THE TEXAS POWER MARKET: A POST-CRISIS Q&A - Natixis ...
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THE TEX AS POWER MARKET:
A POST-CRISIS Q&A
AUTHORS TEXAS MAY HAVE THAWED OUT AFTER
WINTER STORM URI, BUT THE REPERCUSSIONS
MATTHEW KELLY, CFA ARE FAR FROM OVER.
VP, Senior Credit Research Analyst
We’ve received a lot of questions about the storm’s
KEVIN BURK, CFA impact on power companies, the political and
VP, Senior Credit Research Analyst
regulatory fallout, and how Texas might prevent a
AUSTIN NASCA similar crisis from happening again.
Senior Credit Research Associate
We addressed some early concerns at the tail end
of the crisis, but in this Q&A we’ll follow up on key
questions and share what we’ve learned since then.
RESEARCH &
PERSPECTIVES
1 APRIL 2021
Part 1. Direct Impact on Power Companies
Q: THERE ARE SEVERAL DIFFERENT PLAYERS IN THE TEXAS POWER
PIPELINE. WHICH ONES FARED BETTER DURING THE CRISIS? WHICH
ONES FARED WORSE? WERE THERE ANY SURPRISES?
The biggest surprise to us was the impact on gas distribution companies (LDCs).
These fully regulated utilities typically purchase gas at market price and pass
the costs entirely onto customers. They were widely expected to emerge from
the crisis unscathed. However, because gas costs skyrocketed during the crisis
(see exhibit), regulators did not allow the LDCs to pass those extraordinary costs
onto customers. Instead, regulators allowed the LDCs to defer these costs into
“regulatory assets,” which will be placed on the balance sheet. The utilities can
eventually recover regulatory assets through a fixed cost on customer bills, but
the process is likely to span multiple years. In the meantime, LDCs must cover
near-term costs (February’s costs averaged ~1.5x the typical cost in a given yeari),
which have largely been financed through debt issuance. This has placed sizeable
pressure on credit metrics for the LDCs impacted by the storm.
30
DAILY GAS PRICES -
HENRY HUB ($/MMBTU)
25
Sources: S&P Global
Market Intelligence,
as of 1 March 2021.
20
15
10
5
0
2/8/2021
2/9/2021
2/10/2021
2/11/2021
2/12/2021
2/16/2021
2/17/2021
2/18/2021
2/19/2021
2/22/2021
2/23/2021
2/24/2021
1 APRIL 2021 2
We were also surprised at the widespread underperformance of integrated power producers (IPPs), which
have the ability to procure power in the open market or generate their own power supply. We initially
thought that IPPs with a long generation position (i.e., enough company-owned generation assets to meet
load obligations) would outperform those with a short generation position (i.e., those that must supplement
owned generation to meet load obligations). As it turns out, relative outperformance among IPPs wasn’t
determined by a company’s generation position. Instead, three other factors largely drove outperformance:
1. Preparedness for the storm. Generators that brought power plants typically reserved for
the summer back online and those that were able to procure power in advance of the storm
generally performed better.
2. Ability to access fuel (from onsite reserves or suppliers) to keep plants running.
3. The location of a generator’s retail load relative to load shedding (temporary orders to curtail
electricity transmission and distribution). The Electric Reliability Council of Texas (ERCOT)
imposed load shedding throughout the state to help balance the power grid when the crisis
caused a power shortage coupled with surging demand. IPPs that had overweight retail loads
in areas impacted by blackouts tended to outperform as they did not have to purchase power
at elevated prices to service their load.
Yieldcos (renewable energy operators) were also negatively impacted. Many of the wind-generation assets in
the region temporarily shut down in the frigid temperatures, and yieldcos generally incurred increased costs
to get these assets back up and running—most within 24 hours. Additionally, these companies experienced
a modest cashflow impact due to lost earnings and the cost of delivering on contracts at elevated market
rates during the crisis.
Electric transmission and distribution (T&D) utilities, which own and operate the lines that distribute
electricity to customers, were the only sub-sector in the ERCOT market to emerge from the crisis relatively
unscathed. These utilities are generally not responsible for purchasing electricity or gas in the spot market,
which largely insulated these companies from the wild price swings during the crisis. While some T&D
operators were forced to temporarily curtail electricity delivery during the winter storm (load shed), we
expect the ultimate financial impact to be minimal.
1 APRIL 2021 3
Q: AS CREDIT ANALYSTS, DID THE CRISIS CHANGE HOW YOU THINK ABOUT THE ERCOT POWER MARKET? We once considered ERCOT to be the strongest power market in the United States due to stable population growth, relatively attractive energy margins and historically low reserve margins. The fact that every power generation company under our coverage incurred losses to different degrees during the crisis has made us reevaluate that thesis. It has also made us question if power generators in deregulated markets warrant an investment grade rating without material market redesign. This unprecedented operational incident has put a renewed focus on the risk management of renewable energy projects, specifically with respect to greater winterization measures and enhanced weather outage predictors. Power generation contract structure is another area of focus, as contracts can vary widely. Some require the fixed delivery of power generation, while others include power purchase take-or-pay provisions or hedging mechanisms. How the market will ultimately respond in the wake of this crisis is still unclear, though we expect a greater emphasis on operational reliability for those assets bound by the contractual physical delivery of power generation. Part 2. Political and Regulatory Influence Q: ERCOT IS RESPONSIBLE FOR MANAGING THE STATE’S ELECTRICITY FLOWS AND PAYMENTS. AS OF THIS WRITING, ERCOT IS $3.1 BILLION SHORT ON CUSTOMER PAYMENTS AFTER THE POWER CRISIS. HOW DID THAT HAPPEN AND WHAT HAPPENS NEXT? ERCOT, in addition to establishing wholesale power prices, acts as a clearing house for power generators and those entities buying power, which could be electric cooperatives or retail electric providers (REPs). Per S&P,ii two electric cooperatives were responsible for approximately 75% of the $3.1 billion in due payments, one of which has filed for bankruptcy since the events of February. The remainder is due from various REPs. These entities had to procure power in the open market at scarcity pricing in order to service their customers during the crisis. Many are now under financial distress. We have heard that certain customers are disputing charges and have opted not to pay during the dispute (for if they do pay, and the charges are reversed, they may not get the money back). If we assume that ERCOT is unable to collect on any of the shortfall, then after 90 days the system operator would have the authority to spread the cost to all non-defaulting ERCOT members on a pro-rata basis (based on maximum MWh activity in the prior month). Importantly, current law only allows the socialization of these shortfalls up to $2.5 million/month. Therefore, it would likely take ERCOT decades to recover the full shortfall of $3.1 billion. This cap materially reduces credit risk for non-defaulting market participants. 1 APRIL 2021 4
Per the Wall Street Journal,iii ERCOT is in discussions with banks to temporarily cover the shortfall. As credit analysts, we are keeping a close eye on whether laws are imposed to lift the monthly cap (in order to accelerate payments to ERCOT). Such laws could have negative credit implications for power companies as well as social considerations given that end-users’ rates could materially increase. Q: ERCOT IS UNDER PRESSURE TO RETROACTIVELY CHANGE THE $9,000/MWH PRICE CAP FOR THE LAST 32 HOURS THE PRICE CAP WAS IN PLACE DURING THE POWER CRISIS. IS THAT LIKELY TO HAPPEN? We think retroactive repricing is unlikely at this point, given the lack of support in the Texas House. This issue was first raised by the Public Utility Commission of Texas’ (PUCT’s) independent market monitor (IMM). The IMM claims that pricing was held at $9,000 /MWh for 32 hours longer than it should have been. It states that pricing during this period should have been closer to $1,200/MWh. The IMM also claims the incorrect price cost consumers $3.2 billion. The former ERCOT President (who has since been fired) and the former PUCT Chair (who has since resigned) both claim the $9,000/MWh price was not an error, and was imposed to keep industrial load offline. The Lieutenant Governor of Texas has sided with the IMM and has called the pricing during this period an error. The governor has indicated a decision on repricing should be left to the courts. As of this writing, ERCOT does not have legal authority to adjust pricing without legislative action. On March 15, the Texas Senate passed a bill giving ERCOT the authority to adjust pricing. However, the speaker of the Texas House opposes the bill. Therefore, we think it is unlikely this bill (SB2142) becomes law. This could ultimately end up at the state Supreme Court. Even if ERCOT were to obtain the legal right to change prices, it currently has no commissioners (all three commissioners have resigned since the storm in February). Without any voting members, nothing can be approved. We expect the governor to nominate new commissioners in the coming days. Q: WHICH COMPANIES MIGHT BENEFIT FROM REPRICING? WHICH MIGHT LOSE? Power generators that had to procure power in the open market during that 32-hour window would likely benefit from repricing, whereas those that did not could be negatively impacted. Several power generators have indicated that they view repricing as a bad precedent for changing the rules of the game if the outcome is not what politicians expected. Before the former Chair of the PUCT resigned on March 16, he warned that retroactively changing prices could have unintended consequences given the financial and physical hedges in place at the time. Retroactively changing pricing could result in a net-sum game. We’ve heard similar comments from the power generators. 1 APRIL 2021 5
Part 3. Prevention
Q: WOULD TEXAS CONSIDER REGULATING ITS POWER INDUSTRY?
At this time, we have not heard any discussion among politicians, power suppliers or consumers
advocating for a regulated market. Despite the power grid’s shortcomings, we expect commercial and
industrial consumers to remain supportive of a deregulated market. A deregulated market allows consumers
(retail, industrial and commercial) to shop around, and since electricity is a commodity, retailers tend to
compete on price. Additionally, ERCOT is a competitive market, so power generators typically strive to
maximize profitability by maintaining an efficient operation, which helps keep power prices relatively low.
Alternatively, regulated utilities are typically incentivized to spend as much as possible as quickly as possible
to drive rate base and earnings growth, which tends to increase customer bills.
Q: WHAT PROPOSALS IS TEXAS CONSIDERING TO PREVENT THIS TYPE OF EVENT FROM OCCURRING IN
THE FUTURE?
On March 5, the power generators provided recommendations to law makers to prevent such an event from
occurring in the future. Here are the three consistent themes that surfaced:
1. Winterize the power supply chain, especially for the gas suppliers (this would require
legislative action).
2. Market redesign.
• Lower the price cap of $9,000/MWh.
• Improve reserve margins. This could potentially be accomplished through a capacity
market.iv However, one could argue that the February crisis would have occurred even
if ERCOT had had higher reserves at the time.
3. Communication improvements between gas suppliers, generators, utilities and customers.
Other recommendations included:
• Force Majeur limitations (limits gas suppliers from getting out of supply obligations)
• Energy storage incentives
• Change pricing to incentivize generation assets to stay online during the winter when power demand
is typically lower
1 APRIL 2021 6We remain cautious on broad market reform in Texas in 2021. The five-month
Texas legislative session runs through May 31. Given the tight legislative window,
lawmakers typically already have a full agenda heading into the session. We think
laws related to winterization of the power supply chain are likely to get approved
along with communication enhancements. However, we see minimal chance
of major market redesign taking place in 2021. Proposals related to capacity,
resource adequacy markets or price formula changes are likely to be studied in
the interim session and may be introduced in the 2022 legislative session.
Q: ARE THERE IMPLICATIONS FOR TEXAS’ SHIFT TOWARD DECARBONIZATION?
The shortcomings exposed in the ERCOT market could indicate the potential for
“ increased reliance on carbon-intensive base load generation. Volatility in the
ERCOT market may also create a near-term hurdle for renewable developers in
We believe this event the state to secure financing. If anything, we believe this event highlights a need to
highlights a need to better pair battery storage with renewable energy sources to support enhanced
better pair battery grid reliability. Government support and technological innovation is likely required
storage with renewable
to accelerate utility-scale battery adoption and help advance the proliferation of
energy sources to
renewable power generation.
support enhanced grid
reliability. The power crisis has also introduced the question of whether Texas should keep
retiring coal at its current aggressive clip. Coal fared relatively well during the
crisis and is a form of baseload power that could be kept as a reserve if other
power plants fail.
Q: ARE TEXAS’ MARKET REFORM PROPOSALS POSITIVE, NEGATIVE OR
NEUTRAL FOR POWER GENERATORS AND CUSTOMERS?
At a high level, we expect market reform to largely focus on improving grid
interconnectedness and reliability. This could include new weatherization
standards, better emergency preparedness, enhanced coordination among
electric and gas utilities and a greater reliance on energy storage. In our view, any
changes that could help prevent a catastrophic event from occurring again should
benefit market participants over the long term.
GENERATORS
The near-term implications for power generators are unknown. For instance,
we still don’t know who will be required to pay for incremental weatherization of
1 APRIL 2021 7power assets—will it be end users, the generators themselves, or a combination?
These discussions are still in the early innings and specific details have yet to be
worked out. Under Senate Joint Resolution 62, Texas would create a fund to help
support projects that support grid reliability, which could help lessen the financial
burden of weatherization costs on the IPPs.
We believe that increasing power reserves in the state, all else equal, would likely
depress wholesale power prices and negatively impact credit. On the other hand,
if increased reserves are driven by a mechanism like a capacity market, then we
would view the change as more neutral to positive.
Another key proposal, lowering the administrative price cap of $9,000/MWh is
likely more neutral for generators. Lowering the price cap would reduce the
“ potential to capture upside, but it would also reduce large swings in associated
cash flow.
There appears to be CUSTOMERS
bipartisan support
for securitization of We believe customers are likely to see higher rates from market reform. In other
unexpected costs power markets that have implemented a capacity market (such as ISO-New
incurred by electric and England or Pennsylvania-New Jersey- Maryland Interconnect), reliability tends
gas utilities. We believe
to be less of a concern. However, customers typically pay higher prices for higher
securitization can be
reserves that provide a source of backup power.
credit accretive as it can
allow for immediate Finally, there appears to be bipartisan support for securitization of unexpected
recovery of unusual costs incurred by electric and gas utilities. We believe securitization can be credit
costs incurred.
accretive as it can allow for immediate recovery of unusual costs incurred. We
view securitization as generally positive for consumers—securitization bonds are
usually a cheap financing mechanism, thereby helping to minimize the impact on
consumer wallets.
Conclusion: Some Answers, but Questions Linger
The situation in Texas is still evolving. We’ve learned a lot in the last month, but we
still don’t know if there will be retroactive pricing changes or what will be done to
prevent a similar event from occurring in the future. Lastly, until we know more,
we cannot truly know whether these changes will be good, bad or neutral for
power sector issuers.
1 APRIL 2021 8One Financial Center Boston, MA 02111 www.loomissayles.com
AUTHORS Endnotes
i
Source: Bank of America Research
Source: S&P, “Winter storm in Texas will continue to be felt in Utilities’ credit profiles”
ii
published 15 March 2021.
Source: Wall Street Journal, “Texas Grid Operator Discussed Financing With Goldman as
iii
Energy Buyers Balk at Payment Shortfall” published 12 March 2021.
iv
Capacity markets can create cash incentives for generation asset owners to keep their plants
available for reliability purposes.
MATTHEW KELLY, CFA
VP, Senior Credit Disclosure
Research Analyst
This paper is provided for informational purposes only and should not be construed as
investment advice. Opinions or forecasts contained herein reflect the subjective judgments and
assumptions of the authors only and do not necessarily reflect the views of Loomis, Sayles &
Company, L.P. Other industry analysts and investment personnel may have different views
and opinions. Investment recommendations may be inconsistent with these opinions. There is
no assurance that developments will transpire as forecasted, and actual results will be different.
The information is subject to change at any time without notice.
Market conditions are extremely fluid and change frequently
KEVIN BURK, CFA Commodities, interest and derivative trading involves substantial risk of loss.
VP, Senior Credit Past performance is no guarantee of, and not necessarily indicative of, future results.
Research Analyst
This is not an offer of, or a solicitation of an offer for, any investment strategy or product.
Any investment that has the possibility for profits also has the possibility of losses
LS Loomis | Sayles is a trademark of Loomis, Sayles & Company, L.P. registered in the US
Patent and Trademark Office.
AUSTIN NASCA
Senior Credit
Research Associate
LSWP191-0421
Exp. 04/30/22
3518938.1.1
MALR027012
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