- The unregulated power sector was thus far relatively insulated from the severe economic shock ensuing from the pandemic-driven lockdowns.
- We expect more pronounced impacts on demand in the second quarter as user industries ramp down utilizations or idle capacities.
- We think weather-adjusted load is down across the U.S. by about 7%-15%, and there is significant variability across regions and segments.
- Many single-asset (and portfolio) project financings were hindered by milder winter weather in 2019-2020; the impact of COVID-19 demand declines is adding pressure and has started to result in negative rating actions.
- The sharp shock represents a stress test of the retail-wholesale IPP business model. Perversely, a muted impact could prove the efficacy of the integrated model. We intend to publish more on this subject in an upcoming commentary.
The "severe" and "acute" in severe acute respiratory syndrome (SARS)--of which the novel coronavirus is a particularly infectious strain (SARS-CoV-2)--is not a tautology. "Severe" refers to the disease's widespread invasion of the lungs, deep into the bronchioles. "Acute" refers to the abruptness of its onset and the duration for which it lasts. It is typically of short duration, but it is rapidly progressive, requiring urgent care. It is the opposite of chronic.
The impact of the pandemic on the economy is similar. Although we knew the impact was widespread, our economists now think the GDP decline will be deeper in the second quarter, and forecast a 35% decline, resulting in an annualized 5.2% decline in GDP in 2020 compared with 2019. Right now it appears as if we are flying blind. However, with the curve flattening, there is optimism that the duration of the lockdown may not be as long as we expected in March. Yet, full recovery could take several months and will likely be nonlinear.
With such an unprecedented shock to the economy, investors have asked for our views on the unregulated power markets. We provide our assessment in a two-part commentary.
In this first part of the commentary, we present details on regional power demand drop, the effect on spark spreads, and the ensuing impact on single-asset/portfolio project-financed transactions. In the second, we will identify areas of credit risks for larger independent power producers (IPPs) and our views on the credit quality of rated IPPs.
Broadly, we think smaller project-financed transactions are now increasingly compromised given COVID-19's brutal impact, which we expect will last at least into the third quarter. This is on top of milder winters (particularly in 2019) that have long stopped generating power prices required to support many financings. We think COVID-19 could prove to be the last straw on the proverbial camel's back for a few project finance credits. On the other hand, we think the impact on IPPs is relatively muted up to this point, especially compared to sectors such as oil and gas. Yet, we expect some credit weakening as IPPs experience the full onslaught of a slowing commercial and industrial (C&I) segment in the second quarter.
Power Demand In The U.S.
While the decline in U.S. power demand is still showing signs of weakening, we can glean some information from overseas markets, which are showing signs of stabilization. In Europe, the power market showed an initial resilience, even rising in some countries, as customers stocked up and prepared for the lockdown. It was only after the first week of the lockdown that the declines started manifesting. So far--and unsurprisingly--the effect on electricity demand has been most significant in Italy and Spain; power demand in these countries is about 28 gigawatts (GW) and 24 GW, respectively, at this time of year, and it appears to have declined about 20%-22% compared with the five-year averages (2015-2019). Power demand in France and Germany, both markets at about 50 GW, is lower by 15% and 12%, respectively, over five-year norms. The U.K. is showing some rapid declines as it contends with increasing infections.
In the U.S., it has been a month since cities and states began instituting stay-at-home and shelter-in-place directives to reduce the spread of COVID-19. U.S. electricity generation, a proxy for economic growth, also shows increasing impairment on a nationwide basis. On a weather-adjusted basis, loads in the contiguous 48 states over the past two weeks have been trending about 8% below what would be expected at this time of year. Statistically, it is outside of the five-year range. About 1% of this decline was seen before the pandemic lockdowns in the weather-adjusted load through February. So, it appears that about 7% of the declines are COVID-related.
Now, as economic activity in the C&I sector begins to fall significantly, we are seeing an increasing impact of the slowdown on power sales. While power demand showed an initial resiliency immediately following the lockdowns (as states prepared for the siege) almost all power markets began to retreat about a week following the lockdowns.
There are significant regional disparities. Demand in New York City has eroded as much as 17% year-over-year and PJM Interconnection about 10%, but demand in Electric Reliability Council of Texas (ERCOT) increased over last year due to unseasonably warm weather.
Demand Declining In Regional Markets But To Varying Degrees: A month into the lockdown, some consistent patterns of the impact of the shutdown on electricity demand are emerging. Broadly, U.S. grid operators are reporting not only demand declines but also shifts in load shapes. Our affiliate, S&P Global Platts, reports the following discernible patterns:
- Activity downturn in the commercial sector is outweighing gains in residential electricity loads.
- Hourly load (and price) profiles have shifted significantly in areas affected by stay-at-home rules–-morning peaks are delayed while daytime loads have declined much more than late evening/overnight loads.
Spark spreads initially held up as natural gas fell faster than power prices, but have since declined. On-peak spark spreads are still holding at about $10-$12/megawatt hours (MWh) in PJM and New England even as the front end of the curve (through June 2020) is significantly impaired at levels of $6-$8/MWh.
PJM Interconnection: The proportion of power consumption in the PJM is roughly 37% residential and commercial, and about 25% industrial. We think this split is an important consideration across all markets as there will be a greater impact on commercial sales given numerous establishments are outright closed and potentially delayed in re-opening due to the pandemic. While data is still streaming in and changes weekly, we think this load is down 10%-15% across the U.S. In fact, we perceive that, while material, the extent of the current downturn is likely less on industrial load than in 2008-2009, but likely more of a commercial impact in our view. By contrast, the residential offset, also seen in the last recession, is potentially all the more potent today. Charts 1 and 2 below compare PJM's 2020 load with the corresponding period in 2019. While it is unadjusted for weather, load is about 10% down year-over-year. In the charts, we see load clearly starts to break away from 2019 by mid-March.
PJM has guided two likely trends in load projections:
- Reduction of commercial load will likely cause an offsetting increase in residential load because of an increase in lighting, laptops, heating/air conditioning, etc.
- Industrial will not shift to residential, but also may not be impacted as significantly because much of the demand is state-dependent.
Also, PJM's highest electricity use is coming in a little later in the morning, and the grid operator expects electricity use to drop to some degree if schools and businesses stay shuttered because of the coronavirus. Electricity use will more closely resemble weekend days. The grid operator also noted that although demand appeared much lower it was also weather-related.
The impact of the load destruction on spark spread has been swift (Chart 3). As expected, even peak spark spreads have been crushed in the prompt months. The problem for PJM assets is that with natural gas declining and low volatility, it is not possible for even efficient gas-fired units to earn higher margins from relative fuel efficiencies, especially in regions where coal-fired generation doesn't provide a price floor.
New England Independent System Operator (ISO) ISO New England has said that it has witnessed a similar decline in system demand of approximately 5% compared to what would normally be expected under normal weather conditions in the region. Along with demand reductions, the grid operator also noted changes in demand across the region that appear to be mimicking load patterns that resemble those of snow days, when schools are closed. Load in the past few days has exhibited slower-than-normal ramp of usage in the morning, and increased energy use in the afternoon.
We note that the ISO load has anyway been declining, especially in the industrial segment and the ISO anticipates behind-the-meter solar generation and energy efficiency will grow by 8.6% and 8.1% annually, contributing to lower secular load demand throughout the region.
Chart 4 below presents a similar decline, albeit lesser, decline in load relative to PJM. The chart shows that load in 2020 across New England has been lagging 2019 since Jan, also because of the weather.
Given that the New England pool is a smaller market than PJM and is already oversupplied, even a smaller level of demand loss has caused prompt sparks to drop further. On-peak spark spreads in New England (Chart 5) are lower than in PJM.
New York ISO The greater NYISO is observing shifts in energy-usage patterns throughout the state compared to prior weeks and the zone is down about 9% compared to 2019 (Chart 6). However, power declines vary during the year. New York Control Area-wide power consumption reductions compared to typical demand levels ranged from 1% during the hour after midnight to 12% during 7-8 a.m.
This is amplified in New York City, where electricity demand has been particularly weak, as one might expect. By mid-April, NYC loads have been 17% lower than what would have been expected without the coronavirus pandemic with similar weather. While overnight loads are down slightly, the impact of reduced commercial sector activity increases sharply at 5-8 a.m., with a peak reduction between 10-11 a.m. Impacts remain relatively stable through 6 p.m. and then reduce for the balance of the day.
As a consequence, NYISO Zone J (New York City) on-peak real-time locational marginal prices have trended down over the past 30 days, currently averaging near $15/MWh, down $10 from month-ago levels. NYISO Zone J on-peak July-August is currently near $30/MWh, down $5 from levels at the start of the year and less than half of where the 2019 prices traded this time last year. Prompt month on-peak sparks are as low as $4/MWh.
ERCOT Texas is one region that bucked the trend and showed higher loads compared to 2019, largely due to unseasonably warm weather (Chart 7). Peak power demand in ERCOT set a record for the month of April at 55.2 GW when temperatures soared to 97F recently. However, adjusted for weather, ERCOT has also found that the load effects of the coronavirus pandemic have been adverse with overall energy usage falling about 2%, and the morning ramp up in power demand has been down between 6% and 10%.
ERCOT's market is more exposed to exploration and production (E&P), chemical, and refinery demand. Refinery utilization rates are 80% today, and E&P activity went from 20% growth to decline in a matter of weeks. However, declining load will also push out renewables and may not impair the forward curve in the long run. We think ERCOT summer 2020 (Chart 8) could liquidate significantly weaker-–at levels of $60/MWh--than the forwards predict due to a slower recovery for fears of a resurfacing of the virus.
What This Means For Credit Quality
While coal-fired generation is an obvious victim of lower gas prices and receding lender interest because of sustainability mandates, we find some gas-fired assets leveraged to a higher gas-price environment, and higher weather-driven power price volatility, in distress as well. In the wake of COVID-19 there will be further underperformance and we expect many generators to have difficulty refinancing, particularly those with maturities in 2020 or 2021. The table below presents some of the recent actions by us in the power space. We expect more to follow through 2020.
|Rating Actions In 2020|
|Rating Action Date||Current Rating||Prior Rating||Rationale|
Panda Patriot LLC
|1/30/2020||CCC||B-||Lowered due to refinancing risk at maturity in December 2020. Ratings initially lowered to B- in 2019 after perceived risk of breaching financial covenant test after a revision to our base-case projection, including a reduction in spark spreads to below $10 per MW hour, reflecting the lower on- and off-peak locational marginal prices we have observed in multiple major power trading hubs in the PJM Interconnection.|
Panda Liberty LLC
|1/30/2020||CCC||B-||Ratings lowered because of refinancing risks when the term loan matures in August 2020. Liberty has been underperforming below our expectations over the past 18 months with multiple financial covenant breach, including the recent one in Q4 2019 that was addressed with an equity cure. The weak performance to the combined effect of the payment structure in one of the two HRCOs, extension of a planned outage beyond the initial estimated completion date, and hub-to-node basis risk.|
Chief Power Finance LLC
|2/14/2020||CCC||CCC+||Potentially faces a situation similar to Longview. This PJM coal-fired asset faces an upcoming maturity in Dec. 2020. Exposed to market power prices, which have been low for a prolonged period because of cheap natural gas and, more recently, a mild winter.|
Sandy Creek Energy Associates L.P.
|2/14/2020||CCC||B-||The plant has not realized material merchant margin in the past seven years and still has about $900 million in outstanding debt, which matures in November 2020 (including the $100 million tax-exempt tranche).|
Longview Power LLC
Kestrel Acquisition LLC
|3/5/2020||B+||BB-||Ratings lowered after poor financial performance in 2019 that prevented the project from sweeping any cash. Additionally, we lowered our expectations for future cash flows based on the PJM power price forward curve, prior to the COVID-19-induced incremental pressures.|
Longview Power LLC
Longview Power LLC
|4/14/2020||D||CC||Had a fully drawn revolver due April 2020 and filed for bankruptcy protection.|
Revere Power LLC
|4/15/2020||B+||BB-||We expect weak spark spreads, a failure to sweep any cash against debt in 2019, and to date, and weakened NE-ISO capacity payments in future years will leave Revere with materially more debt outstanding.|
Lightstone Generation LLC
|4/17/2020||B+||BB-||Despite mainatining debt sweep targets as expected in 2017 and 2018, Lightstone swept only $41 million of excess cash in 2019 due to a significantly milder winter. It is unlikely to sweep material cash in 2020, resulting in a major lag in outstanding debt balances compared with expectations.|
Hummel Station LLC
|4/21/2020||CCC+||B||Due to transmission outages and a mild 2019 winter, Hummel has persistently failed to sweep cash. As a result, the debt balance has become unsustainable and S&P has concerns that Hummel will breach its 1.15x covenant (although we expect equity cures to occur).|
Panda Stonewall LLC
|B-||BB-||Although the project had performed in line with our expectations through 2019, significant demand destruction due to COVID-19 has led to a sharp deterioration in cash flow such that we expect Stonewall could breach its 1.15x covenant in 2020. Although the project's capacity to repay debt is diminished in the current market environment, we do not view the capital structure as unsustainable.|
|HRCOs--Heat rate call options.|
Term loan (TL) B financings were originally introduced under a "smoothing assumption." While it is difficult for merchant power projects to generate predictable cash flow each year to service amortizing debt, there will be some years of weather-driven overperformance during the tenor of the debt. The financing assumed that in such years of overperformance, mandatory cash flow sweeps will smooth out repayment of debt over the seven-year term. We think merchant TL B deals were underwritten and financed using forecasts that assumed weather normal conditions. Over the past decade, these merchant transactions have performed as intended--substituting default risk for refinancing risk. Even as an asset underperformed relative to expected cash flow sweeps, a benign financing environment allowed refinancing.
Now, with weather not cooperating in several past winters (or summers in ERCOT), many PF assets have performed below base cases they showed lenders before COVID-19, and have limited, to no room, to begin 2020. We expect many single-asset deals will experience challenges through 2020. This will be particularly true of transactions that have not fully hedged third quarter of 2020 in the hope of better pricing discovery. Even when managed well, it is difficult to hedge due to collateral constraints and operational risks (hedging a high % of a single asset). With the unseasonably warm 2019-2020 winter and the sharply weak second quarter, many transactions will be at risk of breaching their financial covenants on a 12-month rolling basis.
It is evident that having a big balance sheet, operational diversity, and retail operations will be a difference during this crisis. While on the subject of larger IPPs, we think this period of a sharp shock represents a stress test of the retail-wholesale IPP business model. Ironically, a muted impact could prove the efficacy of the integrated business model. We expect to see the largest impact on companies with greater exposure to the C&I sector, and/or those that have volumetric risks in their physical or financial hedges, or simply a lack of meaningful hedging in 2020-2021, and we intend to publish a separate commentary on that subject.
This report does not constitute a rating action.
|Primary Credit Analysts:||Aneesh Prabhu, CFA, FRM, New York (1) 212-438-1285;|
|Kimberly E Yarborough, New York (1) 212-438-1089;|
|Secondary Contacts:||Kyle Thumar, New York + 1 (212) 438 1446;|
|Zachary S Fiore, New York;|
|Research Assistant:||Sachi A Sarvaiya, Mumbai|
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