As the power industry undergoes the largest fuel-switch in its history, independent power producers (IPPs) must separate the cyclical, short-term shifts from the structural, long-term disruptors. The COVID-19 pandemic has put new hazards on the course, but for IPPs the long and short games continue to focus on the advancing renewables proliferation.

S&P Global Ratings has long argued (see "Independent Power Producers: The Long And Short Of It," April 5, 2017) that weather-influenced demand and natural gas inventory levels largely dictate power prices in the short term, while secular demand trends, energy efficiency, growth of distributed generation/storage, and cost propel structural power prices. Our credit assessments were focused on how effectively merchant generators hedged in the short-to-medium term, and if the market offered them any efficient hedges in the long term.

We believe COVID-19 has emerged as a structural disrupter of energy demand over the next decade. We expect demand to change and generation growth to be at least two years further away than pre-COVID in most energy markets, and in some segments several years more. COVID-19 has also underscored other ongoing changes in U.S. electricity production and consumption patterns.

But the proliferation of renewables remains the key obstacle. Power prices have been declining because of them. As a result, we expect regional markets in U.S. to become "long energy" (i.e. supply higher than demand) in most months and the opposite (short generation) during the summer and winter.

The proliferation of renewables is also changing the supply stack: it is often cheaper to buy power than to produce it, with physical generation largely as a backstop for summer and winter. Load serving entities and retail power providers now have a choice between generating power from owned assets, or contracting for it. Owning a generation asset has effectively become a directional bet that the asset will remain economical through its physical life.

Against this backdrop, we now see a different long and short discussion arising: Is it better for a load-serving entity/retail power provider to have a long generation position relative to its retail obligation, or to have a short position and then contracting for the balance?

A Beleaguered Conventional Power Business

The conventional wholesale power dynamics are changing rapidly:

• More renewables is resulting in lower round-the-clock power prices.
• Lower commodity prices mean less opportunity for IPPs to earn energy margins from relative fuel differences. An efficient natural gas-fired plant, for example, earns higher margins when gas prices are high.
• Increased energy efficiency has resulted in declining demand for electricity.
• Renewable portfolio standards (RPS) are contributing to declining load growth expectations. Behind-the-meter solar generation (electricity produced by customers), for example, can be thought of as a net reduction in demand.
• Climate change will intensify what were already unpredictable weather patterns, altering the long-term need in different regions for heating or cooling.

Economically speaking, the proliferation of wind and solar renewables is pushing the conventional generation supply to the right on the variable cost curve's horizontal axis, resulting in a lower clearing power price at the same level of demand. Meanwhile, reductions in marginal fuel costs (the vertical axis) and improvements in gas turbine technology is also flattening that supply cost curve. We think these declines also reflect some combination of lower natural gas prices and milder winters and summers that weighed on prompt power prices, which then cascaded onto the forward curve. All of this has led to backwardation in forward power price curves (i.e. power prices in the current year are higher than the futures), which is exacerbated by a lack of liquidity in the outer years.

Retail And Contracted Renewables Are A Hedge Against Disruption

The problem is the IPP sector appears to have lost its long-term investor group, for reasons not limited to the volatility in commodities. Deregulation generally works best when competitive markets are left to decide the lowest-cost reliable provider. Lately, winners and losers have been chosen for other reasons, including fuel diversity, clean generation, impact on local economies, and reliability issues.

With the wholesale power business in disruption, and in the context of disruptive renewables and better storage facilities, the retail power business (i.e., sales to commercial and residential customers) becomes the next battleground. With the grid likely to become much smarter over the next decade, getting inside a customer's premises could mean opening up an entire avenue of growth through sales of everything from thermostats and smart meters to photovoltaic (PV) solar and battery solutions. In this way, retail provides a great defense against renewables, and perhaps the only pivot around which merchant generation can build a viable business model and win the long-term investor back.

Still, different business strategies have different risks. Vistra Corp. and NRG Energy Inc. (NRG) are two IPPs whose business strategies started diverging about three years ago. While NRG shed a substantial portion of its owned generation and pivoted emphatically towards a retail dominated model, Vistra has retained substantial generation capability. Both companies have growing retail power businesses. However, NRG is pursuing an asset-lite strategy while Vistra is still asset-heavy in its major markets.

Vistra: A Case Study In Long Merchant Exposure

Vistra's integrated wholesale generation and retail power model have gained credibility over the past two years because retailing power appears to provide it with a hedge for its wholesale power operations when they are regionally matched, which reduces the financial effects of lower forward power curves. The company's volatility has been lower at about 15% trough to crest. We view the pandemic as a severe stress test of its integrated model and the company's performance has been relatively stable thus far.

Backwardated power prices remain the key risk for Vistra's long position

The main risk that we see for Vistra is its open wholesale generation position and the backwardation of forward power curves in markets such as ERCOT. The chart below presents the company's regional generation mix in 2019, 2020, and pro forma for the recently announced coal-fired power asset retirements.

Chart 1

While the company has recently announced significant asset retirements through 2027, it is still significantly long generation relative to its retail load (see chart 2).

Chart 2

What jumps out when reviewing Vistra is that almost 55% of its gross margins are exposed to riskier energy margins. If we were to mark Vistra's unhedged economic generation to the current forward power curve, we believe about 25% of the company's margin in its 2022 wholesale EBITDA is at risk (or about 15% of its aggregate EBITDA).

Renewables without storage have failed to deliver

However, over the past four years we have observed the forward markets are heavily influenced by a small number of power purchase agreement (PPA)-related transactions in a relatively illiquid hedging market. The forward prices also do not appear to reflect any scarcity associated with the increasingly intermittent availability of resources. Therefore, forward power prices have consistently risen in the late summer of the immediately preceding year of delivery as liquidity improved. Vistra has repeatedly shown its ability to hedge against the volatility despite the backwardated forward curve.

It is clear that coal-fired generation is in decline. However, given the inability of renewables to provide power on a firm and peak-coincident basis, efficient conventional power assets (e.g. combined-cycle gas turbines with heat rates below 7,000 Btu/KWh) appear to be economical through the decade. However, to investors, this still appears to be a transitional strategy. The potential of storage paired with renewables is the risk that lenders are wary of. They continue to question the fundamental economic thesis for companies that are long conventional generation given that the cost curve for renewables is declining and batteries continue to advance. On the other hand, long generation companies like Vistra and Calpine view the competition between natural gas and renewable assets as not one of survival but one in which both will coexist.

The company's recently announced strategic shift will substantially right-size its load-to-generation matching

With one of the larger fossil-fired fleets in ERCOT, Vistra's carbon footprint is significant. The company has announced the closure of about 6.6 GW of coal-fired generation in the PJM/Midcontinent Independent System Operator (MISO) regions. This follows its retirement of nearly 4.2 GW and 2.0 GW of coal-fired units in 2017 and 2019, respectively. We view these closures favorably but note that all of the generation capacity the company is planning to retire, or has already retired, is economically challenged.

Despite the announced closures, Vistra still has a long-generation position relative to its retail load. COVID-19 has exacerbated (and underscored) the risks facing merchant coal-fired generation. At the start of 2020, the company estimated nearly 190 terawatt-hours (TWh) of aggregate economic generation from its fleet. With the pull-back in power prices since the onset of the pandemic, it has reduced its expectation to 170 TWh. The announced coal-plant retirements will further reduce that figure to 134 TWh.

Perversely, the decline in its wholesale generation will improve its load-to-generation matching. Before the asset closures, we estimated a load-to-generation match of 61% for the company in 2020, which we now expect to improve to a pro forma 81% (regional mismatches exist) after the shuttering of most of its coal-fired units (see chart 3).

Chart 3

We expect declining volumes and margins for Vistra--and most conventional long generation companies--to result in a backwardation in projected EBITDAs. In response to that expected decline, generators with exposures to merchant markets will have to continue to reduce their debt commensurate to the cash flow decline to maintain financial performance.

A pivot to renewables is a necessity, not a choice

Vistra's announcement of coal capacity retirement comes attendant with planned investments in renewables and storage, and will take coal's share to ~10% of its generation portfolio by 2030, down from 30% currently. The company plans to develop 6 GW of renewables and storage capacity over the same time frame. As part of this process, Vistra has begun development of about 1 GW of solar and storage projects in Texas, which are expected to come online over the next two years. Vistra will spend about $850 million of growth capital expenditures (capex) on this phase I development, and expects to generate about $90 million of EBITDA per year from these investments, that well supplants the loss from its sunsetting coal-generation division. The company is also contemplating incremental development opportunities in Texas (1 GW) and others in California (1 GW) and Illinois (450 MW).

Vistra has also accelerated its emission reduction targets, and now expects to cut emissions by 60% by 2030 (vs. 50% before) and achieve net-zero emissions status by 2050 (vs. 80% before). While these targets show intent, Vistra has yet to retire an economically viable coal plant, though we believe the company's remaining 4.5 GW of ERCOT coal-fired generation will eventually become economically challenged.

NRG Energy: A Case Study In Short Generation

In contrast to Vistra, NRG is now deemphasizing generation with that business pivoting only to support the retail market. NRG believes that by shedding excess generation it is also shedding long-term exposure to merchant markets, and that other companies will be forced to follow suit. In an effort to focus more on its integrated retail and generation platform, the company has shed legacy assets in areas with no retail presence, most notably about 3.5 GW of its South Central portfolio that included large assets like the Big Cajun and Cottonwood power plants. We expect the Midwest to be divested too.

The pivot from wholesale and the retail promise

The acquisition of Direct Energy shifts the pro forma NRG aggregate EBITDA decisively toward retail power (to 56% from 48% of aggregate), a business that the company has been able to assimilate efficiently through its recent acquisitions of Xoom Energy and Stream. Growth of capital-light retail segment has the potential of increasing NRG's cash conversion further.

NRG argues that the retail platform could take further advantage of cross-selling opportunities and introduction of consumer products and related home services, particularly following its Direct Energy acquisition. Direct Energy already provides a number of options for home warranties as well as home protection plans, and NRG has similar offerings at some of its retail businesses, with opportunity to expand across its platform into products like home security.

There could be other opportunities for expansion like consolidated billing in which all energy charges are included on a single bill. While Texas already has consolidated billing, Maryland also recently approved it and there is growing potential of other Northeast states considering the option.

NRG's generation assets are of relatively older vintage

NRG's economic generation, i.e. the generation that can economically back its retail load, is now much smaller than Vistra's, at about 57 TWh in 2019. Despite the smaller portfolio, over 35% of NRG's generation is still produced by coal-fired assets. NRG's generation, in our opinion, is also somewhat higher priced on a variable and fixed operating and maintenance (O&M) cost comparison because its assets are older.

Because the forward prices were in backwardation, we expected NRG's fleet to produce about about 50 TWh to 55TWh of economic generation from its fleet (37 TWh, 11 TWh, and 3 TWh in its ERCOT, East, and West markets, respectively) and down from about 57 TWh generated in 2019). In the wake of the pandemic, power prices have receded even further. Through June 2020, NRG had generated 6 GW less from its fleet than it did in 2019. We now expect the company to generate only about 44 TWh to 46 TWH in 2020. While purchasing cheaper power from the market augers well for its margins, the short position has become more pronounced from a liquidity perspective because NRG's assets are relatively older and inefficient.

Table 1

A short generation position in retail-to-wholesale matching works in NRG's favor, for now

Because of its vintage position on the supply stack, NRG's eastern fleet dispatches at much lower levels than its ERCOT fleet despite similar levels of owned MWs in the region (see table 1). NRG does have substantial generation in the eastern markets where much of Direct Energy's load resides. While NRG plans to hedge that load with power purchases, should it fall short, it has a number of assets in the east that can flex up, typically with its out-of-market peaking gas-fired units. This generation is costlier than the costs NRG has budgeted in its forecast and will result in lower EBITDA than anticipated, but will prevent the need to cover short positions from the market under extreme prices.

NRG's performance in its ERCOT business is key after the Direct Energy acquisition

Based on our estimates, NRG's legacy business is about 2 GW short in ERCOT in the peak summer periods. Recognizing that need, the company has already made one request for offer (RFO) for renewable PPAs and has contracted 1.7 GW. Much of this generation, currently under construction, has now been delayed because of COVID-19. Given that these PPA contracts were competitively priced, NRG has had to re-hedge this power from the market (or self-generate) at higher costs, resulting in lower expected margins in 2021 than our earlier estimates.

We estimate that Direct Energy's load would add a further 4 GW to NRG's retail position in ERCOT (although 2 GW of these contracts are indexed). As a result, the pro forma company will either seek more renewable PPAs, which would increase its operating leverage, or enter tolls/heat rate call options/structured obligations to secure generation capacity--which we will consider as non-executory contracts that will typically result in debt imputation of the demand charges.

Liquidity has emerged as NRG's dominant credit risk, in our view

While the merchant risks of being long wholesale power are apparent, being short generation has its own unique risks. Being short generation, and hedging retail requirements through purchases, will result in margining calls should power prices drop. Limiting must-take supply-to-minimum demand expectations mitigates hedge costs and liquidity demands during mild weather events.

The gas supply business requires margining and collateral requirements. Direct Energy has historically provided that through a parental guarantee, which will need to convert to letters of credit (LCs). The company estimates this requirement at $2.1 billion (about $1.7 billion of LCs that will replace Centrica's parent guarantees and $380 million in incremental margins because of NRG's speculative-grade ratings). The company proposes to fund these immediate requirements at close through a combination of sources, including funded LC facilities.

While the company will likely renegotiate collateral posting requirements as contracts come up for renewal, the reduction is not going to happen quickly given 800 counterparties. We note that realized reductions through tighter management of LC usage parameters, synergies with overlapping counterparties, offsetting trades, and overlap of generation and retail in the Northeast are likely.

Given a short position, a stress scenario for the pro forma company is a significant decline in power prices. In order to evaluate NRG's potential future exposure to its LC reserve, we asked the company to run a market stress test considering a roughly 30% decline in power prices in 2021 and a 20% decline to 2022. Results were based on a P95 case across 500 simulated market price paths, including adding future trades for contracted retail load. The simulations show that NRG legacy business's liquidity requirements would peak at $2.0 billion in summer 2021, leaving about $1.1 billion as excess liquidity for Direct Energy's future exposure.

Bringing In The Verdict

Vistra can develop a matched book

The risks of a being long generation when the industry is witnessing the largest fuel switch in its history are apparent. In this regard, Vistra's strategy appears to now focus on developing a mostly matched retail-to-wholesale book in ERCOT and PJM, and reducing its exposure to power curve volatility. To this end, we expect to see it optimize by incrementally paring its generation fleet, while simultaneously rolling up its retail business to match that generation.

In a nod to the eventuality that more of its coal-fired generation will retire, Vistra has announced the pivot to solar and storage projects. While we think of renewables as a hedge against disruption, the ownership of renewables entails merchant tail risks because no retail contracts extend that long. We note that while Vistra has started revamping its generation mix, it still believes in owning assets compared to contracting for generation. In this regard, the company's strategy has departed from that of NRG, which has instead chosen to contract for renewable generation to serve its retail load.

In our view, the solar investments are an efficient tax mitigation strategy as much as a direct sale opportunity to retail customers. However, it still leaves merchant tail risk with the company in a market where we expect substantial solar additions. There is increasing confidence amongst industry policy experts for a solar ITC extension to be passed in 2021, irrespective of Senate outcomes, or potentially split Congress. If the extension occurs, we expect 15GW-20 GW annual solar deployments through 2025. That would add to the ERCOT region's supply and, potentially, to the backwardation in its power prices.

NRG Energy: Liquidity risks dominate, as does the ability to procure generation

NRG has decisively pivoted in favor of its retail platform. Power generation is a capital-intensive business and, at a time when much of the new capital is going into renewables, NRG decided to exit this space. NRG has essentially decided to focus on retail power as its defense against the disruptive forces in the wholesale market.

By shedding conventional generation at the time it did, NRG was able to focus on growing its retail business. It also guessed correctly on the timing of the renewable cost curve decline. By purchasing, instead of producing power, NRG has effectively rented the lower cost of capital that comes attendant with the balance sheets of investment-grade utilities. The company has been able to contract for cheaper renewable energy, as evidenced from the discount in its 10-to-12 year PPAs compared with ERCOT forwards.

The acquisition of Direct Energy is expensive, yet such transactions are few and far between. Direct Energy is the third largest brand in ERCOT, the largest retail market. We believe the acquisition--even if somewhat higher priced, in our view--is not the problem as the potential for synergies does exist. However, the timing of the acquisition certainly is. Perhaps in that regard, NRG has moved to acquire Direct Energy early as a preemptive move to thwart rivals likely because of a growing belief that Centrica was contemplating divesting its retail power business and exiting its North American operations.

The major risk for NRG is in its ability to procure generation to match its suddenly higher retail load. We think NRG will rely on a combination of its peaking generation units, purchasing call options, and supplemental market purchases, to cover demand during periods of extreme weather. However, it will still need generation to cover its residential and longer commercial and industrial load exposure. We note that even if PPA contracts for solar generation are structured as energy-only payments, given the predictable nature of the resource, generation is also predictable, making a take-and-pay contracts similar to take-or-pay contracts. This increases its operating leverage and would result in meaningful debt imputation as the PPA books increases.

Both companies have an incentive to delever

It is clear that the retail business has provided both companies the countercyclicality to mute the backwardation in their wholesale power businesses: retail margins have improved as wholesale power prices have declined. Yet, a major risk to the retail strategy is the concern that storage solutions will eventually minimize volatility in the marketplace and also reduce competitive barriers. As a result, we expect both companies would incrementally delever in their bid to achieve investment-grade status. We note that both companies generate meaningful free cash flow because retail power is a capital-lite business. We believe utilizing excess cash for debt reduction should allow the companies to lower their adjusted debt to EBITDA to about 2.5x-2.75x on a sustained basis. We believe that level of leverage would result in an investment grade credit profile.

The liquidity needs to run a business of the scale that NRG has become are high. Typically, operations of such scale are more efficiently run under an investment-grade balance sheet. As a result, we believe NRG has an additional incentive to delever to improve credit quality and stride towards its investment-grade aspirations.

On a relative basis, while both companies have business models that could get them to investment-grade status, we think NRG has higher execution risks because of the combination of risks relating to extraction of synergies, deleveraging, and managing its liquidity needs through 2021.

Related Research:

• Weakening Commodity Prices And Demand Will Require Alberta Energy Producers To Adjust To A New Reality, Nov. 30, 2020
• Independent Power Producers Update: The Greatest Risk Is Not Taking One, Dec. 6, 2017
• Power Market Update: Knowledge Speaks But Wisdom Listens, May 23, 2017
• Independent Power Producers: The Long And Short Of It, April 5, 2017