The depth of the economic stop and the duration of the recovery matter.  Industries that use significant amounts of power have experienced substantial demand destruction as a result of the unprecedented global lockdown. According to S&P Platts Analytics forecasts, U.S. shale oil output may drop by 1.8 million barrels per day (mbpd) by the end of 2021 under their most likely case, down from its year-end 2019 level of 8.3 mbpd, or about 20%. However, because the current global oversupply is causing record low oil prices, curtailment of U.S. production of up to 3 mbpd (36% decline) may be needed in the next three months, with most of it coming from the shale.

As it relates to power load, our concern is that declining loads could have a secular slant (i.e., some segments do not rebound and are permanently impaired) that could hurt power prices over the long run, just as the last recession lowered load 4%-5% for a sustained period. Texas, for instance, is more exposed to exploration and production (E&P), chemical, and refining demand. Current refining utilization rates are about 70% as product has nowhere to flow, and E&P activity went from 20% growth to a decline in a matter of weeks. We are now seeing increasing loss of cogeneration steam load as plastics and chemicals load declines. There are increasing oil and gas shut-ins in West Texas across the Permian region, and based on recent liquefied natural gas (LNG) arbitrage economics, we expect some liquefaction facilities (perhaps Freeport) to not run.

We expect to see lumpier changes for industrial load since economic activity slowed down dramatically in early April. As more manufacturing facilities shut down, the impact of industrial demand for natural gas was likely larger than during the financial crisis, in our view. Market experts we spoke to estimate the impact on demand at about 2.0-2.5 billion cubic feet (Bcf)/day (10% of weather-normal usage). Similarly, impact to gas demand for power burn also appears to be larger than observed during the financial crisis at about 1.75-2.0 Bcf/d in April-May 2020 (7.5% of weather-normal use).

While we now have better visibility into the severity of the demand destruction that accelerated from late March into April, what matters more is the duration of the lockdowns, and the form and shape of the economic recovery. Key industrial indicators suggest economic activity is still visibly impaired but also showing signs of recovering (power decline has troughed and reversing direction; gasoline usage has improved to 64% of average annual demand for this time of year compared to 55% in early April). Table 1 presents S&P Global Ratings' economic outlook. We are still assuming a reasonably strong recovery for the third quarter that could well happen as 29 more states follow Georgia, Texas, and Florida in relaxing the lockdowns. By May 10, 2020, 42 states will have suspended their restrictions. We expect industrial activity will climb back in the third quarter and recover significantly through December, while power demand takes a faster trajectory and recovers through September, except in pockets of slower growth such as the commercial and industrial (C&I) segment. This is an important assumption for our views on the sector.

Table 1

Credit Risks

Independent power producers (IPPs) typically have wholesale power and retail power businesses. Wholesale power entails generating power from a variety of fuels and selling that power into forward or prompt (real-time, or short-term) financial or physical markets. Although a power generator can hedge its production by selling the expected economic generation in the forward markets, the hedge is for relatively short periods, perhaps on a ratable basis over the next three years. Although retail power customers are acquired competitively, they provide a home for the wholesale power business of the company. When well-matched, the retail business provides a native hedge for the wholesale business and the company becomes a better-integrated power platform.

Companies that have developed large-scale retail businesses typically source a substantial proportion of their load-supply requirement from the power assets of the wholesale business but are not obligated to do so. The proportion of wholesale generation of a company directed to its retail business depends on alternate sources (and costs) of power and the load profile of the retail business, among other factors. Also, companies with large retail businesses show expected margins on forward sale of generation in the wholesale book. Any margins subsequently optimized by the retail business through dynamic hedging is reflected in the retail book. However, companies that have smaller retail businesses tend to consolidate the businesses and present aggregate margins.

It is noteworthy that the biggest declines in economic activity are in the second quarter, which tends to be a seasonally weak quarter for IPPs due to milder temperatures. These companies generate a vast majority of their wholesale power EBITDA and free cash flow during the summer, when our economists expect economic activity to start recovering. Still, with meaningful demand destruction in the wake of the pandemic-driven lockdowns, we identify the following risks for IPPs:

• Market exposure of energy margins; less scarcity price formation/instances in the Electric Reliability Council of Texas (ERCOT) and potential for lower capacity prices in the PJM Interconnection.
• Load shape risks in the wholesale power generation business.
• Retail power business exposure to volumetric risks, especially in the C&I segment.
• Bad debts and incremental working capital.

Market Exposure

IPPs typically hedge their economic generation substantially in the prompt year, and most companies entered 2020 with 90% of generation hedged before the crisis deepened, insulating them from the immediate impact of demand destruction. Although power price risk is mitigated this year, there could still be volumetric risks as load shapes shift as well as moderate. Also, the "margin at risk" from wholesale power business presents a larger risk for companies such as Exelon Generation Co. LLC (ExGen), Vistra Energy Corp, and Calpine Corp., which are materially long in generation capacity relative to their retail load, compared to companies such as NRG Energy Inc. ExGen, for instance, is significantly long generation in the Midwest and Mid-Atlantic, while Vistra and Calpine are long ERCOT.

Before the lockdowns, power prices took time to decline relative to natural gas prices, and some generators were able to capture value from lower gas (and coal) costs. So there were some opportunities to increase wholesale margins relative to the budgeted plan for 2020. Similarly, higher congestion in west Texas drove strong pricing for the Permian basin power plants throughout the first quarter. We expect companies reporting first-quarter earnings this week to not show significant impact from the lockdowns even as they could show weakness from the mild winter.

However, the favorability will be dampened by generators taking a price reserve against some of the remaining open positions in 2020 due to potential continuation of lower demand into the summer months, limiting scarcity events and resulting summer prices versus plan. For example, Vistra typically carries about 1 gigawatt (GW) of operational length as a backstop against potential operational outages during peak summer. That generation will be likely get marked below the curve as we expect ERCOT summer power prices to liquidate well below what the current forward curves suggest. In fact, since the crisis accelerated, ERCOT summer 2020 prices have fallen about $40/megawatt-hour (MWh) and could further weaken to liquidate in the $70s from current levels, which average $100/MWh.

Similarly, given its much larger wholesale power business (Table 2), Calpine's hedging of its wholesale power business bears watching. The company had hedged over 90% of its balance-of-year economic generation (about 85 terawatt-hours, or TWh) through firm swaps on exchanges and with high-grade counterparties. We estimate that only about 5% of the wholesale contracts have full requirements load shaping risks, of which 50% is to a cooperative that has a capacity payment in its contractual arrangement. We think some IPPs may also be looking to hedge their positions in California for the fourth quarter of 2020 as power prices have fallen in the West.

Table 2

Not only is merchant power a price-taking business, it is biased to the downside in a recession. This is because both fuel prices and market heat rates decline. Based on forward curves, and current hedges, there is the possibility of a 10%-15% decline in wholesale EBITDA of IPPs in 2021 in isolation, before hedging and mitigation. However, the IPPs have repeatedly shown their ability to hedge into the volatility, despite a backwardated forward curve. In fact, we think IPPs are likely hedging in ERCOT right now for 2021 because the forward curve is still structurally strong and holding up well. For example, in its first-quarter 2020 earnings call, Vistra indicated that it is about 57% hedged for 2021, noting that nearly 70% of its EBITDA comes from the ERCOT market. Yet, we see the ability to preserve 2021 cash flows as a material risk if there is a second wave, or should the actual path of the recovery be much slower than anticipated. We will wait for further visibility into the likely impact on 2021 cash flows before we consider outlook resolutions.

As a separate, yet related point, we should point out that with significant cuts to oil production, associated natural gas is also shut in. This could tighten balances into winter 2020/2021 and push natural gas prices up next year. An increase in gas prices could help power producers that have substantial coal-fired and nuclear generation like Talen Energy and ExGen.

Although demand will likely be lower in ERCOT next year than projected, backwardation in power prices also depends on actual renewable penetration. ERCOT's capacity, demand and reserve report currently estimates incremental additions to renewable capacity of 2.5 GW in 2020 and an additional 6.5 GW by year-end 2021. How much of this is actually built (a combination financing, tax equity, or supply-chain issues) is important. The declining load could push out renewables and not impair the forward curve in the long run. We could still see higher Texas and flattish PJM pricing that could offset declines in New England and New York.

Load Shape Risks In The Wholesale Power Business

Typically, sales into request-for-proposals and regional power auctions expose the generator to load shape risks, whereas firm swaps/future contracts are for blocks of power and do not have volumetric risk.

For companies that have exposure to auction markets, the exposure is typically to a combination of residential and C&I customers. For example, ExGen's about 50 TWh wholesale book principally serves full-requirements provider-of-last-resort for residential customers (who don't shop for power in competitive markets) and hence are less at risk of load erosion. Similarly, PSEG Power's economic generation of about 50 TWh-52 TWh has load hedges as well as fixed swaps and futures. From public disclosures made by the company in the past, we estimate that about 30% of PSEG Power's hedges are load-variable hedges. The company sells about 12 TWh-13 TWh into the New Jersey basic generation service auction and 4 TWh-5 TWh into similar default service constructs, and/or through its C&I retail book. Thus, its load hedges are predominately for the default service consisting of residential and small commercial loads, which is less sensitive in an economic downturn compared to large C&I and industrial load that has already migrated to retail providers.

Retail Exposure To Volumetric Risks

Due to a combination of the expansion of its retail power business, backwardated wholesale margins, and likely additional plant closures, we expect NRG's retail business to account for about 75% of the company's aggregate EBITDA by 2023, up from 50% now. Although the EBITDA shift is more dramatic for NRG, we see increasing proportions of retail EBITDAs for other IPPs too. For an EBITDA shift so dramatic, the success of the retail power business is extremely important to the IPP sector. As a result, we delve into this risk in some detail.

Apart from two years in which there was a decline (2011 and 2014), retail margins have held up well for IPPs over the past decade. Over the past three years, the IPPs have promoted their integrated business model as one more about managing the retail load-to-wholesale generation matching rather than the long commodity position. They contend that as natural gas prices have moderated and become less volatile, the merchant commodity risk is now manageable through a proportionately sized retail business because it moves counter-cyclical to the wholesale business. At low wholesale power prices, capital charges for the retail business decline. Although customer migration ensues, gross margins for retail volumes rise due to increasing headroom between locked-in retail prices and wholesale prices. Thus, although the generation business' profitability declines when prices are low, the retail business' profitability improves, and vice versa

S&P Global Ratings has been skeptical about the efficacy and efficiency of the retail offset. While the retail businesses have indeed performed well over the past decade, we do not have good visibility into how these business performed during the great financial crisis because the typical retail business was small at that time. We think a recession could impact both wholesale and retail volumes. In fact, we wanted a test of the resilience of the integrated business model in a recessionary environment. Perversely, this pandemic driven demand decimation is the stress test that could validate their claim. How well these companies are able to handle the volumetric risk would be a vindication of that model, in our view.

Nature Of Hedging

Compared to the 2008/2009 financial crisis, we now are seeing a greater impact on commercial sales given numerous establishments are outright closed. By contrast, the residential offset seen in the last recession is all the more potent today. As a result, we have focused more on companies with C&I as well as large commercial and industrial (LCI) exposure as well as the nature of hedging activities in these sectors.

Over the past weeks, we have waded much deeper into the nature of hedging that companies engage in and it is evident that all hedging is not equal. In particular, we are assessing what proportion of hedges have volume risks and list our salient conclusions below:

• Contracts in ERCOT are largely physical (buy multiples of gas and sell power), while in the northeast/Mid-Atlantic hedging is mostly financially settled.
• Contracts in the C&I and LCI segments tend to be block and settle, indexed and fixed-price products. The break-out is important as fixed-price products have volumetric risks.
• Residential contracts are fixed-price (from month-to-month to about 18 months) and therefore have variable volume risk, but residential has increased in all markets.
• Small C&I contracts are a mix of fixed-price products, variable load, and block and index products. C&I contracts in the Northeast and Midwest have a higher proportion of fixed-price products (90%-100%) than in ERCOT (65%).
• LCI contracts tend to be largely indexed and can also have swing bands; i.e., where a minimum volume floor is defined. Contracts with refineries, for example, are typically on swing bands. These contracts are similar to the downward tolerance threshold in LNG contracts.

C&I Demand

As we've noted, our focus remains on C&I demand recovery as it has been affected much more than industrial to this point. It is difficult to tell whether there will be further pressure on industrial demand, as it tends to be lumpy. Meanwhile, for residential retailers, this seems to be a strong environment, particularly as some are still underhedged, and many now have greater load at lower wholesale prices, with the stay-at-home orders combined with low energy as well as lower capacity obligations as peaks decline with flatter power curves. Even though this overall demand loss is negative for power prices, the shift in demand from C&I to residential customers could offer some offset to margins of energy retailers given that residential volumes tend to carry higher margins compared to C&I volumes.

In terms of demand loss for our analysis, we are assuming C&I demand is down 15% through August, and 10% down through December. We also assume a 20%-25% reduction in to-be-sold volumes through 2020 (affecting Vistra's Ambit retail outlet, which uses door-to-door sales).

Risks For Various Companies

We see the combination of a large C&I exposure and a long position in wholesale generation as the one at greatest risk. As a result, the risk is most pertinent to ExGen and Vistra, although a larger proportion of retail margins for Vistra come from its residential segment.

ExGen  ExGen has the most exposure to volumetric risks , in our view, given relatively high C&I retail exposure with the possibility of overhedged generation.

Based on public disclosures made by the company, it has about 155 TWh of total retail load. We have assumed that about 125 TWh was left to serve for the balance of the year by March 2020. Given a predominantly C&I book, we estimate that about 75%, or 90 TWh, is C&I demand. We have assumed a 15% decline of these volumes, or 13.5 TWh, through balance of year.

We estimate ExGen would lose about a $4/MWh margin, which is our estimate of the average margin across C&I segments. We believe there is very little relative fuel economics benefit in the PJM Interconnect with energy prices relatively flat along the forward curve. So it is reasonable to assume that the energy component embedded in the C&I contract price could be sold in the market without a loss. However, fixed-price products offered to C&I customers also unitize other costs (for capacity, ancillary, load shape, etc.). These costs will differ across customers but we have assumed these at about $7-$8/MWh. Our analysis then translates into about $150 million-$160 million of EBITDA impact (13.5 TWh times $11-$12/MWh). This analysis makes a fairly broad assumption on unitized costs, which could be higher, and also ignores ExGen's ability to optimize its portfolio hedges, or lower O&M and marketing costs. However, it provides the expected range of impact of the volumetric decline.

NRG Energy  NRG has the unique situation of being short economic generation (that's power that it can generate economically from its assets relative to purchasing) in ERCOT because its retail business has rapidly expanded (see Table 3). To be clear, it does have incremental generation in the region, but that would likely be invoked only when the company needs to cover an unplanned short position (for example, on a very hot day when a major unit goes down). So far, the company has mitigated the short position by entering power purchase agreements (PPAs) with solar power producers. The company's third-party hedges are fixed-price and fixed-volume except for its solar PPA, which is generally fixed-price but variable volume (it gets MWh when the sun is shining). The company can also self-generate power from its less-efficient units, but that would erode the company's margin relative to budget.

Table 3

A substantial proportion, but not all, of NRG's energy generation is allocated to its retail book for 2020. The other is sold to third parties for periods when the company is long generation relative to load (e.g., off-peak hours in shoulder months). On the retail side, while third-party purchases have closed the short position, the company still has a retail open position that needs to be closed. So if load were to decrease in the coming months, that would first mean a reduction of this short position since the company is also managing the position in the aggregate across mass residential sales and C&I. Only if load were to decrease even more and/or there was some location and hourly mismatches, will the company have to sell the excess generation into the market (or stop running its plants, depending on economics). Even if C&I loads go down, C&I margins are considerably lower than retail margins and therefore less impactful to consolidated EBITDA.

For 2021, we estimate that only about a third of the expected retail load is hedged at this time. We would expect the company's generation to be pointed to its retail book and that it will enter into external hedges over time as it locks new and existing customers. In this environment, we're monitoring how premium brands do. NRG's ability to retain its month-to-month customers is a key factor. To recall, residential contracts are fixed-price that range from month-to-month to about 18 months

We see the impact on retail cash flows in the range of about $40 million-$50 million for 2020 based on an assumption that about 60% of NRG's C&I contracts are fixed-volume contracts. However, we perceive a greater risk in NRG's ability to retain residential customers next year. In 2021, NRG's retail hedge levels remain low but will increase over time as it signs up/rolls over customers. However, if wholesale power prices are lower next year, it should benefit the retail business since cost of goods sold would be lower and working capital/bad debt should decrease. The wholesale generation will likely be less economic and so running less, but it should also mean more likely retirements in ERCOT and also fewer new developments impacting prices.

Finally, as NRG's generation portfolio is not as well-matched with its retail load in the East, it will likely hedge its exposure with the market, which is relatively liquid in PJM East. Outside of ERCOT, NRG has volume and price exposure but the margin at risk is much lower than in ERCOT.

Vistra Energy  Vistra is somewhat more exposed than NRG because of its long generation position. Although the company's load-to-generation matching has improved over the past two years, it is still significantly long and needs its retail load to augment its wholesale power hedged position. Table 4 is updated to reflect our estimate of the increase in Vistra's residential retail business in ERCOT that we published in September 2019 (see related research). The higher numbers incorporate organic growth as well as roll up of the recently acquired Crius and Ambit retail businesses.

Table 4

We are interested in the volumetric risk in the roughly 45 TWh of large business load that Vistra serves, of which about 40 TWh is likely still to be served. We estimate that a decline in that load by 15% could mean a loss of nearly 6 TWh in retail sales, which will be resold into the market. We estimate a higher impact on Vistra than on NRG because Vistra likely has a higher proportion of its retail load served by its own wholesale generation. The financial impact of not delivering these volumes will include lower retail margin, and selling this power back into the market at a lower price. Note that both the lower volumes and sell-back impacts generally sit in the retail segment of the portfolio, with the exception of any default service load. We estimate this impact at about $50 million-$60 million.

Calpine Corp.  Calpine's retail business is not big enough to make a material impact on its aggregate cash flows. Yet, it offers the opportunity of a 'pure play' evaluation. Calpine has two separate retail businesses under Energy Solutions and Champion with loads of about 35 TWh and 25 TWh, respectively. Sales through Solutions are to LCI customers on a block and indexed basis. The hedges typically sit on the customer's account and managing any volumetric risk is therefore on the counterparty. However, all of Champion's volumes are on a load shaped basis with only about 5 TWh sold to residential customers. Thus, Calpine has exposure to about 20 TWh of C&I load shaped risk.

Bad Debts And Working Capital Needs

There is little visibility on bad debts at this point and we expect initial figures to start emerging around mid- to late-May when April numbers come in. We have tentatively assumed that bad debts will be 2.0x-2.5x the incremental level during the 2008/2009 financial crisis. This largely reflects the current sharper economic decline and significantly higher unemployment numbers across the country compared with the financial crisis.

On a preliminary basis, estimated financial impact of higher bad debt expense, limited ability to charge associated customer fees (e.g., late fees), and partial reimbursement by the public utilities commission (PUC) relief program is likely to be in the $50 million-$80 million range for retail businesses of companies the size of Vistra and NRG. We also think working capital could increase by $75 million-$100 million in the second quarter of 2020. That said, the Texas PUC has quickly moved to address the potential increase in bade debts. The PUC has adopted an "Electricity Relief Program," which reimburses retail electric providers (REPs), at a standard rate, for unpaid bills during a proposed disconnect moratorium of six months for a protected group of customers.

The REP recovery is set at $0.04/KWh ($40/MWh). Procedurally, the ERCOT transmission and distribution (T&D) utilities (TDU) will implement a rider to facilitate funding for the program, which will collect funds to reimburse TDUs and REPs for unpaid bills from eligible residential customers experiencing unemployment due to COVID-19. Unpaid bills are considered "bad debt"; the TDU absorbs the T&D charge and the REP absorbs the energy bill. Once a customer is eligible for the COVID-19 electricity relief program, the TDU will cease charging REPs for the delivery charge. The REP will then offer a payment plan for the energy portion of the bill and if the customer is unable to make those payments, then the REP can recover the $0.04 KWh. At that point, the REP can continue to pursue payment from the customer for the portion that is not covered by the $0.04 or simply take the charge. Also, if all bad debt claims from REPs drain the fund too rapidly, TDUs will cover the difference and the rider will remain in place even after the program is terminated to make them whole. Although the reimbursement mechanism is still under discussion, this will provide some moderate relief to the bad debt ERCOT REPs will likely incur, but will still likely cover 50% or less of the exposure of the retailer. We think this is a credit-preserving mechanism as the recovery is sized right to ensure rational actions by the residential REPs.

In the Northeast markets, IPPs do not negotiate the bad debt rate with the utility. The number is set as part of a calculation that the utility submits to the utility commissions on varying frequencies depending upon the market. In a purchase of receivables (POR) program, the utility purchases the residential customer receivables of a retailer at a discount rate roughly equal to the utility's actual uncollectible rate. This discount rate is then offset from the monthly payments the utility makes to the retailer. The key difference between how it works in ERCOT for mass customers versus in POR markets is that the IPP is not responsible for the bad debt management or collections, and simply pays a predetermined rate each month, which varies by utility. However, that rate can fluctuate depending on actual performance for the entire utility service area, not just the IPP's customer portfolio.

The current POR rates across most of the Northeast are 0.25%-2%, with an average of 0.75%. It is likely that some utilities will apply to their PUC to increase their rates in the future (e.g., Consolidated Edison Inc. recently filed for an effective rate of 1.02%).

Our Credit View On AES Corp.  We would be remiss in not adding a word on The AES Corp., the other large unregulated power company in our rated universe, and its aspirations of achieving an investment grade rating.

The highly contracted nature of AES' business with over 70% of subsidiary distributions from highly rated countries provides a good line of sight on cash flows. We think the fortunes of the company are now less related to the unregulated proportion of its cash flow, which have progressively declined and constitute only about 15% of aggregate parent-level cash flows (we rate AES Corp. based only on the parent-level indebtedness that are serviced through distributions from its numerous nonrecourse subsidiaries). We view favorably the willingness and ability of the company to lower recourse debt to about $3.7 billion from over $6.5 billion in 2012 favorably. The company's success around 2.5 GW of new long-term contract for renewables at AES Gener S.A. have mitigated the potential for a cash flow decline in 2024 when the regulated PPAs were set to roll off.

We are monitoring risks that are unique to AES because of its businesses in geographies that could have heightened regulatory risks. These businesses could experience economic contraction as a result of the ongoing COVID-19 lockdowns across many countries. In particular, some of the risks are as follows :

• Delayed impact of COVID -19 on emerging markets where there is limited ability for economies to employ fiscal stimulus through borrowings.
• Regulatory risks of changing contractual terms due to lower load, or from delays in payments to utilities (such as in El Salvador)
• Load degradation at Indianapolis Power & Light or Dayton Power & Light given absence of decoupling mechanisms.
• Recent repositioning from U.S. dollar-denominated contracts in Argentina to local currency and risks of further reductions in compensation to generators.
• Variability of resource risk and ensuing cash flow volatility in hydro portfolios such as AES Tiete, AES Colombia, and AES Panama.

If cash flow generation continues on track and the company continues to execute its budgeted plan, we expect to resolve the outlook before year-end 2020.

What Does All This Mean For Credit Quality?

We plan to maintain the positive outlooks on AES Corp., NRG Energy, Vistra Energy, and Calpine Corp. despite the negative impact on cash flows from the lockdowns. However, delayed upgrades are possible given the broader market uncertainty and volatility. We acknowledge some adverse selection in our assessment as there are too many unknowns. We emphasize that visibility into the resiliency of 2021 cash flows-–where the IPPs have lower hedged levels--is equally important.

Broadly, we think the impact of the economic stop on the IPPs is relatively muted up to this point, especially when compared to sectors like oil and gas, midstream and refining. Even in an unprecedented shutdown such as this, it takes time for the energy juggernaut to slow. Having a big balance sheet, operational diversity, and countercyclical retail operations that provide a native hedge certainly make a significant difference to the credit quality, in our view. However, although power demand is directly correlated to economic deceleration, it is somewhat insulated and feels the domino impact with a lag. We expect to see increasing levels of credit weakening as the full onslaught of a slowing C&I segment is experienced in the second quarter.

Given their focus on leverage reduction in recent years, we think the IPPs on positive outlook are in much healthier shape from a balance sheet and liquidity perspective. Except for ExGen, there are no companies with near-term maturities, with some companies having their nearest maturity stretched out as far out as 2023/2024. Moreover, all companies generate free operating cash flow under our base case scenario even after the COVID-related sensitivities. Arguably, the cash flow will be lower and the financial ratios a trifle weaker than what we had earlier estimated for 2020. Still, that may not influence the credit profile of these companies as they could simply change their capital allocations to keep on the deleveraging path they have set themselves on. We expect to start reviewing the positive outlooks in the third quarter as the economic recovery takes on pace.

Some investors have questioned whether this environment will add to the depressed equity valuation of these companies as the public markets remain underwhelmed with commodity volatility. Investors argue that Public markets now have a number of opportunities in the energy sector at some of the lowest prices in years and may remain relatively uninterested in IPPs. There is potentially a risk that the boards of companies like Vistra or NRG may contemplate a take-private transaction to maximize shareholder returns. Based on our conversations with the companies we do not factor a leveraged buyout scenario in our ratings.

Related Research

Pandemic Accelerates Erosion In Unregulated Project-Financed Power Credit Quality, April 24, 2020

Can Independent Power Producers Be Investment Grade?, Sept. 4, 2019

Unregulated Power: S&P Global Ratings' Evolving View Of Retail Power, May 14, 2019