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NRG Energy Execs "Baffled" by Lack of REP Defaults from August Heat

October 4, 2011

NRG Energy executives are "baffled" by the lack of fallout from the extreme heat and wholesale pricing in the ERCOT market on retail electric providers, NRG CEO David Crane said during an investor call to revise guidance downward due to the difficult August.

"[I]t was a very, very difficult month to be a retailer in Texas," Crane said.

However, there have not yet been any REP defaults to ERCOT or POLR transitions as a result of August. Additionally, as opposed to the spring and summer of 2008, there have not been multiple fire- sales or other "quiet" exits from the market to avoid a POLR drop.

"To be frank we have been surprised that we haven't seen more visible fallout from that in terms of other participants in the market," Crane said. Though REPs which exit the market can do so quietly if no default is involved, Crane confirmed that NRG has seen "very little" fallout from the August whole- sale pricing to date.

"We don't have a good explanation for that," Crane added, agreeing with an analyst that more fallout was expected, particularly for small REPs and those not owning generation.

Given that more than 30 days have passed since the end of August (and 45 days since the middle of the month), the lack of fallout is not simply due to a lag in the ERCOT settlement process, Crane added.

Speaking with Matters on the subject, Chad Price, Co-Chair of AEG Affiliated Energy Group's M&A Practice, offered two explanations for why there has been very little fallout in the retail market to date.

First, Price noted that the February rotating outages and pricing event may have served as a "wake-up call" to REPs on risk management, and REPs thus entered the summer more prepared. Additionally, REPs may have had in place more conservative supply and risk strategies resulting from the transition to nodal.

Second, Price said that the trend toward lockbox agreements for REPs to meet heightened PUCT credit requirements likely imposed discipline on REPs. First, Price reported that lockbox providers often try to sell additional insurance and risk protection to their REP clients, some of which may have taken such offers in a fortuitous decision. More broadly, lockbox providers also only transact with soundly managed companies, and can have very defined parameters in terms of REP operations, including risk management and hedging policies (and well as customer product offerings, bad debt, etc.). This means that any REP relying on a lockbox is likely in a position to weather August without default, although, like NRG, such REPs likely took a hit (but a sustainable hit) in earnings.

Matters itself would also note that the lockbox providers have an incentive to keep their REP clients in business, even if, due to a "one-time" event like the August heat, REPs fall out of compliance with their covenants or otherwise default under their agreement and require the lockbox provider to cover ERCOT credit calls on their behalf.

Although there have been cases of lockbox providers stepping in to take over a retail book, most lock- box providers have little interest in being retail suppliers themselves, especially for a disparate number of very small books, which are those most likely to be stressed under the August conditions. Matters suspects that lockbox providers are more inclined to work-out any default or similar event with their REP clients if such default results from a one-time event (rather than systemic business operations at the retailer), in order to maintain a future earnings stream for the provider from providing credit and other wholesale services to the REP (QSE, supply, etc.).

Indeed, rather than finding a REP in default, lockbox providers may find it more beneficial cover the REP's position and use this as leverage to require the REP to commit to a longer-term lockbox agree- ment, or agree to purchase additional services, in exchange for the lockbox provider not calling an event of default. The lockbox provider may look to recoup any monies still owed by the REP under a long-term agreement, as opposed to the hard deadlines applicable if the REP itself were exposed to posting credit with ERCOT.

Turning back to NRG, the company said that its retail and wholesale results were hurt in August as it hedged 100% of its peaking gas fleet in July in response to high forward heat rates for August. How- ever, this left no assets to cover the retail book during super peaks, and also left NRG exposed to buying expensive replacement power for any plant outages, which increased in late August as the gas assets were cycled more often.

NRG said that, given the forecast tight conditions in ERCOT over the next few years, it will not fully hedge its peaking gas assets and will retain an amount to cover the risk of outages, or, if not needed for that purpose or for the retail book, to take advantage of day-ahead and real-time pricing.

NRG did not provide a specific amount of capacity it would keep unhedged, but said that the amount would vary based on conditions.

Additionally, NRG reported that it will purchase additional insurance for its retail books to protect against exposure to super peaks.

NRG expects other REPs to pursue similar insurance, and said that it expects retail to pricing to rise as a result.

In response to an analyst's question, executives conceded that retailers may either choose to accept lower margins (rather than pass on the insurance premiums to customers), or accept earnings volatility and not purchase insurance, both of which would not result in higher retail pricing by competitors.

NRG initially said that it would reflect the costs of insurance in its retail rates, but then said more broadly it expects other retailers to take such action without committing to any specific pricing action for its own retail businesses going forward.

As a result of August, NRG lowered its forecast of adjusted EBITDA for 2011 to a range of $1.775 billion to $1.85 billion, down from the August 4 guidance of $1.9 billion to $2.0 billion.

At Reliant, adjusted EBITDA guidance is now $550-$575 million versus the earlier $610-$660 million. At Green Mountain, the adjusted EBITDA guidance is now $60-$70 million versus the earlier $70-$80 million.


 

 

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