Welcome to the Dynegy Incorporated Second Quarter 2015 Financial Results teleconference. Please note that all lines will be in a listen-only mode until the question and answer portion of today’s call. At that time, you may press star, one on your touchtone phone if you have a question. You will be prompted to record your first and last name and company name for pronunciation purposes. I would now like to turn the conference over to Mr. Rodney McMahan, Managing Director, Investor Relations. Sir, you may begin.

Thank you, Kino. Good morning everyone and welcome to Dynegy’s investor conference call and webcast covering the company’s second quarter 2015 results. As is our customary practice, before we begin this morning, I would like to remind you that our call will include statements reflecting assumptions, expectations, projections, intentions or beliefs about future events and views of market dynamics. These and other statements not relating strictly to historical or current facts are intended as forward-looking statements. Actual results, though, may vary materially from those expressed or implied in any forward-looking statements. For a description of the factors that may cause such a variance, I would direct you to the forward-looking statements legend contained in last night’s news release and in our SEC filings, which are available free of charge through our website at Dynegy.com. With that, I will now turn it over to our President and CEO, Bob Flexon.

Good morning and thank you for joining us today. With me today are Clint Freeman, our Chief Financial Officer; Hank Jones, our Chief Commercial Officer; Catherine Callaway, our Executive Vice President and General Counsel; Sheree Petrone, our Executive Vice President of Retail; Dean Ellis, our Vice President of Regulatory Affairs; and Carolyn Burke, Executive Vice President of Business Operations and Systems. We posted our earnings release presentation and management’s prepared remarks on our website last night. Following a few opening remarks, we will devote the bulk of our scheduled time to your questions. Our safety performance improved during the first six months of 2015, and for the first time includes the workforce associated with our acquisitions that closed at the beginning of April. Following a successful winter preparedness program in which no weather-related injuries occurred, the entire fleet completed the equivalent summer preparedness activities with the goal of duplicating the success of the winter program. Adjusted EBITDA for the second quarter was $193 million versus $38 million during the same period last year. In highlighting just how important these recent acquisitions are and will be to Dynegy, the second quarter adjusted EBITDA contribution from the newly acquired businesses was $157 million. The location of the acquired combined cycle plants provide highly advantageous access to lower cost natural gas supplies that results in strong spark spreads, even in periods of low demand and low commodity prices. Power demand during the second quarter was adversely impacted by weather trends throughout our core markets. As can be found in the presentation slides, June temperatures were below average and precipitation was much higher throughout our core markets, with Illinois and Ohio recording the wettest June in over 120 years. Three PJM capacity auctions are scheduled to occur over the next few weeks. Dynegy is…

[Operator instructions] Our first question is from Greg Gordon. Your line is now open. Please go ahead.

Thanks. Great quarter, and thank you for the capital allocation decision.

Thanks, Greg.

I’m looking through your slides really quickly here, and I don’t see that you’ve tried to calculate it, but given that you’re confident that a MAC unit is a unit that must clear the ’16-’17 transitional auction, do you have a rule of thumb on what the EBITDA uplift would be on an annualized basis if all your CP eligible units just cleared at the last MAC price?

What we did, Greg, for that--and first of all, under the current design of the transitional auction, in our math we do see that the price, they’re going to need megawatts from the east to reach their target of 60% of transitioning the capacity product to the capacity product, and as a result you’re going to need the megawatts in the west and a good portion of the megawatts in the east to actually get there, so we do believe that’s where the price will be set. What we did indicate on Page 17 is a footnote that said for every $10 per megawatt day increase above the prior clear equals $40 million of EBITDA times the percentage of your megawatts which you clear, so you just have to make an assumption on how many of our, call it nearly 11,000 megawatts gets transitioned as the percentage that you’d have to apply to that. I would say that certainly we expect the vast majority of our megawatts to clear, but not all. There are some peaking units that probably won’t be in that clearing, so you have to put that bit of a sensitivity around there. But our average all-in price in the ’16-’17 auction, Hank, I think was around $70 or so--

Yes, it’s in the footnote, $67.

Yes, it’s in the footnote. So to the extent that you clear above that, that’s the math that you would do.

Okay, so max cleared at 1, or just around 120 in that auction, and your average price was 70, so we’re talking about at a minimum a $50.01 uplift on whatever percentage of your megawatts re-clear at--

That’s right, so that would be--if that was the math, that would be $200 million uplift times the percentage of megawatts we clear.

Right, annualized, so you get half of that in essentially Q3 and Q4 of ’17?

That’s right.

Perfect. Thank you very much. Have a good morning.

Thanks, Greg.

Thank you. Our next question is from Julien Dumoulin-Smith of UBS. Please go ahead.

Hi, good morning. Can you hear me?

Yes we can, Julien.

Excellent. So just a clarification on the adjusted EBITDA outlook that you gave at the time of the analyst day. Where do you stand mark-to-market on the $1.3 billion base case? I imagine that hasn’t moved much, but I just wanted to confirm that, given your guidance.

The only thing I’d say to that, Julien, the only, I’d say the most material movement would have been in the MISO coal fleet we’ve seen at the very far end of that range in terms of time, the 2018 time frame. We’ve seen some reduction in energy price there offset by lower coal costs, so that’s really where the only movement has been. That’s the majority of any movement that’s occurred.

Got it. Then if you’ll take that a little bit, you obviously talked about having some assumptions later in around PJM and MISO at the time of your analyst day. I just wanted to circle back to that, if you will, and make sure we’re all very clear about as a proportion of MISO versus PJM in terms of the assumptions you were making, you kind of alluded to a couple hundred million. I imagine the bulk of that is MISO rather than necessarily PJM, but I just wanted to get a sense if you could break it down percentage-wise of the couple hundred million.

I won’t put necessarily a fine quantitative number on it, but let just provide some further explanation of that. At the time of the investor day, where the rules of capacity performance were still being developed, we at that point had not made the assumption that it would be just one clearing price; it could be zonal. Since that point in time, the rules have obviously been finalized and it’s going to be one clearing price across the entire PJM network. So then what we had in our numbers around a PJM uplift was a fairly minor number, so now if you, even going back to the discussion with Greg, just assumed that it cleared where eastern MAC cleared last time at 120, it’s going to be a significant portion of that unpriced capacity, and then any difference which was the unpriced capacity for MISO would be what you would need to achieve to fill the bucket, are pretty modest amounts at prices that are less than capacity that we have already sold in MISO. So I think since analyst day, I think what’s different is that we had very little in there for the transitional uplift. It appears under the existing design that it’s going to be substantially--you would expect it to be substantially more than what we thought, which very much narrows the amount that you need to get from MISO to fill that unpriced capacity bucket that we talked about at investor day, and again at prices that are in the range or below what we’ve been selling capacity at.

And just to clarify, in terms of the MISO uplift, are the latest Joppa peaker, call them re-powering [indiscernible], are those eligible for capacity as well as energy margin? Just seeing expectations there.

Julien, this is Hank. Yes, the Joppa CTs are actually an external resource to MISO, but they can be offered in as capacity and energy into MISO.

Okay, so we can make an assumption that they receive at least some revenues from both sides?

Capacity and energy.

Yes. And then Bob, a last quick one here in terms of the share repurchase. Is there any ability to clean up large shareholder potentially? I’d be curious from a corporate governance [indiscernible], is there any restriction around cleaning anyone up who might be wanting to get out.

Julien, there’s not any restrictions. I would think the only thing - we’ve checked this internally as well - is that if you were to transact with an affiliate, in this case Franklin, that any agreement that would reach would need to be made public at some point in time. But there’s no restrictions - we can do private transactions, block trades and the like.

Excellent. Thank you very much. Congrats on the repurchase, and talk to you soon.

Great, thanks Julien.

Thank you. Our next question is from Michael Lapides of Goldman Sachs. Please go ahead.

Hey guys, just a bigger PJM question, not really a CP one but broader market. There seems to be--we all know there’s been a lot of coal plan retirements, but there seems to be virtually every week or so another announcement of a financing for a new combined cycle. Just curious for your view over the next three or four years, four or five years how much capacity of combined cycle you see coming online, and how you think that impacts both energy and capacity markets.

This is Hank. History tells us that only about 20% of the announced new build in PJM ever gets built, and over the last five to 10 years the average--it’s 4 to 5 gigs is what gets installed in PJM. So we would expect--it’s a normal response, given the bullish outlook on capacity performance, that new build projects would start lining up and going through their exercise. Again, we expect only a portion of those to be built. Concurrent with that, we expect a part of the purpose of the PJM capacity performance product is to weed out unreliable units, so as we discussed at investor day, it’s our view that concurrent with new builds arriving on the scene, that there will be retirements of assets that are not up to performance, up to CP standards.

Got it, okay. The other thing, and this is a separate topic, can you give an update just on your thoughts on the California portfolio?

Michael, not much has changed on the California portfolio. We’re still waiting to work through the gas delivery rate case that’s up in the air, that’s kind of a big pivot point on value of the facility, and still the timing around that, assuming that there’s no settlement, is the fourth quarter of this year. Once we have got clarity on the rates for transporting gas to the facility, it will really clear up the value of what Moss Landing is worth. Right now, again, if you make assumptions, minor movements in the assumption has a significant impact on the value, so we’ve got to get through that before there’s much different about California.

Much appreciated, guys. Thank you for taking my questions.

Thanks Michael.

Thank you. Our next question is from Steve Fleishman of Wolfe Research. Please go ahead.

Hi Bob. Could you talk maybe a little bit about the timing of buybacks relative to cash availability, and how much can you do sooner than later within this target by year-end ’16?

Sure. As an overall premise, we would never make a move on repurchasing shares if we felt it put our liquidity at a point that we’re not comfortable with, so anything we do is always in the context of never sacrificing the balance sheet. That said, when we look at our cash position now and our liquidity, we view that we can get, I would say, in the first half--I mean, for the balance of this year, we’ll put a pretty good dent into it. I mean, I think this year we could get maybe upwards to half of it done in a base case scenario, but in times like this when the equity value across the sector has done what it has done, this is when you take a step back as a management team and say, we have to double down our efforts on our PRIDE initiatives, particularly as they are around the balance sheet, and find ways to get more efficient cash out of the balance sheet and deploy it for things like this. So if you notice on our PRIDE slides on our balance sheet, it says 29-plus. That plus, we’re targeting to be a big plus, and Clint’s team is working on repositioning some collateral that’s out there to free up some cash, and if we’re successful in doing the things that we think we can get done in the very near term around collateral and some other things, we can free up additional liquidity that really allows us to hit the repurchases fast and in pretty good size. So that’s the question, but I think the slowest we would do is getting roughly half of it done this year, but I’m confident with the efforts that we’re going to do through PRIDE that we’re going to be able to do more than that. That will work itself out in the next few days or few weeks or so, but we’ll be starting the buyback into the markets as soon as we get into open periods, given where our equity price is.

Okay. Secondly, just on the year, the guidance for the lower half of the range, maybe could you just give us a little bit more? I think you said based on the forward as of July 21 and the like, and just what you’ve seen kind of even over the last month since then, three or four weeks since then, just how you’re feeling that within that range.

Steve, this is Clint. As you noted, the updated guidance views as of July 21 curves. Since then, we’ve seen some level of volatility in the curves, but no meaningful move, and I think when we look at the balance of the year compared to our previous expectations, really what you’re seeing is a relatively balanced impact across the fleet. I think given the hedge levels on our coal assets in MISO, you’re not seeing much movement there; but between PJM and New England, there’s a relatively balanced impact of the recent curves on those fleets. So I would say there are a couple plants, particularly Kendall and Brayton and a couple of others, that are kind of the lion’s share of that, but again more of a broad based move given what we’ve seen in the curves, really mostly through PJM and New England. But again, since we’ve re-run our forecast, we haven’t seen a meaningful difference in our expectations bringing it forward to today.

Okay, then lastly, you seemed to kind of hint at in the remarks, published remarks at opportunities potentially coming up on the coal side. Could you maybe give a little more color on what are some things that you might be able to do on coal procurement?

Yes, you’re talking for the existing fleet? I think around the coal side, first of all, there is a number of things of happening. Certainly the coal commodity price itself is really coming down, and you’re seeing now you can go and buy PRB - I think the producers are pretty much selling it at pretty flat at their cost, roughly about $11 per ton. So you’ve seen a pretty steep decline in that. Another benefit that’s offsetting kind of the inflator in your rail transportation contracts is what has happened with the price of diesel, and the price of diesel--Hank, you know the sensitivity off the top of your head on that?

Sure. Every $0.10 move in low sulfur diesel is worth about $5 million to us, and it’s come off about $1.00 per gallon since last year.

I would say that, Steve, the biggest opportunity that we have in this is similar to what we experienced when we purchased IPH. The reliability around the coal generation facilities that we purchased from Duke offers a substantial opportunity, and we had lower than expected capacity factors at those plants in the second quarter, because you think of some of the big plants - Stuart, Conesville, Zimmer, they have forced outages in high teens, into the 20% range, and the Ameren fleet was kind of like that at the same time. The Ameren fleet this quarter had a weighted average forced outage rate of, like, 4%, and part of our PRIDE effort is to drive reliability and we’re full speed ahead on doing those things for the Duke fleet. When you look at for the Duke coal fleet, the uneconomic hours of those fleets are very, very low. They’re basically always in the money, and these are big plants that just run, and we’ve got--you know, one of the big synergies here is driving this reliability where to take those forced outage rates in the 20% range and bring them down to where they should be, like we’ve been able to do with IPH where you have a quarter where the average is 4%. That offers substantial opportunity. Now, the lost opportunity cost in the quarter was about $25 million or so for the whole fleet, so given the low commodity prices, it didn’t really penalize us a lot, but it’s a significant opportunity going forward, particularly as you see power prices rise or you get into the high demand periods, and then obviously the capacity performance construct, it’s important to have the reliability. So we’re making a lot of investment and operating practice to do what we can to bring the reliability rates in line with where they should be, and I think that offers us the biggest opportunity on the coal fleet.

Great, thank you.

Thank you. Once again, if you would like to ask a question, please press star one. Our next question is from Andy Bischof of Morningstar Equity Research. Please go ahead.

Hi, good morning. In regards to your prepared remarks about the clean power plan, particularly in Ohio and Illinois, can you provide additional color on the measures you expect regulators to undertake to meet their average reduction goals that give you comfort that your coal plants will not be retired?

Yes, the states need to come up with their plans, and there isn’t really any state that’s going to go down the path of saying, here’s the rate performance that a unit has to do. You’re going to have to utilize, whether it’s the renewables or energy efficiency of whatever the case may be, to work down towards that average, and if you look at our fleet outside of Illinois and Ohio, the emissions rates of our fleet versus the targets that those states have to get to, we’re essentially a net--we generate less emissions than what their rates are, so you are a beneficiary or providing beneficial services to that particular state in terms of bringing the average down. In Illinois and Ohio where we have the coal plants, we’re above the targeted rates to get to, so for there it’s going to be working with state agencies, state implementation plans on kind of all of the above to get the blended rate to that level. Or, what a state may do is rather than thinking about rates but go to the mass requirement, which is probably the more likely circumstance, which then it’s a situation of using credits to help bring it down. In a market like Illinois, where you have so much coal generation, and particularly coal generation that’s on the margin, if you get into a credit type of scheme, then it’s largely going to be a pass-through because it’s going to be coal setting the price. In Ohio, that might be a little bit different because you’ve got more gas resources there. So it really is going to come down to--you know, we wanted to include something on the clean power plan because it’s obviously in the news this week and has an impact on us going forward. So that’s just really some high level thoughts - our efforts need to be around Ohio and Illinois to make sure that the state implementation plan is a rational one that gets it to the point where the economics are right, and even--you know, I was at a session that Gina McCarthy was at, and she even said that by 2030, she still expects 30% of the generation in this country to be coming from coal. So working through programs like this, controlling on the mass level, our plants are positioned to be fine through that, and particularly since in Illinois you have coal-on-coal at times. It’s a pass-through if it’s based upon a credit.

Great, thanks. [Indiscernible] you mentioned relating to the MISO transmission expansion plan. Is that a quarter only effect, or should we continue to see outages I the remainder of the year for your coal fleet?

Well, I’d say if you look back over the past few years that certainly as I’ve been here, it always seems that the expansion plans are frequent and forever. There continues to be investment around transmission. I think certainly they continue to try to build out the network, and I think the positive side of it is when you look at some of the biggest congestion points that the expansion plan is meant to deal with, should benefit our facilities in the south. But you’re going to continue to have--it’s what they do. Those build-outs continue to happen, but I think it can be a benefit to us to reduce some congestion long-term, and even an example of that, when we looked at all of our congestion points in Illinois, the one that was highest on the list that MTEP wasn’t going to address was around Baldwin, and we did the Baldwin transformer project. It’s now operational, and time will tell how successful it is in reducing congestion, but we would say - and Hank, you can verify this, but when MISO puts out its highest congestion points in the system, Baldwin typically was always in the top 10, and we haven’t seen it there since we have completed that project. Is that--?

That’s right.

Great, thanks so much.

Thank you. Our next question is from Jonathan Arnold of Deutsche Bank. Please go ahead.

Good morning, guys.

Morning.

Bob, if I could just ask on the buyback and the sizing of it, and the fact that you haven’t yet had the result you anticipated in the ’16-’17 auction, I know you anticipate completing this by the end of ’16, but how are you thinking about future capital allocation decisions? You were going to have an announcement in November. Is this sort of a preview of what might be a more holistic discussion in November, or will we be talking about this sometime early next year? Can you just give us a sense of how to think about how this is the plan?

Well, I would say internally capital allocation is an evergreen discussion. We’re always talking about it and we’re always looking at it. Clint’s tracking liquidity, cash flow, and everything, so we continually will evaluate what is the best thing to do. I wouldn’t expect right now any additional big announcements in November. I think what we’ll be focusing on is certainly completing this repurchase as fast as we can, but there’s no question that there’s more to come and it’s going to be more around timing. We’ll have more clarity on capacity auctions, whether that be the PJM ones or the MISO ones, and you go through the winter and with 120 million megawatt hours, power prices don’t have to move much to create a lot of cash flow for us. So we’ll continually evaluate it, and when we feel comfortable we’ll follow on. So this is definitely a second step. The first step is we allocated $100 million at the closing of the EquiPower deal to reduce the equity being issued at that time, which was 3.5 million share essential buyback. So this is the second step, another 250, and I would think that when you look at our investment opportunities, and the question came up earlier about investing in PJM and combined cycle units, we’ve got a fully permanent site that you could build a new combined cycle unit right at our Ontelaunee location, but when you look at our investment opportunities, the things that climb to the top of the list when I look back are PRIDE projects, up rates, and share repurchases. Share repurchases are the filter that everything needs to go through, and where the equity now is, from my perspective, from the company’s perspective - and we’re in complete uniform agreement here, the opportunity to buy our shares at this price is the most compelling investment that we have right now. We’ve got up rates that we can be dealing at $300 a kW, and we will do that; but the priority is going to be always to let the capital flow where the best opportunity is, and again, $23 or so for our share price is a very compelling price for us to move quickly, which is why we’ve accelerated.

Okay, so we shouldn’t be thinking of the 250 as, like, the 2016 capital allocation actually.

That’s correct. We will certainly provide updates, and I think as you get towards the end of this one, whenever that is, that we would always provide clarity on what we’re seeing in the market and expectations on what’s next. So you remember at investor day, we generate a lot of free cash flow, so we’ll be very open with the market on our plans on how we think it should be allocated.

Okay. Then I was going to ask about the performance of the Duke fleet, given the comments in the prepared remarks, and you just gave that number of $20 million to $25 million opportunity cost. Was that for just those acquired PJM assets that you cited, that had the forced outages, or was that more an across the fleet number?

Yes, the $20 million to $25 million is for the coal fleet, both in Illinois and in Ohio, and then as we look at the forced outages in the Ohio fleet--or in the PJM fleet, which you saw was Kinkaid performed very well, and then when you look at the Ohio plants, that’s where really most of your forced outages were, really kind of across the board in that fleet.

Okay, that’s good. Thank you.

Thank you. Our next question is from Michael Lapides of Goldman Sachs. Please go ahead.

Hey guys, just one quick clean power plan related question. I know they revised the heat rate improvement or the efficiency improvement for coal plants expected. Just curious - how achievable is that when you look at the fleets, when you look at your own units, when you look at the market?

Well, I would say, Michael, that’s what the PRIDE program does, so we’ve been doing this all the time, and I would say that I think most generators do this all the time. So I think this is a government that thinks that no one worries about efficiency because they don’t. We do this every single day, and if there’s anything we can do on our PRIDE program to find where we’re losing heat rate, whether it’s heat loss through piping or variable speed fans, or whatever the case may be, we do this all the time. I would say to think that we’re going to suddenly find 4%, which I think is what the eastern interconnect target is, is--again, that’s just the government thinking that no one worries about efficiency. But again, unlike them, we do, and we do this every day.

Got it. Thanks, much appreciated.

Thank you. At this time, speakers, there are no questions, but if you would like to ask a question, please press star, one.

Okay, Operator, I guess that’s the conclusion of the call. I appreciate everybody calling in, asking questions, and following us with great interest. Thank you very much.

Thank you, speakers. That concludes today’s conference. Thank you for participating. You may now disconnect.