of the things they can do is we don't have to inject, we can just buy their storage from them, and they'll transfer it over to us.
Teri: Interesting. Do you think more participants out there are looking at, because it's also been a problem on the pipes, is they have had interruptible, not firm rights. We possibly are also seeing completely through the supply chain, firming up that relationship to make sure you have the supply.
Charley: Yes, and right now all of our transportation is firm, the storage is firm. We only buy firm gas. Except during Uri we get any type of gas we could get. Our customers, 98% of our 151,000 are residential customers and we serve human needs. We need firm gas, we need to know what's coming in to protect our customers.
Gary: CoServ Gas historically, for many years, has maintained firm gas capacity rights and delivery rights. We have heard through the industry, just as you mentioned, Teri, that many of the other gas off-takers, both gas distribution companies like ourselves, but power plants, too, are really looking to try to firm up their delivery rights, their capacity, and delivery rights.
Tamra: The reinforced playbook that we heard about from CoServ also includes a very robust program of member communication and coordination. More than two out of three Texans, or 69% of the state lost electricity at some point during Winter Storm Uri. One of the defining moments for our co-ops was the relatively positive perception that their members had, due to the coordinated efforts to communicate what was happening during the storm.
Teri: As we’ve heard from our guests, the U.S. natural gas market is evolving and it’s important that our cooperatives plan and pivot with those changes, to ensure that they continue to reliably serve their co-op members. CoServ’s procurement strategies demonstrate a thoughtful response to a changing marketplace. First, they’re going to keep a higher level of baseload gas on hand, and they’re going to make sure to have flexible but firm delivery options to deliver that gas.
Tamra: I want to thank our guests for providing their insights and, of course our listeners. I hope that you will join us next month where we sit down with the Exawatt team, as they discuss the global outlook for battery energy and the supply-chain challenges ahead.
Teri: Goodbye until then.
