NRG Energy Inc (NRG) 2016 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the first-quarter 2016 NRG Energy earnings conference call.

(Operator Instructions)

As a reminder this call may be recorded.

I would now like to introduce your host for today's conference Kevin Cole Head of Investor Relations.

Please go ahead sir.

Thank you, Christy.

Good morning and welcome to NRG Energy's first-quarter 2016 earnings call.

This morning's call is being broadcasted live over the phone and via the webcast which can be located in the Investor Relations section of our website at www.NRG.com under presentations and webcasts.

As this is an earnings call for NRG Energy any statements made on this call that pertain to energy yield will be provided from the NRG perspective.

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 everybody to review the Safe Harbor in today's presentation as well as the risk factors in our SEC filings.

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 a reconciliation to the most directly comparable GAAP measures please refer to today's press release and this presentation.

Now with that I'll now turn the call over to Mauricio Gutierrez, NRG's President and Chief Executive Officer.

Thank you, Kevin, and thank you everyone for joining our call today.

Joining me this morning is Kirk Andrews, our Chief Financial Officer.

Also on the call and available for questions we have Elizabeth Killinger, head of our retail business, and Chris Moser, head of operations.

We are off to a really good start for the year.

Our financial performance was strong for the first quarter allowing us to reaffirm guidance for the full year.

We are making significant progress in our priorities of reducing costs, replenishing capital and deleveraging the business.

And importantly we are bringing certain people our platform with the conclusion of the GreenCo process.

So let me start with our first quarter results.

NRG delivered $812 million of adjusted EBITDA under very challenging marketing conditions.

We remain focused on our day-to-day operations achieving top quartile safety performance, good availability across our generational fleet and stable results from our retail business.

All of these combined with our opportunity hedging program mitigated the impact of the very weak wholesale prices that we experienced during the quarter.

These results illustrate the strength of our platform and the unique value proposition that NRG offers.

We are making good progress in our commitment to deleveraging the business.

We retired $229 million of NRG debt or approximately 30% of our 2016 targets.

Not only are we on track with our original plans, we have expanded the total capital available for deleveraging to $1.3 billion after adding $253 million from our Midwest generation capacity monetization financing which Kirk will provide additional details on during his remarks.

Finally this quarter we are taking another important step forward in simplifying our business as we concluded after much consideration the GreenCo process.

With the reintegration of business renewables last quarter and now the resolution for our home solar and EVgo businesses which I will cover in more detail in a few slides, we have turned the page on this period of uncertainty and now are focused on executing our plan.

On our last call I spent some time talking about the merits of diversification as a necessary condition to succeed in the future of the competitive power industry.

Today I want to expand on the multiple levers that NRG has to deliver value to our shareholders.

Now turning to slide 5 I have outlined the three key macro levers that describe the earning potential of our business.

Over the years we have successfully repositioned the Company away from solely relying on energy margins to other more stable and predictable sources of revenue, so let me start with the first lever which now represents two thirds of our economic gross margin.

This comes from parts of our business that are either not directly correlated to or that are countercyclical to the price of natural gas including our retail business, contracted generation and capacity payments.

This lever of our business provides a stable base of predictable and visible earnings potential, a quality that differentiates us from many others in our industry.

And we do it at significant scale across all three areas.

Keep in mind this base is also growing given market trends in renewables and contracted generation where our relationship with NRG Yield will continue to be a competitive advantage in the future.

Now let's talk about the second and third levers that comprise the other one-third of our economic gross margin which is directly tied to the price of gas and power.

This portion's relative share has declined over the years given the prolonged weak price environment.

But we have deliberately maintained upside through fuel diversity as I believe the current gas price environment is unsustainable in the medium to long run, and we want to be there with scale when the market recovers.

The second lever is what I refer to as the fuel spread.

This is the traditional way we have made money selling coal, oil and uranium at gas prices.

It is effectively a synthetic long gas position.

For those of you who invested the E&P sector we are long roughly about 3 BCF a day of gas.

So for every $0.50 move in gas prices our portfolio has the potential to flex up by $0.5 billion in additional gross margin.

Let me be clear, we're not gas agnostic and don't want to be gas agnostic as we believe current prices are not sustainable.

The third lever is our power spread or heat rate exposure.

As power markets tighten due to retirements or low growth we maintain significant upside to increasing power prices as we have the largest competitive power portfolio the country with close to 50,000 megawatts of generation with both geographic and merit order diversification.

So when people ask me why I'm convinced we have the right platform to be the leader in the competitive power space today and into the future this is why.

Success in this industry is all about diversification of the business and core operational excellence.

Our platform is designed to deliver results even in a difficult market, and given how unpredictable the markets can be, having stability in our core platform is critical.

At the same time our leverage to any market recovery should be embraced not ignored, because it's quite substantial.

And when you couple these dynamics with our commitment to strengthening our balance sheet and streamlining our costs, I have no doubt that NRG's built to thrive under a variety of market conditions.

So moving on to the next slide I want to touch briefly on key developments across our markets.

We are encouraged by recent actions from regulators in support of competitive markets.

We are pleased that FERC has stepped in to effectively stop the out of market TPAs for AEP and FirstEnergy in Ohio.

It is also encouraging that the US Supreme Court decided to invalidate Maryland contract created for the sole purpose of suppressing capacity prices.

In PJM the transition to the capacity performance product has brought higher capacity payments in exchange for higher performance commitments as we have pivoted our suite accordingly.

Our program of transforming coal plants to gas was undertaken with an eye towards becoming a provider of reliability.

In Texas we are optimistic in haircut as we see up to 9 gigawatts of coal-generation at risk due to upcoming environmental regulations and continued strong growth.

In addition we expect market changes to ORDC with the purpose of increasing prices to better reflect scarcity conditions.

And in the West while the Aliso Canyon issue will present reliability challenges for the California ISO over the next year, we do not expect this issue to have significant impact to our generation portfolio since most of our revenue in California is supported by TPAs and RA contracts.

Also our newest merchant plant Sunrise is supplied off the Current River pipeline and thereof not impacted.

We hope this becomes a catalyst to address gas power for the nation and fuel cost recovery issues that are much needed in California.

Turning to slide 7 let me now discuss the details around the conclusion of the GreenCo process that we started in September of last year.

Last quarter I explained that there were three objectives we sought to accomplish in this process, maintain our capability to take advantage of renewable trends at appropriate investment returns, incorporate all of our businesses into our financial results and to minimize the use of the $125 million revolver.

Today I'm here to tell you we have met our objectives and have concluded the process.

To do a quick recap, beginning last quarter we reintegrated business renewables which allows us to maintain a strong position in the renewables market.

This business is now fully integrated, and I will be updating you on its progress in the months to come.

Moving to residential solar, we undertook a comprehensive strategic review process over the past six months to determine the best course of action to realize value, to minimize capital needs and like business renewables ensure we do not lose the ability to meet renewable energy demands across all types of customers.

While our original goal was to secure permanent capital and deconsolidate the enterprise, we were not able to move forward in this direction in a way that met all our objectives.

Today we are announcing a change in our approach to residential solar that will allow us to meet them.

First we are both streamlining and simplifying the organization by significantly lowering the cost structure and focusing in markets where we have a competitive advantage.

Residential solar will become a product in our retail offering, and we intend to fully integrate into our retail business by 2017.

Second, we are changing our business model to focus on origination, installation and direct third-party sales which will allow us to simplify financial reporting by providing immediate revenue recognition.

I am pleased to announce new partnerships with both Sunrun and Spruce Financial which will allow us to execute on this plan.

Our approach comes with significant changes in our overall organization, cost structure and business model.

This model allows us to maintain our 2016 financial guidance as we transition the business throughout the remainder of 2016 to be at least an EBITDA breakeven business by 2017.

While this is not a business you can expect to hear about each quarter our strategy for this business is important to our organization allowing us to maintain a viable yet rightsized structure so that when the haircut economics are viable we can offer residential solar to our existing 3 million customers.

We have also concluded the strategic review process for our electric vehicle charging network or EVgo.

I am announcing today the sale of a majority stake of this business to Vision Ridge Partners.

NRG will receive total consideration of approximately $50 million with $19.5 million up front available to NRG and $30 million remaining in the EVgo platform.

In addition NRG has an earn up potential of up to $70 million through 2022.

Under this structure NRG will have -- will not have any ongoing capital commitments to EVgo other than its obligations under the California settlement.

With the closing of this transaction EVgo results will no longer be consolidated into NRG financial statements.

With the conclusion of the GreenCo process the $125 million revolver is no longer necessary and will be eliminated as we move forward and execute on our new plans.

On slide 8 I want to provide you an update on the great progress we have made in streamlining our cost structure.

We are on track to realize $250 million in recurring cost savings in overhead and O&M, and we have made significant progress in our new fornrg program targets.

This means that over the next two years we will have taken an impressive $400 million in total costs out of the system.

Additionally you will be able to track these costs in our disclosures to see our progress as we move through the subsequent quarters.

While I am very pleased with our efforts today, I expect that we will be able to find even more opportunities to reduce our cost structure as we continue with our remaining asset sales, the integration of the residential solar business and our push to find even more opportunities to streamline the organization.

So with that I will turn it to Kirk for the financial review.

Thank you, Mauricio, and good morning, everyone.

Beginning with the financial summary on slide 10 NRG delivered $812 million in adjusted EBITDA and $249 million in free cash flow before growth in the first quarter of 2016.

Having now concluded the GreenCo process, our financial results and our guidance now include both EVgo and the newly restructured residential solar within our corporate segment which is part of the generation and renewable subset of our consolidated guidance.

With all businesses now included we are reaffirming our 2016 full-year guidance for adjusted EBITDA and free cash flow before growth.

During the quarter we continued our deleveraging program and have now retired a total of $229 million of NRG corporate debt year-to-date through May 4 leading to an additional annualize cast interest savings of $16 million.

Finally to update our progress in achieving our target of $1 billion in incremental consolidated available capital which was announced on September 18 of last year, NRG has now completed a non-recourse monetization of future PJM capacity revenues from our Midwest Generation fleet for cash proceeds of $253 million.

This transaction which will be accounted for as a non-recourse debt financing with no impact on adjusted EBITDA represents the final component of our plan to free up $1 billion of 2016 capital leaving only the balance of our $500 million asset sale target, and we expect to complete this over the balance of this year.

Turning to slide 11 the MidWest Gen non-recourse capacity monetization proceeds of $253 million increases our 2016 capital available for allocation by $210 million versus our prior expectation as we reviewed during our year-end earnings calls.

The remaining $43 million in financing proceeds represents the acceleration of capacity revenues within 2016 which were already included in the NRG level free cash flow before growth guidance mid-point which was part of the $1.488 billion in 2016 capital available shown in our year-end earnings materials.

Including the MidWest Gen proceeds total 2016 capital available for allocation now stands at approximately $1.7 billion at the NRG level.

We expect to allocate this incremental capital to further advance our deleveraging efforts or alternatively to repay our convertible preferred stock which based on the conversion price relative to our current share price presents a compelling potential opportunity.

The drop-down of NRG's remaining stake in CVSR to NRG Yield continues to represent an additional opportunity to further supplement NRG level capital available, and we intend to offer this remaining stake to NRG Yield during the quarter.

Finally liquidity stands at $1.9 billion as of March 31 which includes $589 million of cash at the NRG level.

Which has since been supplemented with the proceeds from the MidWest Gen capacity monetization which closed just following the quarter end.

Finally turning briefly to slide 12, our continued progress on deleveraging keeps us on track to bring our 2016 corporate debt to corporate EBITDA ratio below our target as we position NRG's balance sheet to maintain adherence to our 4.25 times target ratio even through a continued low commodity price cycle, and we will continue to update this analysis as our debt reduction program progresses.

With that I'll turn it back to Mauricio.

Thank you, Kirk, and in closing I wanted to remind everyone of our priorities in slide 14.

This is the scorecard that I will share with you throughout the rest of the year.

As you can see we have made considerable progress in just the first few months of the year.

Addressing the GenOn debt is among one of our highest priorities given the overall debt levels and maturities in 2017 and 2018.

We are actively evaluating alternatives to optimize the capital structure with a focus on maximizing value for all stakeholders.

With this objective in mind we expect to be engaging in discussions with GenOn creditors as a part of this process in the near term.

As we evaluate alternatives, we remain committed to our prudent balance sheet management principles including maintaining our target corporate credit metrics.

We remain focused on executing our current strategy, and with the reintegration of renewables, we are now in a position to reinvigorate the development pipeline and provide certainty to NRG Yield's growth potential.

I believe we now have all the pieces to move forward and demonstrate the value of our integrated platform.

So with that, operator, we are ready to open the line for questions.

(Operator Instructions)

Stephen Byrd, Morgan Stanley.

Hi, good morning.

Good morning, Stephen.

I wanted to delve into the relationship with Sunrun and Spruce that you mentioned.

Could you just walk through the roles of NRG and then your two partners just so I can understand better the nature of that relationship, what each party brings to the table and what this business looks like for you going forward?

Sure, Stephen.

I think the best way to think about it is we are going to be focused in the area that we believe we have a competitive advantage, that is in selling the system and installing the system.

Once we do that we have an agreement with Spruce and Sunrun to monetize the system to monetize these leases into their platform, so it is a different way of -- the way we have done it in the past if you recall we were -- before we would drop it into yield, but it would be consolidated NRG as a whole.

Now basically the entire lease goes to our partners.

Understood.

So the assets won't go to NYLD, but -- and your partners will monetize it so would you receive effectively and upfront fee for the value you are creating by acquiring a customer or would there be an ongoing cash flow to you?

This is Kirk.

The way to think about this is the cost of the system which is normally in the traditional construct you think about the CapEx necessary to put a given system in place.

The way to think about that in this contract is that is basically cost of goods sold.

And the revenue is the price that Sunrun and Spruce pay us for that particular system.

So rather than seeing proceeds come in in terms of a return of capital and CapEx go out in advance of that, that is now going to be revenue which is what we will receive for lock, stock and barrel the entire new system to Sunrun or Spruce.

And then they will also retain the ongoing obligation to manage and operate the system O&M and the like and what was formerly our capital expenditures would be COGS.

So think about it we are migrating to a gross margin model rather than a gain on sale model if you want to think of it that way.

Yes, that's very clear.

So, Kirk then every quarter as you get new customers and you sell those assets to Sunrun and Spruce then that's revenue in terms of the proceeds you receive from them.

Every quarter your operating used to be CapEx are truly COGS that's clear.

Okay.

And I just wanted to shift over to, Mauricio, what you had said on GenOn at the end.

I know we can't predict what the outcome will be of those discussions, but it is a clear priority that if there were to be an outcome that outcome needs effectively to be consistent with your overall credit metrics of NRG as a whole?

Absolutely Stephen, and I said that before.

I want to make sure that I am clear.

We have to maintain the credit metric targets that we have at NRG and adhere to that principle in any of the options that we are going to be evaluating.

As I said I would like to simplify the message.

In the spirit of that, we need to look at simplifying also the capital structure.

We need to address GenOn for that reason and because of the near-term maturities that we have, but we have to adhere to those prudent balance sheet management principles that we have.

That's great.

I'll get back in the queue.

Thank you very much.

Greg Gordon, Evercore ISI.

Thanks you guys.

Can you hear me okay?

Yes, good morning, Greg

Great so just to beat a dead horse a little bit on the resolution of the process it sounds like you created a reasonable way of keeping an option while stopping the losses.

But there's probably a lot of investors who were hoping that there'd be a clean break here.

So can you talk about the process in the market (technical difficulty) rooftop solar and those assets and why the option which frankly I think sounds like a good option is the best thing that you could to come up with?

Greg, we actually went through a process that took a significant amount of time.

During this time I think everybody knows that we knew that the conditions both in the capital markets and then through the beginning of the year were pretty challenging for both the residential solar business as a whole but also on the capital markets, so this was not the best time to be in the market.

We knew that.

That's why we were looking at selling a majority stake not all of it because we wanted to maintain the optionality on the Texas market where we think we have a significant asset in our customers to be able to offer them residential solar.

I think when you couple that with this change in the business model where it's effectively we sell, install and flip to a third party and importantly refocusing the business where we actually have been successful in the past and reducing significantly the cost structure.

We felt that combination was the best path for maximizing value for this business, and I think we provide that over the next 12 months we expect that business to be at least breakeven in 2017.

I've always looked at residential solar as another product in our retail offering.

It makes a whole lot of sense if we already have that relationship with the residential customer, and this is one of the products that they are asking for it that we provided.

And if we can't provide it in a way that is cost effective and that we can create value, we should have it in our lineup of product offerings.

I think the rationale is there.

I think the appetite from customers for rooftop solar is there.

We just needed to make pretty significant changes in the way we can structure the business model to ensure that it was quite candidly a profitable one.

And I think that's -- those are the steps we have taken.

Okay so first of all you are focusing on New Jersey, Massachusetts, New York, those are states where you have a presence.

That means you're going to stop spending gobs of money on advertising and feet on the street to try and break into markets where you don't have a presence.

Should I presume this also means you are merging the business line into the core business and getting rid of duplicative overhead, marketing staff and other things like that a making it sort of part of the product offering of the overall business as opposed to a separate freestanding business and those are sort of the ways you are reducing the cost (technical difficulty)?

Exactly.

Not only we are reducing all the costs by not being in states or regions where we don't have a core advantage, but making it part now of our retail business or in the process of making it to our retail business we will have significant synergies particularly in the marketing and selling.

If we now have already of relationship with a customer that is buying system power, we will be using those same vehicles to offer now rooftop solar and potentially decrease our -- the cost of selling that we had on a standalone basis.

So I think this way we create not only a lot of synergies by including in our retail business, but we also are being very disciplined in terms of the size and the scope of this business as we transition through this period and importantly maintain the option to if this becomes viable in Texas we can offer this to our 3 million customers because that to me is the price.

That is the goal.

Great.

One more question, and then I'll go to the back of the queue as well.

You made the decision to bring some cash flow forward by monetizing these capacity payments.

Theoretically cash in hand today is better than cash in hand a year or two from now especially if you are in a position to aggressively delever the balance sheet.

But, Kirk, can you talk about what you are foregoing in the future to get that cash today?

How much financing costs are you incurring, and do you see that as working given the market opportunities to retire debt, and where is your debt currently trading is it still a big discounts or has it improved?

Sure I'll try to cover all that, but it I miss a piece of your multi-part question you can remind me.

But as to the MidWest Gen financing the answer to your question is it worth it, yes.

As I think we disclosed in the press release certainly in the queue the cost of just under 4.5%, and that is basically the way to think about the cost of financing.

The way that it works mechanically is you are basically monetizing today the discount and the implied cost from an interest rate standpoint is that kind of 4 1/2 type costs relative to the opportunities certainly that we have and even relative to the path we were on exploring previously which is the term loan D market.

We see that as an attractive cost as you well put it to bring cash forward today to take advantage of opportunities and obviously get ahead in our deleveraging progress.

I mean certainly we are focused on doing that, but we are cognizant of the fact that right-sizing the balance sheet is important today so that we can preserve flexibility for the Company tomorrow.

So this $250 million, net $210 million as I mentioned for 2016 is an important step in that direction for us.

As far as our overall debt is concerned our long-term notes are still trading at a much smaller discount.

They have accreted largely closer to par even on the long dated maturities which certainly from the standpoint of opportunistically purchasing debt at a discount makes it more expensive, but as you well know we are a serial issuer or serial roller of debt from a refinancing opportunity standpoint.

So that certainly I feel a lot more comfortable with what that means in terms of the barometer and the confidence that the high yield market has and the quality of our credit I think underpinned by what we're on the path to do and driving those ratios down and also giving us greater flexibility on the refinancing side.

So in the total package I like where we are today.

I think we've probably seen 350 basis points of rally on the long side just since our last earnings call.

Great.

Thanks, guys.

I'll go to the back if I have more.

Angie Storozynski, Macquarie.

Thank you.

I actually have a question about your sensitivity to gas and heat rates.

I think we've all struggled with trying to gauge what is the correlation between heat rates and gas especially in Texas and also how linear this correlation with gas is especially for the GenOn portfolio.

You're showing a movement of $0.50 and gas, and I'm basically trying to understand how you are showing that sensitivity, because a $0.50 move in gas presumably has little effect on GenOn's assets.

Angie I'm assuming that you're talking about the slide 5 where I put the sensitivities for the entire portfolio.

Let me just -- this is the entire portfolio not just coal and nuclear which has been our traditional disclosures.

But I guess in the spirit of providing more visibility and clarity to the sensitivity on commodities I included the gas and oil portfolio as well in this sensitivity chart.

The way to think about my remarks of moving the value of the portfolio by $0.50 $0.5 billion is an open basis, and this is based on economic generation that we can see today at current markets.

So as you can appreciate that economic generation as commodity prices move will increase, and your sensitivity to the same $0.50 move will be greater.

Desensitivity basically reflects the economic generation that is exposed at current market.

So I don't know if that at least provide some clarity in terms of what this number is.

Now in terms of the GenOn I would say that it's pretty sensitive to increases in natural gas.

I'm not sure I --

I understand, but I'm trying to say a $0.50 increase in natural gas for GenOn doesn't necessarily mean that a number of those plants are now becoming economic right and yet $1 increase in gas would make a number of GenOn assets economic.

So I am basically trying to see how to capture that sensitivity which is clearly accelerating as gas prices rise.

That's fair.

The only thing I would say is as you recall in particular on the GenOn complex, but this is in general to both portfolios for GenOn and EME we already went through a pretty comprehensive asset optimization process where we converted some of these coal plants that were very sensitive to energy prices to natural gas in affect pivoting the revenue driver from energy margin to capacity margin.

So, I would say that some of that is already captured in the GenOn complex.

I don't know if that was part of your comment that perhaps the GenOn complex is not as sensitized to natural gas because of those fuel conversions, but $0.50 makes some difference.

It is not -- you will be I guess adding economic generation as prices increase but from current levels where we are clearly it's not as significant as it would be in a different market scenario.

And how about the he link between gas prices and heat rates?

I'm particularly struggling how to call it in Texas, so you are showing the movement and gas prices $0.50 and long heat rate can you tell us what's the correlation between these two in Texas and PJM or across the portfolio?

Look I mean I think for simplicity we have provided this as a linear sensitivity, so $0.50 move on gas, half a heat rate move on power.

I mean clearly when gas prices increased heat rates tend to be compressed because you want to keep sparks [bud] content, and the reverse happens when gas prices decrease.

We have not provided that comprehensive correlation just -- I guess just for simplicity.

Not that we don't have it, because the way we actually model our portfolio when we account internally for different changes in commodity prices.

But for this type of disclosure we are trying to make it linear and something simple that people can just have a rule of thumb.

Okay, thank you.

Steve Fleishman, Wolfe Research.

Hi, good morning.

Just a couple clarifications on the EME money forwarding, are you going to have to put money back into Edison Mission, MidWest Gen back in 2018, 2019?

I'm sorry Steve are you saying some sort of environmental CapEx or asset optimization?

No.

I'm sorry the forwarding of the hedge value the capacity value excuse me.

Not necessarily putting money in, but as I said before its literally a shift forward.

So one of the points I wanted to make clear is because of the accounting convention behind how this particular capacity monetization is treated.

It is treated as a financing which is why the EBITDA or capacity revenue component of our revenue line is unchanged, but the overall cash flow effect is we are getting those proceeds today.

We'll have the capacity revenues tomorrow, but we will have an offset for principal and interest payments that is associated with the payments if you will to the third party.

But there isn't an injection of cash per se.

It's just that the capacity revenues serve to pay the financing cost principle interest.

At least directionally or the way back is going to play out in the financials as we go forward if that makes sense.

Okay, but from a cash flow standpoint in 2018, 2019 I assume you lose that cash at --

Yes.

The direct answer is yes.

You are pulling the cash forward today which means it won't be there tomorrow.

Okay.

And then just on the thinking on GenOn, so the support payments which I think are part of your NRG EBITDA, in the event that we go to the scenario where you do have to let it go, can you cut cost significantly to offset the loss to that revenue?

Yes, Steve, I think the rule of thumb is it's about 50% of the cost that we --

It is a significant portion of that number overall.

As you recall if you go back and look at our overall corporate G&A before GenOn and after GenOn, the costs associated with managing that overall portfolio and providing those services is a significant portion of that shared services payment as we move forward.

So there is an offsetting reduction in cost for academic purposes imagine that shared service payment away.

It isn't an absolute.

Okay great thank you.

Praful Mehta, Citibank.

Thanks so much.

Hi, guys.

Good morning

So, Mauricio, you made the point on natural gas prices and the fact that you're long on natural gas which makes sense.

Just want to understand how you look at retail when you talk about it because you mentioned retailers countercyclical which we all understand it is, so when you look at EBITDA sensitivities to natural gas prices how do you figure in retail and the sensitivity of retail being countercyclical to that EBITDA sensitivity?

We have said in the past that with -- in a rising natural gas environment which theoretically will also increase in power prices our retail business will contract in the margin.

That will be more than offset on the pick up that we will get on the generation side.

When we think about that integrated platform we have actually smoothed some of the peaks and valleys by putting it together particularly in Texas which is important because of the market construct, the energy only type of market construct that is the way I describe it is feast or famine.

It's almost a digital market, prices are very low or prices are very high.

We feel very comfortable with that value proposition.

And we feel very comfortable that if gas prices rise the impact or the negative impact that happens in retail is more than offset by a significant multiple on the generation side.

Got you.

Any order of magnitude impact on the retail versus the wholesale?

I don't think we have -- we've provided a band of our retail business in the past, but I don't believe we have provided a sensitivity to a percentage move in natural gas or power prices.

But that is something we could potentially look at in the future.

I'm making a note of that.

Okay, great.

That would be very helpful.

And just quickly secondly I was looking at your hedge disclosure on slide 24 and the Texas and south-central seems to have a weighted average hedge price it looks to a drop for 2017 by about $5 a megawatt hour.

I just want to make sure I understand what's driving that?

Yes, look, what we did is we layered in additional hedges for 2017.

If you look at the hedge percentages from the last quarter to this quarter, I think we increased by I want to say 25% to 30% our total hedge price.

And I think that is the effect of just increasing our percentage hedge at some lower prices which reflect current market, and we did it in the back of the recent rally that we have seen in the natural gas market.

As I have said I continue to be bullish in 2017, but we need to be prudent in terms of our hedge profile for a potential extension of this trough in the commodity cycle.

As we have been in the past we are very opportunistic, and we felt that with this recent move it was a good time to layer in additional hedges.

Now, I think that only pertains to our coal and nuclear fleet.

It does not have our gas portfolio reflected in this.

Chris, do you have any additional comments?

I think that's true.

I think that's a factor of some of the key great moves we seen on the expansion and how you calculate gas sales when you translate them into heat rate sometimes you get a bit of a funny move like that.

As you can see the average equivalent natural gas price is decent right there at $3.52, so I think it's an artifact of some moving around on the heat rate side.

Okay.

Thank you guys.

I will get back in the queue.

Michael Lapides, Goldman Sachs.

Hey, guys.

Two questions for you and congrats on a good start to the year.

Just looking at some of the detail you provide on the Texas market in your market outlook on slide 21 and beyond.

Just curious the units you view at risk, what do you think the catalyst is?

What do you think that timeframe is for when the owners of some of those units have to start making decisions about when to retire?

Is there a forcing function, or could this drag out longer than people expect?

Look I'll give you $0.2 on it before I pass it on to Chris for -- but clearly the current commodity or power price environment is already a pretty good catalyst for starting that conversation.

We announced at the beginning of this year that we were going to -- our intention was to retire one of our units because of the absolute lack of scarcity pricing and the failure of ORDC to provide the right price signal in what we consider the tightest market in the country.

So I would say that you have different catalysts right now brewing.

The first one is lack of or this very low power price environment in Texas.

The second one is the regional case regulations, and then the one hour SO2 requirements.

When you put all those three together I think this is what we tried to show in this slide which units are exposed to either one, two were all three, and I think that will inform the decision of asset owners in terms of the economic viability of their units.

But, Chris, do you have --

I don't know that I have a lot to add to that.

I think is you are sitting there and you're thinking god, I have to put new scrubbers on big Brown and Monticello, and then we still haven't seen exactly what the damage is from those in terms of we haven't yet seen the final one hour SO2 impact, I think that combination has to be daunting.

What's the time line -- when do plants have to comply with both those?

Well, Regional Haze will be later 2019, 2020, and the one hour SO2 I don't have a good answer for you on, because I think it is still being baked.

Got it.

And when you think about nuclear plants in Texas, we're seeing retirements of nuclear plants in some of the markets that have capacity payments.

Can you talk about weather South Texas project is generating free cash flow and whether you think nuclear plants are facing some of the same challenges in Texas that we are seeing elsewhere in the country?

Yes, Michael.

I think all baseload, the traditional baseload generation is facing some challenges at $2 gas prices.

I think what -- from our perspective, and we don't provide specific information on a plant by plant basis, but I will tell you in Texas we actually have a higher threshold than if we were a stand-alone generator, and the reason why is our integrated model.

We actually achieved significant amount of synergies and value by pointing generation to retail.

We avoid a lot of charges.

We avoid friction costs.

So we have this higher threshold when it comes to evaluating the economic viability of the plant.

But again I don't think we can take a -- we can make a decision of retiring a plant based on one month or three months of very low commodity prices which to be fair we have very effectively mitigated with our hedging philosophy and strategy.

What we need to do is we need to look at it in the context of all the dynamics in that market what are the prospects for each of those plants, and what exactly is what that plant provides to the system that eventually will be captured in the prices.

That's I guess where I see that.

What I will tell you is that we have an absolute commitment to operate plants that our economic.

We have I think a pretty good track record in terms of retiring plants where the system doesn't need them in the past, over the last 10 years.

And even since the beginning of this year we have retired close to a gigawatt of generation in Western New York and Texas because the market just doesn't support it, and because we felt that the economic prospects in those particular markets were not going to support it.

I think investors should rest assured that we will make the right economic decision, but we need to make sure that we go beyond the next month, and we look at the prospects going forward.

Got it.

Thanks, Mauricio, much appreciate it.

Julien Dumoulin-Smith, UBS.

Good morning.

A couple questions a little details here on the resi solar piece just going back to that, how many megawatts do you expect to be able to monetize annually as far as a run rate?

And secondly on the EVgo piece can you comment will quickly what's the California payout still due, I imagine I think you'd said you retained that piece?

Sure, Julien, it's Kirk.

I'll answer the EVgo piece of that.

We probably got over the next four years about the good rule of thumb on the California settlement think about that order of magnitude about $20 million a year over the next four years.

It bumps around, but that's a good averaging, and then we would be completed in terms of our obligations in California under that settlement.

And, Julien, I think what you should be looking at on the home solar business is we're actually looking at the last six months of operation.

We don't have any grand aspirations in terms of the total sales and installations that we want to have for the year.

We are calibrating that to the historical levels.

I feel very strongly that our plan needs to be a plan that is achievable.

I'm not going to provide specific numbers, but what I will tell you is that I feel very comfortable hitting those targets, and I think with the agreements that we have with our partners we're going to be able to effectively implement this new business model.

So I think that's what I am comfortable disclosing to you Julien today.

Sorry just to be clear you're comfortable hitting which target?

What I am comfortable is on the financial numbers that I provided I don't want to go into the specific systems that we're going to be deploying.

What I said is that this business is going to be at least breakeven by 2017, and in 2016 the negativity that I have disclosed is mostly coming from this first six months of operation while we were running this business.

Going forward I think that turns into a breakeven value proposition.

But I don't want to provide right now specifics in terms of [mare] was deployed or systems installed.

I feel that the financial disclosures that we are providing will be sufficient going forward.

Got it.

And just turning to the PJM auction coming up here I just have to ask you put 140 to 160 as the analyst expectations, but what are your expectations and then specifically within that what you thinking about demand response the rice regulations and new supply [atree]?

Chris any comments on the BRA?

Yes, back on page 22 we discussed it a little bit.

We've seen some pretty decent numbers out of capacity markets in general across-the-board $7 and equal we like.

Obviously the last BRA in the 200s for areas where we have a lot of generation were fantastic results, and then the New York May spot market has been -- was a great [print] there in the face of a lowered load forecast.

We see a lower load forecast for the CP auction as well, so it's probably down year-on-year so that's why we through the analyst expectations on.

I'm not going to throw a number, our internal number out there but, look, I think it's reasonable to think it's going to be down some or moderate a little from the numbers we saw last time just because of the changes in load forecast.

And then you are right to point out there I think there are some pretty big wild cards out there in terms of hey, what does FirstEnergy do, what does AEP do, what kind of impact is RICE NESHAP going to have on those, and those are a bit of wild cards out there that could swing that one -- I think that those swing it directionally upwards compared to where it otherwise would be if you start pulling out some of the DR based on auto DR and then also look at FirstEnergy and AEP decide they retire those units and do want capacity obligations because they are concerned about whether or not this end run, this most recent end run they are trying around FERC works or not.

I think there -- that 6000 megawatts of stuff that's up in the air which arguably could have a bullish piece on it.

Will that be enough to offset the load change that they've had in the load forecast?

That remains to be seen.

But I hear you are emphasizing new supply or big swing into mana spots, right?

Sorry, Julien, say it again?

I don't hear you emphasizing a big move in new supply or demand response participation.

I think on the demand response side this is the last hurrah for the base capacity product, so we will see what happens on that side, but I don't think there's big swings either way on those two points.

Got it.

Thank you.

Jonathan Arnold, Deutsche Bank.

Good morning guys.

Hi Jonathan.

Mauricio, you mentioned at one point that you were going to start looking for incremental savings, and when we benchmark your SG&A against some of your peers, obviously you are a bigger company, but it does seem still to be a much more scaled number than maybe others have.

Can you give us some insight into what you see as the factors there and what sort of areas you might be looking at as you try to drive further cost savings, is it a presentational issue?

Right, Jonathan, no.

What I said in the past is I think it's not a fair comparison to put us against some of our generator peers, because they don't have the scale of our retail platform and our retail business.

I think on a generation -- our generational platform I will put it vis-a-vis anybody in our space but you need to take into consideration we have a retail platform that I don't believe anybody else on our sector has.

What we have done today, and what I tried to articulate today, is really to give you a comprehensive look at the entire cost structure that we have, one that you can actually reconciled with our financials and that you can hold us accountable going forward.

We have identified and either executed or in execution close to $400 million of cost reductions that I feel we all feel very comfortable that are very achievable, and we are making significant progress.

I think there are more opportunities as we integrate some of the business, specifically residential solar, into the platform, but I expect that we will be looking at other areas.

We now have a comprehensive continuous improvement program that over the years have been very effective under the fornrg umbrella, and we are extending that to the entire organization, so we are reinvigorating that initiative.

It is now company wide, and I expect we will come with additional savings under that framework going forward.

And as we start identifying them, I will provide that additional detail, but just -- I'm excited about where we are in terms of our cost reduction program.

We have made significant progress, and I think we run a -- we're going to be running very efficient organization here.

That is my goal, and again I think when it comes to comparisons you need to make sure that you compare apples to apples.

Do you think this next round you are alluding to is something we hear about in 2016, or is that more longer-term?

No.

I think it would be in 2016.

We are in the process right now.

I announced today the reintegration of residential solar.

We have identified as I said of significant cost savings I think fully integrates with retail.

I am sure there will be more.

We're looking across other areas in the organization so this is an area of focus and to be candid it is a reflection and it has to be -- it is an imperative in this commodity cycle.

So we are looking across not just overhead but also operations O& M, and that is an area of focus as we are seeing changes in dispatch profiles and changes in terms of how our units get compensated specifically moving from energy driven margins to capacity driven margin, so everything is on the table, and I think as I said it is an imperative in this current commodity market environment.

And maybe one quick one if you do move into Texas with the home solar business is it agreed that will be with the same partners under the same model or is that TBD?

I think that's a TBD.

Right now the partners we are focused in the three northeast markets.

I can't comment right now in Texas but I think it's a TBD.

So the deal you have was Sunrun and Spruce is Pacific to the three markets we've talked about today?

I think what I will say is that's where we are focusing right now, and our partners will support us on those three markets.

All right.

Thank you guys.

Thank you.

Brian Chin, Bank of America Merrill Lynch.

Hi, thanks and good morning.

Good morning, Brian

Just going back to the Midwest Gen capacity I get that you're just walking out for a lower cost of capital, but what I'm wondering is that $253 million does that cover the entirety of the Midwest Gen capacity?

Is there an ability to upsides that to a larger number?

Why wouldn't you potentially upsides that lower cost of capital financing?

Brian, it is Kirk.

What I'll tell you was no it doesn't include all of it.

The order of magnitude the little less than half.

There is maybe an incremental opportunity to do so, but that number provides us the amount of capital we thought was prudent right now given the opportunities we see on the deleveraging front, but it's a little less than half of the total amount of capacity, so think about maybe 1500 megawatts a year through the 2016-2017, 2017-2018, 2018-2019 timeframe.

Got it and then could you conceivably expand that for any of your assets in PJM East or potentially in California under resource adequacy constructs?

I can't really comment too much on California.

I think that's a little bit more complex, but the answer on the PJM East front is yes.

Added complexity there is obviously a lot of those assets are in the GenOn complex, but it certainly not impossible where that's concerned.

I think going back to Midwest Gen, certainly that is an opportunity that we'd revisit post the completion of the next round of auctions there in PJM.

Appreciate it.

Thanks for squeezing me in.

Thank you and that does conclude our Q&A session for today.