NRG Energy Inc (NRG) 2020 Q4 法說會逐字稿

Ladies and gentlemen, thank you for standing by, and welcome to the NRG Energy, Inc. Fourth Quarter and Full Year 2020 Earnings Conference Call. (Operator Instructions) Please be advised that today's conference is being recorded. (Operator Instructions)

I would now like to hand the conference over to one of your speakers today, Mr. Kevin Cole, Head of Investor Relations. Sir, please go ahead.

Thank you, Michelle. Good morning and welcome to NRG Energy's Fourth Quarter and Full Year 2020 Earnings Call. This call is being broadcast live over the phone and via webcast, which can be located in the Investors section of our website at www.nrg.com under Presentations & Webcasts.

Please note that today's discussion may contain forward-looking statements, which are based on assumptions that we believe to be reasonable as of this date. Actual results may differ materially. We urge everyone to review the safe harbor in today's presentation as well as risk factors in our SEC filings, and we undertake no obligation to update these statements as a result of future events, except as required by law. In addition, we will refer to both GAAP and non-GAAP financial measures. For information regarding our non-GAAP financial measures and reconciliations to the most directly comparable GAAP measures, please refer to today's presentation.

And now with that, I'll now turn the call over to Mauricio Gutierrez, NRG's President and CEO.

Thank you, Kevin. Good morning, everyone, and thank you for your interest in NRG. I'm joined this morning by Gaetan Frotte, our Interim Chief Financial Officer. Also on the call and available for questions, we have Elizabeth Killinger, Head of Home Retail; and Chris Moser, Head of Operations.

I'd like to start this call by expressing our utmost concern for the millions of Texans impacted by winter storm Uri. We're actively working in our communities and with our customers to provide support and relief to those in need. I also want to recognize all the men and women from NRG who, under frigid conditions, were working tirelessly to keep our power plants running and those employees who work day and night through this event to inform and support our customers, all while facing their own hardship at home. From everyone at NRG, thank you.

Let's move on to Slide 3 for the 3 key messages of the call. First, above all else, our top priority and core focus today is helping our Texas communities recover from the devastating winter storm. The system-wide energy failure that occurred in Texas is unacceptable, and we are committed to working with all stakeholders to prevent this from happening again. Next, our integrated platform continues to deliver stable results through unprecedented events like the COVID-19 pandemic and extreme weather events, further validating the strength of our model.

Finally, we continue to advance our customer-centric strategy by redefining our platform to better serve our customers. In January, we closed on the Direct Energy transaction, forming the leading North American integrated energy and home services company, now serving a network of 6 million customers. Today, we are announcing the sale of a 4.8 gigawatt portfolio of noncore fossil assets, which I will detail later in the presentation.

Turning to Slide 4. Starting on the left-hand side, winter storm Uri was simply historic. It was the third coldest 3-day stretch on record in Texas, blanketing the state for days with record cold temperatures and precipitation, putting unprecedented stress on the entire energy system. This winter storm exceeded all planning parameters and highlighted the interdependency between the natural gas and power systems. On adjusted estimated peak low of 77 gigawatts surpassing not just the winter peak, but the all-time peak. And due to weather-related system and plant-specific issues, 52 gigawatts of capacity in the market were forced off-line at one time or another.

Last week, we committed to work with regulators and legislators on a comprehensive and exhaustive root cause analysis of what went wrong in the energy system, from fuel supply to the production and delivery of electricity. Our goal is to have a system that is more resilient to prevent this from happening again.

Turning to the right-hand side of the slide. Our work to prepare for winter conditions began well before the onset of frigid temperatures. As part of our winter readiness program, we execute a comprehensive winterization program that starts with the lessons learned from prior winter seasons. Then every September, our power plants in each of our markets, including Texas, begin a well-defined process of preparing for winter operations. The results are presented to me in early November by the Head of Operations and each plant manager. We then submit our declaration of completion of the winter weatherization preparations to ERCOT and the PUCT by November 30.

In early February, we recognized the threat of this significant winter storm. Safety of our employees, customers and communities is always our top priority. For our customers, we send cold weather alerts and energy conservation notifications across all of our retail brands and work with our large C&I customers to proactively reduce their load. For our generation fleet, we put all plants at the highest level of alert, made all operational units available to the market and secured additional critical supplies at our sites. This included moving personnel from the Northeast with extreme cold weather experience and technical expertise to Texas plants.

Ahead of the storm, we also took additional steps of increasing our available generation capacity by bringing back nearly 2 gigawatts of power generation typically reserve only for summer months. We also executed additional natural gas and power hedges. Our available generation portfolio performed at roughly 80% capacity factor on average. When comparing our generation production to a similar period earlier in the month, we produced almost twice as much electricity. Despite our best efforts to winterize the fleet, we suffered our share of unit-specific and system-related problems that will be part of our root cause analysis.

Turning to Slide 5. Our strategy is to maintain a balanced portfolio between retail load and supply to protect both our customers and our business. In Texas, we have a significant retail footprint across the state, supported by diverse generation assets and third-party agreements.

During the storm, we aimed at maximizing the output of our power plants while maintaining a fairly balanced position across the portfolio. Importantly, none of our residential customers will be exposed to the real-time wholesale power prices that occurred during the storm. We don't offer these products to our residential customers, and we also don't believe they should be available to them. And like I said earlier, we're focused on recovery efforts across our communities. We have pledged an initial $10 million in relief to our communities, customers and employees.

Now turning to the right side of the slide. We expect our balanced platform to deliver stable results. Our preliminary analysis of the winter storm financial impact is expected to be within our current guidance range. This preliminary assessment incorporates internal estimates on customer meter and settlement data, which have not been finalized yet. It also makes assumption on potential customer and counterparty credit risk and ERCOT-default allocations. We have also performed a stress test on our assumptions resulting in a potential outcome, although at a lower probability of plus/minus $100 million to our guidance ranges. As information becomes available, we'll be able to narrow this kind of outcomes.

Moving to the 2020 operational and financial highlights on Slide 6. Beginning with our 2020 scorecard, we executed on all our priorities. We delivered strong financial and operational results and had our best safety year ever. I want to take a moment to thank and commend all of my colleagues as this is now the third straight year we set a new record for safety, an incredible accomplishment.

Our 3-year transformation plan goals were fully achieved in 2020. During this time, we simplified and streamlined our portfolio, achieved a strong balance sheet, established a transparent and compelling capital allocation framework and made sustainability an integral part of our foundation.

Over the last 5 years, we have been evolving our platform to move closer to the customer. In 2020, we took major steps towards this goal with key highlights, including the acquisition of Direct Energy, and diversifying our supply strategy through signing renewable PPAs in ERCOT and launching RFPs in the East. We have significantly rebalanced our portfolio by growing retail and reducing generation. I look forward to sharing with you the next chapter during our Spring Analyst Day.

Now moving to the financial results on the right-hand side of the slide. We delivered $2 billion of adjusted EBITDA, slightly above the midpoint of our guidance range; and $1.547 billion of free cash flow before growth, which includes the pulling forward of certain items from 2021 into 2020 in order to fund the Direct Energy acquisition. Gaetan will provide more detail on the free cash flow later in the presentation.

I want to note that our 2020 carbon emissions came in below our 2025 50% reduction goal. We're not adjusting our 2025 targets today, but this highlights our efforts in reducing carbon emissions. Finally, as I previously stated, we're maintaining our guidance ranges for 2021.

Turning to Slide 7. I want to provide an update on the Direct Energy integration. This transaction presented a step change for us as we move closer to the customer by significantly expanding our customer network and home services. Given the complementary nature of both businesses, it also provides a significant opportunity to leverage our operating platform and achieve significant synergies. This transaction advanced our plan to rebalance our portfolio, reorganize around the customer and continuously improve our business and cost structure.

With Direct Energy closed, NRG now have the strongest collection of competitive power brands, offering energy products and services in North America. The Direct Energy acquisition significantly expands our residential and business footprint beyond electricity and outside of Texas. Both residential and business customers are able to leverage our platforms for solutions that feed their specific needs, elevating consumer choice to a whole new level.

Our integration efforts are well underway. And today, we are reaffirming the planned targets. We're already making significant progress on talent assessment, collateral management and systems integration. Throughout this integration process, we are focused on high grading our organization through retaining the best and diverse talent and further deepening our customer-focused culture. The integration is being led by the same team responsible for executing the transformation plan and has a similar governance structure. I am highly confident in our ability to achieve the synergies outlined on the slide.

On the right-hand side of the slide, you will see a scorecard that looks familiar and that is because it is how we reported our transformation plan progress to all of you. We plan to update this scorecard with our results in order to provide transparency and keep you informed of our progress.

Next, turning to Slide 8 for an update on our ongoing portfolio and real estate optimization efforts. I highlighted last quarter that we were actively focused on monetizing noncore assets with a target to realize a minimum of $250 million in equity proceeds within 6 to 12 months. I am pleased to announce that we have reached an agreement with Generation Bridge, an affiliate of ArcLight Capital Partners, to sell a 4.8-gigawatt portfolio of fossil fuel assets across New York, Connecticut and California for $760 million in cash proceeds or roughly 4x EBITDA.

As you can see on the bottom right-hand side of the slide, many of these assets are nearing end of life and with economics dependent upon capacity markets. Excluding Sunrise, the average expected capacity factors ranges between 0% to 6%. This is a good transaction for us. It further streamlines our business and addresses terminal value and earnings concerns that otherwise would have masked our retail growth. Our portfolio repositioning and optimization is a continuous process. We are committed to our business model, and we'll continue to provide updates on our progress. The asset sale is targeted to close in the fourth quarter of 2021. Net cash proceeds after associated debt reduction will be allocated using our capital allocation framework.

Before turning over the call to Gaetan for the financial review, I want to thank Kirk Andrews for his decade of service at NRG. Over the last 10 years, Kirk has not only been a colleague, but also a trusted friend. And I believe I speak for the entire organization when I say that we all wish him well and the best in his future endeavors. Our finance team is in capable hands with Gaetan Frotte, our Treasurer, stepping in as Interim CFO.

With that, I will pass it over to Gaetan for the financial review.

Thank you, Mauricio. I will now turn to Slide 10 for a review of the full year results and our 2021 guidance. Last year, NRG delivered slightly more than $2 billion in adjusted EBITDA and over $1.5 billion in free cash flow before growth. So our adjusted EBITDA for the year is in line with our 2020 guidance, and I would note that it includes the impact of COVID-19 that came in at only $25 million or half of our original cost expectations.

Moving to free cash flow before growth. Year-end results are $47 million higher than our latest midpoint of guidance driven by the inclusion of $43 million in distribution from Agua Caliente in 2020, just prior to the sale of the project in early February.

Finally, from a balance sheet standpoint, 2020 was also very successful with a year-end leverage close to 2.5x debt to EBITDA, which is at the strongest end of our targeted range. In addition, we had over $7 billion of liquidity accumulated in anticipation of the acquisition of Direct Energy in early January. A portion of that liquidity proved very useful during the recent winter storm.

Moving to 2021 guidance. As included in the closing announcement for Direct Energy, we increased our adjusted EBITDA guidance to a range of $2.4 billion to $2.6 billion and our 2021 free cash flow guidance to a range of $1.44 billion to $1.64 billion. As mentioned by Mauricio before, we are maintaining our guidance range for 2021 based on our preliminary analysis of the impact of the winter storm Uri on our results.

Based on a stress analysis, we believe that the financial impact on the guidance range could vary by plus or minus $100 million, subject to final customer meter and settlement data, counterparty credit risk and expected ERCOT-default allocation.

Finally, we have signed a PSA to sell 4.8 gigawatt of generation assets in our East-West region to an affiliate of ArcLight for $760 million, and we anticipate closing to occur by the end of the year. These assets contribute approximately $190 million of adjusted EBITDA and approximately $130 million of free cash flow before growth to NRG. I would note that these numbers have not been yet deducted from our guidance range.

Turning to the sources and uses for Direct Energy on Slide 11. We wanted to provide a bridge between the numbers reported during our last earnings call in early November when we discussed eliminating the need for $750 million of preferred equity and the actual results after closing the acquisition last January. So starting from the left with the $3.745 billion of total sources and uses as discussed last quarter, we first lowered NRG cash by $100 million to reflect the lower cash reserves available at year-end as shown on Slide 22 of the appendix. This was offset with an equivalent temporary growth under the revolver at closing.

Next, we used $13 million of incremental financing cost savings minus $2 million of initial discount on our bond issuance to reduce the temporary draw under the revolver by $11 million. In the next column, we reflected $77 million for a purchase price adjustment that was paid to Centrica due in part to the larger cash balance available at Direct Energy when we acquired the company. This was also financed through a temporary draw under our revolver.

Finally, we show the impact from acquired cash and margin collateral. Since at closing, Direct Energy had $233 million in cash margin posted and $152 million of cash and cash equivalents for a total of $385 million of cash on its -- and equivalents on its balance sheet. This was higher than we had anticipated last quarter, and we were able to use it after closing to repay the $160 million temporary draw under the revolver and reduced the NRG cash allocated to the acquisition by $219 million. More importantly, it also means more cash is available for deleveraging in 2021, which eliminates the need to use future asset sale proceeds to achieve our investment-grade credit metrics by year-end.

I will now turn to Slide 12 where we are updating the combined 2021 capital allocation provided last quarter. Please note that changes on this slide are indicated in blue. Starting from the left, we have adjusted the 2021 excess cash to reflect the final $715 million of CAFA reserve at the end of 2020. The $1.54 billion updated free cash flow before growth, including Direct Energy, based on the midpoint of our guidance range and finally, the $120 million of net proceeds from the sale of our remaining equity stake in Agua Caliente, all these represent a total of $2.375 billion available.

Then moving on to the next change on the third column. We updated the capital allocated to the Direct acquisition, which is now at $496 million, as shown on the previous slide. Finally, given the reduced cash needs for the acquisition, we are allocating our additional excess cash of $219 million to debt reduction. This brings our total debt reduction to nearly $1.2 billion, bringing us to within our targeted investment-grade metrics in 2021 and importantly, without the need for asset sale proceeds that we had mentioned before.

Finally, on Slide 13, I will start on the left with our 2021 credit metrics, which is now based on our finalized plan shown in the middle column. After adjusting our corporate balance for the increased debt reduction from 2021 capital allocation, our 2021 net debt balance is approximately $7 billion, which, based on the midpoint of adjusted EBITDA, implies a pro forma ratio of 2.65x net debt to EBITDA, well within the range of our targeted investment-grade metrics.

Turning to the right. We also wanted to update you on our strong liquidity position at the end of last week, which at $3.8 billion, is ample enough to continue supporting our business even during periods of stress like we experienced over the last 2 weeks.

In conclusion, and as discussed earlier, after proving the resilient performance of our integrated model during these trying times for Texas and our capital allocation plan to achieve investment-grade credit metrics by the end of 2021, we continue to believe in our ability to reach investment-grade ratings by the end of 2001 (sic) [2021] or early 2022.

Back to you, Mauricio.

Thank you, Gaetan. Turning to Slide 15. Our top priority today is helping Texans recover from the impacts of winter storm Uri. Texas is our home. Our customers, employees, friends and families were all impacted by this event. And while we have committed an initial $10 million to relief efforts, I want to make clear we are going to be there for our communities today and tomorrow, helping them recover in any way we can.

Moving to our 2021 priorities and expectations. As always, we strive to deliver on our financial and operational objectives and adhering to our capital allocation principles. With the Direct Energy acquisition complete, we turn our focus to integration and achieving synergies. Our efforts are well underway, and I look forward to updating you on our progress. Finally, I look forward to providing all of you a comprehensive update on our business and strategy at our Spring Analyst Day.

So with that, Michelle, we're ready to open the line for questions.

(Operator Instructions) Our first question comes from the line of Julien Dumoulin-Smith with Bank of America.

Just a real quick question about -- and congratulations again on the outcome. If I can connect at the outset here, I mean you guys gave a lot of remarks. But when you think about the guidance range reaffirmation here, can you give a little bit more commentary as to how you think about some of the caveats, your counterparties? Any remaining questions. You just talked about stress testing here. Can you talk about any assumptions on force majeure, counterparties following through? Any further context you can provide would be very much appreciated.

Sure, Julien. I mean first, the -- we're maintaining our financial guidance. This is inclusive of the expectation that we have on the entire portfolio across our operations. It also includes our preliminary assessment on the impact of winter storm Uri. That's already within the guidance that we're maintaining. Now having said that, we know that we only have preliminary information on customer meter and settlement data. We are stress testing the counterparty risk and also the expected ERCOT-default allocations. So once we did that stress test, that's why we are putting this plus/minus $100 million, which I think is prudent given the -- just the preliminary nature of these 3 key components of it.

Got it. Excellent. And then if I can ask you very quickly, how do you think about the remainder of the balance of your fossil portfolio year? How do you think about the divestment time line? How do you think about positioning it against this, I suppose, latest wave of repositioning?

Well, I mean we are very pleased to announce the asset sale today. As I said, I think you need to look at our portfolio through the prism of the integrated platform and moving closer to the customer. Whatever helps us better serve our customers, that's going to be the guidepost for us in terms of executing. Right now, we're focused on this. But as I said, I mean the portfolio optimization is a continuous process. And we're going to continue to evaluate the rest of our portfolio, and we'll provide you an update when we're ready to do that.

And our next question comes from the line of Steve Fleishman with Wolfe Research.

Nice relief today. Just on the -- Mauricio, I know it may be a little early for this, but maybe just kind of high level. How are you thinking about some of the solutions for making sure this doesn't happen again in Texas? I know you owe some feedback to the legislature I think by the end of the week. Just high level, maybe some of the thoughts that you have.

Well, I think the first step, which is what the Texas legislature already started is a comprehensive root cause analysis across the entire system, not just power generation, but I think everybody appreciate the interdependence between natural gas and power. So I think that process is going to take some time, and the first steps already happened last week. I mean I think everybody has seen the hearings down in Austin. I had the opportunity to participate. And that to me, it is the prudent first step.

Having spent some time down there and just looking comprehensively at the -- at what happened, I will say that there is perhaps 3 themes that legislatures and other stakeholders will be looking at. First is the hardening of the energy system from natural gas to power generation. I think it is clear that when the power generation is made up of close to 50% of the total capacity fueled by natural gas, natural gas -- the natural gas system becomes critical, and it needs to be hardened just as rigorous as the power generation system.

The second thing, I think there is going to be a conversation around the market design. And the focus, from my perspective, should be around the reserve margins and what is the excess capacity that we want to have in the ERCOT system to make sure that this doesn't happen again with perhaps more extreme weather conditions than in the past. And I think part of this excess capacity is not just the quantity of capacity, but also the quality of capacity. And what I mean about the quality, it is fuel diversification.

And then I think, finally, it is the communications. And to me, it is clear that communications needed to be a lot more than what we experienced last week. First is the communication between the power and the natural gas systems and the coordination between the 2. Second, it is the communication between TDUs who were responsible of implementing the power outages directed by ERCOT, and the reps who have the relationship with the customer. I mean I think that communication is to be a lot stronger. And we need to evaluate and assess a -- perhaps an alert system that tells our communities when something like this is going to happen and the potential risk. And then finally, I just -- I think it is important that we recognize just the magnitude of this winter storm. I mean any way you see it, it was historic. And as we are assessing these 3 things, particularly the hardening, we just need to make sure that is that the -- are we rebaselining our winterization efforts with this 100-year winter storm that we all live.

So that would be my initial comments, Steve. Obviously, I mean we're only in the beginning phase of this, but -- and I think we need to -- I think all the parties from what I can gather in my time in Austin, they want to take their time to make sure that they really fully understand what caused it so they can be thorough and have changes that will be effective and long lasting.

That's very helpful. I guess I'll ask one other big-picture question. Just given these potential changes coming, just how do you kind of manage your generation to retail matching, so to speak, in a way, given that we may have some structure changes and other things? Is there -- do you have a way to make sure that there's going to be an ability to kind of reflect that appropriately?

Well, I mean as I said before, we are maintaining our integrated approach as we're moving closer to the customer. I think I said it in the past that generation, the portfolio of generation that we have has to help us better serve our customers. So when you take a step back, obviously, owning physical generation, it is important. But we can get some of the characteristics of physical generation through bilateral agreements. It doesn't -- we don't have to own it all the time or always to be able to have those characteristics. We can actually structure some of those agreements, so we can benefit and utilize these -- the characteristics of physical generation.

I will say that the strength that we all saw in the system last week is giving us already lessons learned on how we should be thinking about counterparty performance, counterparty risk. And the team is already looking at the lessons learned on our commercial team, which, by the way, I just want to give a big kudos to both commercial operations and plant operations because they absolutely maximized the amount of generation that we were giving to the system and, at the same time, maintaining the stability and the balance on our portfolio.

So that's how I think about it, Steve. And obviously, our matching of generation and retail is always informed by market conditions. So it's not like set it and forget it.

And our next question comes from the line of Shar Pourreza with Guggenheim Partners.

So Mauricio, a couple of questions. Your testimony last week indicated that the company had several assets that come off-line during the storm like STP Unit 1 for a couple of days. To what extent the concentration of load shedding in Houston helped you in sort of free up the generation and sort of the purchase power? Just trying to really understand whether this is a product of really good risk management, some load shedding or a combination of the 2, especially as investors are weighing their thesis in the sector and sort of thinking about these type of events potentially reoccurring again.

Well, I think this is the result of really good risk management, commercial and plant operations, all around execution. We -- as we were approaching the storm, the commercial team took the necessary steps to strengthen our position going into the storm both on natural gas and power hedges. In addition to that, our plant operations people brought in almost 2,000 megawatts of generation that normally, in most of the circumstances, never run in the winter and we actually have it reserved for summer operations. So that's another testament of strengthening our position as we go into the storm.

And then as you were looking at -- as you look at our load obligations across the state, it's pretty well diversified between Houston and Dallas and the north. So I think it was a good, good solid execution with the right foundation in terms of the integrated portfolio and the necessary steps to get ready for it.

So Chris, is there something more that you want to add?

Yes. Shar, Chris Moser here. If you look at it, our strategy is to have a mix of physical gen and market purchases. And notwithstanding the problems we face, frankly, on both sides, right, with unit outages and then counterparty issues that we're working through, this strategy of diversified supply seems to have held together pretty well.

As we saw the forecast get colder and colder, we brought more generation, like Mauricio mentioned, not a seasonal layup, and we bought more power from the market. Like let's be clear, we were prepping to cover loads in the high 60s and low 70s, you know what I mean, in terms of thousands of megawatts load. We were also, don't forget, able to use our gas storage and transportation contracts and our ability to find and buy what I will politely describe as obscenely expensive gas in order to keep those gas units of ours producing the megawatts that the grid needed. I know that not everybody was able to do that, but the combination of our contracts and working out in the market, we were able to cover it.

So that is kind of how the whole thing worked out to where we think we're still within the guidance range, plus or minus the $100 million. So I would say our strategy of a mix, a bunch of different stuff paid off.

Got it. And then just one last one from me. The agencies seem to be kind of laser focused on sort of the events in Texas and they've issued the slew of watches. Mauricio, have you had any conversations with them on the event and sort of your broader trajectory for an upgrade, especially on today's better-than-expected storm impact? It seems that you're kind of book ending '22 potentially as [IG] versus the year-end '21. So just a quick sense there.

Yes. I mean I'll turn it to Gaetan, but I will say, first, we needed to prove the strength of our business model, I think we have. Then we needed to ensure that we deliver on our credit metrics, I think we have. So I think we have done what we needed to do. But if Gaetan has -- I know that Gaetan has a very open and continuous conversation with rating agencies. Gaetan?

Yes. That's right. Yes, Shar. Throughout the crisis, we had a continuous dialogue with the rating agencies, updating them on what we saw in the market and our liquidity position. And it was very transparent from our side, just like the dialogue we've had for years with them. And just like Mauricio said, I think now we've shown the resilience of the platform through COVID-19, through last summer, through this stress case, and we continue to perform and to be within the -- our targeted range for investment grade. So we're doing our side of the deal. We're going to continue the dialogue and expect that and totally hope that there's going to be -- that's going to bring us to investment grade by the end of the year again or early next year.

And our next question comes from the line of Angie Storozynski with Seaport Global.

Congratulations on the results. That's a huge relief. Also Gaetan, quite a timing to take over as CFO. I have to admit, if you survive this one, I mean, honestly, I'm going (inaudible) from here.

Thank you. Thank you, Angie.

But just one thing that I noticed, again, besides the stress that we've all felt throughout this last 2 weeks, is that -- we don't really know much about your Direct Energy portfolio. Meaning, you have some retail gas exposure that we couldn't either pinpoint as far as geography or exposure. So could you -- I mean I know that the Analyst Day is coming, but could you give us a sense how well you've managed that portion of your retail book, not just Texas power?

Yes. I mean the operations that we did was integrated NRG and Direct Energy. So what we're -- the evaluation that we've done, the assessment that we've done is across the board. I -- just keep in mind that Direct Energy, all their gas business is outside of Texas. Don't forget that. And remember, they will -- I will be also providing you during the Analyst Day a lot more detail around the redefinition that we're doing our business on moving closer to the customer of becoming more a consumer energy company where it's not just one product electricity, but the benefits of bringing secondary products.

And actually, I think what -- the impact that we saw on our business on this unprecedented winter storm validates that our core business is solid and it is a great foundation to start looking at other secondary products that can improve the customer lifetime value of our portfolio. So -- but we will be sharing more around our combined operations between NRG and Direct during Analyst Day.

Awesome. And just one point here. So you're showing us the EBITDA and free cash flow that's going to go away along with the divestiture of the northeastern assets and California assets. Can you give us a sense if that amount can be replenished by growth either by basically synergies with Direct Energy or organic growth in your retail portfolio so that's, at least directionally, there's no detriment to either EBITDA or free cash flow for the combined company?

All excess cash, Angie, that results from these, we're going to use our capital allocation framework. And I think that's how you should be thinking about all our excess cash.

And our next question comes from the line of Jonathan Arnold with Vertical Research Partners.

A quick one on -- just as you think about the -- obviously, you're saying that the range of outcome is still sort of plus or minus $100 million versus the guidance range. And you've talked about some of the still moving parts. Could you give us a bit more -- do you have a sense of -- is it the billing issue and not really necessarily knowing what usage was, metering, the swing -- the biggest swing factor or credit or ERCOT? Just a little more sense of just what we have to know. And I'm curious as where you think -- how soon it will be before you really have a good sense of some of these metering issues.

Well, I mean, first, I will say is that I think we have a pretty good sense. I mean the team does shadow settlements and in -- with respect to how much load we serve. But obviously, we don't have -- these are preliminary estimates. We don't have final numbers. So I feel very comfortable that the assessment that we have made on this, I would say, 3 big categories, the customer meter and settlement data from ERCOT, the probable counterparty risk and the expected ERCOT default. So that's what you should be thinking about, Jonathan. I mean these are the 3 big drivers. And I feel that the team has done a pretty good job in terms of getting comfortable with it, which is why we feel that maintaining our earnings guidance is appropriate. And then we also perform a stress test, and that's why we're providing yield at plus/minus $100 million.

So I think that's the -- I think the team has done a lot of information here. I mean -- but I mean there are things that have to run their course. I mean you know the settlement data from ERCOT, you have initial 7-day settlement; then you have another settlement, the 55 days; and then the final one is 180 days after. So you just have to -- the process needs to run its course, but this is not something that we don't do. Every day, we run a shadow settlement process. So that's why we're comfortable with it. But I will say that we just have to wait until we have more information on these 3 big categories.

And maybe, Mauricio, if I could. Just the -- when you say plus or minus $100 million, are you talking sort of relative to your -- where your point estimate, where you think you are today? Or should we be thinking of that as sort of in addition to the $200 million range that there is in guidance?

I think it's the latter. So this is a plus/minus $100 million to the guidance range, okay? So that's how you should think about it.

Okay. And then just one quick one. Do you have a sense on timing for the Analyst Day before first quarter earnings or after?

Well, I was planning to provide a date today quite candidly. But I think our priority right now is on ERCOT. As you all know, we run a pretty lean management team and we need to make sure that we focus on that. But I will give you a lot of time before we announce it. And my expectation is that it's going to happen in the spring of this year. That's correct.

But as to whether it's before or after the next call, that's still TBD?

TBD.

And our next question comes from the line of Michael Lapides with Goldman Sachs.

Mauricio, a lot of the issues that caused the events in Texas in mid-February were power related, which many of them were actually further upstream from the power plant, meaning gas infrastructure and other. How do you think about changes on that end that could impact this? I mean we couldn't -- the state of Texas could increase the winter reserve margin by a material amount. But if you can't get the gas there, it may -- we can run into the same issue. How do you think about the changes that the state may consider that are kind of outside the power sector but impact the power sector?

Well, I mean I think, as I mentioned, when I'm thinking about the steps that -- or the themes that are coming already in the wake of the hearings in Austin, I mean the first one is the hardening of the system. And I was very clear, the hardening of the system cannot only happen on the power generation side, it has to happen also on the natural gas system. I mean when 45% of our total generation capacity in Texas is fueled by natural gas, they're completely interdependent. And so that interdependency, it needs to be expanded when we're thinking about the hardening of the system, the winterization of the system.

The second thing is the communications. Obviously, there needs to be a lot more coordination between natural gas and power. And just like we talk about fuel diversification on power generation, we need to be thinking about redundancy on critical parts of the gas system like compressor stations. Does it make sense to have a back-up generation? What are the standards for winterization at the wellhead? I mean there is a number of things that can happen on the gas system side. And that will also -- we need to review the winterization protocols on the power generation side.

I mean the last time there was a recommendation was in 2011, and the wind -- the storm in 2011, I mean I have this stat that I think puts things in perspective. The 3-day stretch temperature, this winter storm I think ranks as the third coldest in the last 130 years. 2011 was the 60th. So I think that should give you a pretty good context in terms of what was the baseline that was used for the winterization of the power generation. And I think there's going to be a conversation about rebaselining that. So some of that is going to happen.

And I think it has to be also beyond power generation. It has to be around the customer and the communications with the customer. I mean when you're talking about power outages and rolling power outages, first, you need to make sure that you communicate with the customers. The TDUs are responsible for implementing these load shares at the direction of ERCOT that is balancing the system. And so do we need to review the protocol in terms of how that is implemented, what is the communication protocol between the transmission and distribution utilities and the retail energy providers that have the relationship with the customer. So all of these things are going to have to be taken into consideration. And I think I have to say, I mean the Texas legislature is really doing the right thing in terms of doing this exhaustive and comprehensive root cause analysis.

Got it. Mauricio, one other question, just a quick follow-up. Does this change your view on the need to be the one who owns the generation to serve your retail load? Meaning can we see NRG add generation to the portfolio, especially dispatchable generation, to ensure your teams control the operations that are needed to serve your retail customers?

I mean I think, as I said, the characteristics of physical generation can be achieved by a contractual arrangement and not necessarily by ownership. And I think there are some good lessons learned in terms of what are the additional, perhaps credit and performance clauses that need to be part of that agreement. And I know that the team is already doing here -- our commercial, our credit and risk management team, our legal team, they're already looking at the -- what are the provisions that we need to have in this type of contract, so we actually can utilize all of these characteristics of physical generation.

And this does conclude today's question-and-answer session, and I would like to turn the conference back over to Mauricio Gutierrez for any further remarks.

Thank you. Well, I appreciate everyone's interest in NRG and look forward to talking to you in the future. Thank you.

Ladies and gentlemen, thank you for participating in today's conference. This does conclude the program, and you may all disconnect. Everyone, have a great day.