Q&A: Gary Germeroth, chief risk officer at Calpine

Gary Germeroth, chief risk officer at US independent power producer Calpine, speaks to Pauline McCallion about the company, Dodd-Frank regulation and managing the risks related to renewable energy generation

Calpine is now one of the largest wholesale marketers of natural gas and geothermal power in the US. But last decade it was one of three large independent power producers (IPPs) to restructure under Chapter 11 bankruptcy protection due to the credit constraints and plunging power prices that rocked the energy sector in the aftermath of Enron's collapse in 2001. Filing for Chapter 11 protection allowed these US companies to protect their businesses and continue operations while they restructured at a time of severe financial difficulty.

More than 270 debtors and approximately $18 billion in funded debt made Calpine the sixth largest Chapter 11 case on record when it filed in December 2005, according to Kirkland & Ellis, the law firm representing the company at the time. After its restructure, the company successfully emerged from bankruptcy on January 31, 2008.

Gary Germeroth joined the Houston-based power company as chief risk officer towards the end of this period, in June 2007. He is part of a team that has worked to revive former relationships, connect with new counterparties and put the company back on a secure financial footing. Calpine now operates 91 power plants with 27,500 megawatts (MW) of capacity and its portfolio of natural gas and geothermal assets ensures it is well-placed to take advantage of the current trend towards clean energy generation in the US.

Q. Tell me about the steps Calpine took to improve its credit profile after emerging from Chapter 11 bankruptcy protection?

Gary Germeroth: NRG Energy had filed before us, as had Mirant [both IPPs], so it wasn't like we were entering new ground from the point of view of many of our counterparties – we were the third of the big independent power producers to file and so a lot of people were already pretty savvy about what that did and didn't mean.

Because of that, we continued to work with a number of counterparties as we went through the bankruptcy process. As we progressed out of bankruptcy, we worked with more people – on the origination side more than anything else. We built relationships back up from there if they had been damaged in the process.

We took some action to help too, obviously. For us especially, the credit facility we came out of bankruptcy with had a pretty big chunk of debt that had to be refinanced in 2014. Now that is all paid off and what we did was basically refinance that particular debt with first-lien bonds, spacing out the maturity of those bonds to give a much more even flow in terms of value every year. I think that showed a couple of things: some financial discipline as well as a robust strategy from a financial perspective that I think got a positive reaction from the market.

Q. How has the energy sector progressed during this time in terms of developing credit risk management strategies?

A. The energy sector is slightly ahead of the game in terms of master netting agreements1, giving companies the ability to consolidate obligations into one big pool to get leverage. I think so many more energy companies live by that rule now than 10 years ago. Such natural netting leverages happen every day, especially for a company like ours. Calpine is a big consumer of natural gas and therefore we owe people for natural gas, but we're also a big provider of power and therefore a lot of people owe us for power. By leveraging what we owe another entity for gas and taking the power position we have with them and netting both positions, we're much better off.

More companies accept such arrangements now. There was a time when some were reluctant to participant in netting arrangements because they were unsure about whether they would hold up under Chapter 11 or any other bankruptcy law. Over time, such agreements have actually held up, so more companies have become comfortable legally with that option.

Q. How do you think the new Dodd-Frank regulation in the US will impact your business and the energy sector in general in future?

A. This is a really cloudy area right now for many energy companies and that's the hardest part of the current regulatory environment.

Back when the bill was being discussed in Congress, the terms swap dealer and major swap participant (MSP) were coined and most companies like ours in the energy industry were actually more focused on the MSP definition than the swap dealer definition. Even back then, swap dealers were being referred to as market-makers, while everybody else seemed to be viewed as an MSP. Considering the bill's original intent, the worry was about systemic risk to the economy and there have been a lot of independent power producers that have gone through Chapter 11 restructurings that have had absolutely no effect on the economy. So it's really difficult to say that such companies create systemic risk in the economy.

So, we focused on the MSP category, but as the regulatory process progressed, some other nuances clicked into the definitions. In particular, the addition of the third prong to the definition of a swap dealer [regularly enters into swaps with counterparties as an ordinary course of business for its own account], which creates a very broad definition that is also quite unclear - if I read it as an English teacher, I'd say that it includes just about anybody that ever bought or sold a swap!

Calpine is like a lot of other companies in our industry in that we have a very large position both in power and natural gas due to our generating plants. Other people in the industry know that so they often come to us and ask if we would be interested in laying off some of that risk with them. But because of the way the swap dealer definition has been written, we're still really unclear as to whether we are one or not.

In addition, as we've progressed through the course of designing the new regime, another facet has been added to include those who "accommodate demand". Again, we're one of the top three consumers of natural gas in the US and so we hold a relatively large natural position in that market – do I accommodate demand by accident because of my natural position [in the market]?

Q. Since you are not yet sure what category you will fall into, have you been able to start preparing for the changes you may need to make to your business in order to comply with the new rules?

A. I feel really comfortable with how the CFTC [Commodity Futures Trading Commission] has defined the term MSP - the limits given for uncollateralised exposure for MSPs do give clarity to that definition. I know we will not be classed as an MSP and I don't think many companies in our industry will be either, especially in the independent power producer space, simply because most of us collateralise all of our obligations either through letters of credit, cash, or first lien facilities. But the swap dealer category uses less clear definitional terms, so you're faced with terms that are so amorphous.

If I knew for sure that Calpine would be classed as a swap dealer, I could start talking to our IT guys and begin looking for ways to restructure our transaction management processes and develop systems to be able to meet the new requirements. For instance, what if companies are to be required to report a transaction within 15 minutes? There isn't any transactional risk management system that I'm aware of in the energy space at the moment that can do that. I don't have any internal resource to go to about this and I couldn't call up [an ETRM vendor] tomorrow and ask them to have such a system up and running in three months. It's not possible and I had the same conundrum nine months ago and there is still no answer.

Q. So the timeline to complete the regulatory restructuring is also an issue?

A. Yes. Congress required that the new regulations be implemented in a year - easier said than done. The CFTC has had a really huge task thrown in its lap. These markets tend to be quite complicated, especially for power and natural gas due to all of the different basis locations at which financial derivatives can and do transact.

In an effort to placate end-users at the beginning of this process, [CFTC] chairman Gensler said that giving the CFTC access to all of this information would provide more transparency, basically allowing traders to make back the money spent on compliance, clearing and so on. But when you look at a market such as power trading, because there are so many disjointed locations, it's difficult to get enough depth to gain more transparency. In theory, chairman Gensler's point is correct, but in reality the power markets are not so simple.

And if the regulators give, say, a three-month window for implementation of the new rules once they hit the July deadline, that's also going to cause additional problems. The Dodd-Frank Act lacks a sufficient implementation time window to really consider all of the different facets of where this could actually end up.

Q. Do you think the market could suffer from a liquidity perspective as a result - that is, will companies simply stop transacting because the rules are too unclear and the stakes potentially too high?

A. No. We, along with most companies in our sector, will find a way to comply if we end up in the swap dealer category, rather than abandoning whatever activity it was that made us a swap dealer. And there is actually a really straightforward reason for that: the type of activities that probably have the greatest likelihood of making the company a swap dealer are those that we do as part of our normal course of business. We have these very large positions as a result of our assets on the ground and so people come to us and ask us to do certain transactions. Refusing to speak to anyone in the market is not a very good way to do business and Calpine can't hope to come under the proposed de minimis exception [exemption from mandatory clearing for companies transacting a certain amount of business] because it's so small that it's somewhat irrelevant for a company with [approximately] 28,000MW of capacity.

Calpine has to participate in the market – we have to be cognizant of the fact that its part of our business, so while its likely that the cost of doing that business will go up based on these new regulations, that doesn't mean we're not going to perform that function in the market anymore.

Q. Calpine operates 15 geothermal plants, generating up to 725MW of power. What are the differences between managing the risks surrounding this type of renewable power, compared to sources such as wind and solar?

A. There is a huge difference between geothermal and solar or wind. From a risk perspective, our geothermal assets can very much be regarded as base-load assets. The capacity is very consistent throughout the course of a day and throughout the course of a year. So, in some ways it's very similar to having a large coal position, in terms of the pure, raw base-load aspect.

With solar, on the other hand, there is obviously the off-peak aspect at night, when the sun is not shining, but also during the day you have to worry about atmospheric effects such as cloud cover. Wind is also totally dependent upon questions such as is the wind blowing and at what speed? So it's much more imprecise - by a quantum factor – and that will always be the case.

Q. So geothermal is a much safer bet?

A. From a risk perspective, it's much more consistent. And even the term ‘much more' is too weak - it truly is a base-load asset from a risk perspective.

The risks for geothermal generation are actually to do with expiration, as you try to expand a geothermal fleet or maintain production. So it's much more like oil & gas from a depletion point of view than any of the other renewables.

Q. What's the typical lifetime for a geothermal asset?

A. Again, much like oil & gas properties, some last for 50 or 60 years, while others could last a year. Because you are drilling into a formation you get varying results.

We expect the Geysers [the area in Northern California where Calpine's geothermal assets are located] in its current form without any additional significant additional drilling programmes to last another 45 to 50 years. So our particular assets are very long-lived.

But some entities are beginning to develop geothermal projects without as much history behind the reservoir, so it's possible that you could get some short-lived geothermal projects from a reservoir perspective. And again, just like you can drill a well in an oil & gas field that has an extremely long life, you can drill some that last maybe five years or less. We don't have that issue, but others do.