Dyne Therapeutics, Inc. (DYN) Q1 2013 Earnings Report, Transcript and Summary

Hello, and welcome to the Dynegy Inc. First Quarter 2013 Financial Results Teleconference. At the request of Dynegy, this conference is being recorded for instant replay purposes. [Operator Instructions] I would now like to turn the conference over to Ms. Laura Hrehor, Managing Director of Investor Relations. Ma'am, you may begin.

Good morning, everyone, and welcome to Dynegy's investor conference call and webcast covering the company's first quarter 2013 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 statement. For a description of the factors that may cause such a variance, I would direct you to the forward-looking statements legend contained in today'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 this morning. Here with me are several members of Dynegy's management team, including Clint Freeland, our Chief Financial Officer; and Hank Jones, our Chief Commercial Officer. Our agenda for today's call is located on Slide 3. I'll begin with a review of the first quarter highlights, including recent events and follow that with an update on operational results for the quarter and an early look at how the EPA's recent effluent guideline proposal may impact the Dynegy coal fleet. Hank Jones will provide the commercial update, including MISO's recent resource adequacy projections. Clint will review the first quarter financial performance and provide an update on our refinancing activities. I will close the discussion with our priorities for the balance of 2013 and reemphasize our investment thesis around limiting downside risks as well as positioning the company for market recovery and capital allocation opportunities. With the remaining time, we will open the discussion for Q&A with the Dynegy management team. The first quarter highlights are shown on Slide 4. First quarter 2013 adjusted EBITDA was $43 million, a $5 million improvement period-over-period despite an 18% reduction in generation. Adjusted EBITDA for the Coal segment was down $18 million compared to last year due to several items including planned outages, economic fee rates, higher coal transportation costs associated with the rail contract modification that occurred in 2012 and basis. When we refer to basis for the Coal segment, we typically are referring to the discount between INDY Hub, the liquid pricing reference point, and the local plant busbar price. Offsetting the Coal segment decline was a $21 million period-over-period improvement at the Gas segment. This improvement was led by independent stations benefiting from strong spark spreads as a result of cold winter weather and a better sourcing of natural gas. In addition, the Gas segment is no longer impacted by legacy option positions which negatively impacted 2012 results. Liquidity has improved to $715 million, an increase of approximately $120 million since our year-end call, and as Clint will explain, will further increase once the finance activities are completed. The successful refinancing of GasCo and CoalCo term loans released previously restricted cash and upsized our revolver to $475 million. The refinancing also significantly lowered the interest rate on outstanding debt balances, the combination of debt paid down during the past 6 months and the lower interest rates reduces our annual cash interest costs by approximately $100 million annually. Our integration of Ameren Energy Resources is underway. We recently submitted the required filing with FERC and later today, we plan to make the required filing with the Illinois Pollution Control Board. We remain on track for a fourth quarter closing and continue to target annual synergies of at least $60 million. And finally, we are reaffirming our adjusted EBITDA and free cash flow ranges for 2013. Clint will provide additional insight into the quarter's financial results and our full year outlook. Slide 6 highlights our operational performance for the first quarter. Safety, first, we had 2 recordable employee incidents during the period. We focus every day on our safety behaviors, practices and procedures, striving to achieve our target of 0 injuries each and every day. Production volumes for the quarter declined 18%. The Coal segment declined 10% with approximately 80% of that decline due to planned outages and derates, with the balance of the decline attributable to market-related factors. Gas segment volumes are 25% lower as a result of an extended planned outage at Kendall unit 2 and the planned Ontelaunee outage, which also adversely impacted the Gas segment equivalent availability factor, or EAF. Casco Bay volumes contributed to the lower first quarter volumes due to gas supply issues. Independents experienced increased generation during the quarter as spark spreads increased over the first quarter 2012 as a result of colder winter weather coupled with improved sourcing of Marcellus gas supply to the plant. EAF at the Coal segment declined as a result of planned outages at Baldwin unit 3 and Hennepin unit 1. On April 19, the EPA released the proposed changes steam electric effluent limit guidelines, or ELG. While our analysis of this proposal is very preliminary, Slide 7 outlines the 7 wastewater streams covered by the proposed rule and how they may impact each of the coal plants. 5 of the 7 wastewater streams identified in the rule are applicable to our coal plants, with each plant affected differently. The EPA has proposed 8 options for comment, of which 4 are their preferred alternatives. The preferred -- the proposed options are included in the appendix on Slide 36. The options presented in the proposed rule range from least stringent and least expensive to option 5, which is the most stringent but not a preferred EPA option. The proposed compliance state would coincide with the renewal of water permits, which in our case, likely results in Havana having the earliest compliance state for the coal fleet possibly by 2018, while the other Dynegy locations likely would have compliant states subsequent to that but not later than 2022. As with any regulatory proposal, we anticipate considerable public comment from stakeholders on many sides of the issue. However, the EPA has noted that despite the range of options and technologies, they do not prefer the most stringent and most costly options. Provided on Slide 8 is a high-level summary of wastewater streams at each of our coal plant locations and control technologies currently employed. Flue gas mercury control addresses wastewater from the transport of activated carbon residue. 3 of our 4 locations utilize dry handling of this residue, thereby complying with the most stringent and the EPA-preferred options. The fourth location, Wood River, currently utilizes an impoundment, which complies with 2 of the proposed options. If the final rule requires dry handling, the investment at Wood River is not expected to be a material amount. Also, any expenditure to convert Wood River to drive flue gas mercury control would also satisfy the dry handling technology the EPA is proposing in certain options for the fly ash transport wastewater system. Fly ash transport water is not utilized at Baldwin or Hennepin, and our early analysis is that this standard would likely apply only to the Havana and Wood River plants. The technology at these 2 plants today appears to comply with 2 of the 8 proposed options. Similar to flue gas mercury control, the investment to convert to drive fly ash handling to comply with all proposed options is not expected to be significant. Bottom ash transport water applies to all coal plant locations, and the current control technology likely complies with 5 of the proposed options, including 3 of the 4 EPA-preferred options. The fourth EPA-preferred option, dry handling for units greater than 400 megawatts, would impact the 3 units at Baldwin and Havana unit 6 and would require additional capital investment. Combustion residual leachate appears to apply only at Hennepin as that is the only site that has point source capture through a subsurface collection system. Hennepin's control technology appears to comply with all 4 EPA-preferred options. Nonchemical metal cleaning waste applies to all coal plant locations and likely applies to the Gas segment's combined cycle plants. Compliance with the EPA-proposed options for this wastewater stream, which would require some level of capital investment, is not expected to be material. Also note that once the ELG rule and EPA's other rulemaking that addresses coal ash handling and disposal, the coal combustion residual or CCR rule, are finalized, Dynegy will make compliance decisions to address both rules. Capital expenditures for purposes of the ELG rule would also go towards Dynegy's cost of complying with the EPA's proposed CCR rule, especially with regard to dry handling of fly ash, bottom ash and flue gas mercury control. I will now turn the call over to Hank Jones for the commercial review.

Thank you, Bob. On Slide 10, I will offer our latest hedging activity on our Coal and Gas segment portfolios, as well as provide an update to our coal procurement activities. Due to recent transmission line outages in Southern Illinois, the correlation between the INDY trading hub and our Baldwin and Wood River facilities declined, which I'll cover on the next slide. To actively manage the corresponding basis risk this creates, we reduced our hedge percentages to 68% for the Coal segment, leaving the portfolio more open to plant busbar pricing. We continue to hedge the Gas segment opportunistically as spark spreads improve. Hedges continued to be layered in for both portfolios in 2014, with hedge levels currently around 25%. 2014 PRB pricing has decreased almost $2 per ton over the past 4 months despite higher gas prices. We captured this lower pricing for approximately 5% of our 2013 volumes and approximately 35% of our volumes for 2014. As the graph in the lower right indicates, PRB pricing is beginning to trend up with gas. We intend to keep a portion of our remaining 2014 coal supply requirement open to the spot market and opportunistically fill the short position over time. Slide 11 addresses basis for the Coal segment. As a reminder, the Indiana hub is a relatively liquid trading location for buyers and sellers of financial power. Dynegy has historically hedged the coal fleet at this location and actively manages the commercial positions when necessary for correlation changes between power prices received from MISO at the busbar versus the hedged price at the Indiana hub. Basis differential is primarily due to transmission limitations for generation in Southern Illinois to the areas that need electricity the most. At our Analyst Day, we devoted some of the discussion to Coal segment's basis issues that have resulted from line outages in the Prairie State facility. During March, the basis differential widened for Baldwin and Wood River due to generation outages at several power stations in Central Illinois and transmission work in the southern part of Illinois as shown by the dotted lines on the map to the left of Slide 11. With these lines out, our Baldwin facility and nearby Prairie State facility have fewer transmission lines to move their combined 3 gigawatts of power to the load centers in the state, increasing congestion along the remaining transmission paths. This resulted in basis issues that decrease the correlation previously observed between Baldwin and Wood River facilities and the Indiana hub. The around-the-clock monthly basis for Coal segment's average weighted generation to INDY Hub increased during the quarter as plant and transmission outages in addition to milder weather started to materialize. This trend is reflected in the monthly basis differentials provided on this slide. While we expect basis will improve when the transmission work is completed, our commercial team will continue to actively participate in annual and monthly options of the financial transmission rights, or FTRs, during 2013 to partially mitigate basis risk. Historically, basis improves during the summer with increased localized power demand and a seasonal reduction in scheduled maintenance of power generation plants and transmission resources. Mid- to long-term basis management strategies also include access to retail customers as provided by the AER acquisition and through increased local bilateral sales. Additionally, our congestion relief analysis has identified 5 to 6 potential projects to debottleneck transmission flows, which may relief congestion and the corresponding impact on the basis. Turning to Slide 12. MISO held their 2013, 2014 planning resource auction this spring that resulted in the cleared capacity auction price of $0.03 per kW-month. MISO published the auction summary results, indicating roughly 8 gigawatts of surplus capacity that did not clear the auction. The excess capacity was primarily made up of generation resources with a small amount of behind the meter generation and external resources not clearing the market. This excess supply, along with a vertical demand curve, are the main contributors towards MISO clearing price of $0.03 per kW-month for the 2013/2014 auction. While the current result was generally expected, future auction results are anticipated to increase in value in the 2015-2016 time frame as MISO projects net retirements from the system to be around 8 gigawatts, almost the same amount of capacity that was deemed excess in this year's auction. There are no plans for changes in the formal market design. However, there are initiatives which we are monitoring that would improve the MISO capacity market. First, MISO's independent market monitor, Potomac Economics, has made a recommendation that MISO move towards implementing a downward sloping demand curve versus the current vertical demand curve. Dynegy continues to fully support the IMM's recommendation. Secondly, Dynegy and other parties have a rehearing pending with FERC regarding the lack of any minimum price offer rules in MISO's tariff as the method to mitigate buyer market power. FERC has no statutory time requirement to issue a ruling, but we will continue to encourage a resolution. Lastly, MISO has recognized the future resource adequacy risks, which is discussed in more detail on the following slide. As a result of significantly reduced reserve margins in just 3 years, MISO now fully supports a longer forward commitment period of 3 to 4 years for future planning resource auction as well as the downward slope in the demand curve. MISO continues to express concern over resource adequacy in the coming years. As highlighted on Slide 13, MISO expects 2016 to be significantly tighter on supply than recent history. Looking at the graph on this slide, MISO continues to refresh their expectations of generation retirements, primarily due to EPA regulations and derates to gas units that lack adequate gas supply. The table on this slide calculates what the actual reserve margins would be in 2016 based on MISO's estimates for resources in 2016 and their resource requirements. MISO projects reserve margins of around 16% for the 2016 summer and winter periods if a moderate forecast is applied. If a high-load forecast is applied, those reserve margins are reduced to approximately 13% to 13.5%. As we indicated during the Analyst Day, when reserve margins were 18% in MISO in 2009, capacity prices averaged $2 per kW-month. As reserve margins decrease below 18%, we anticipate the region will experience much stronger capacity pricing. I'll now hand over to Clint to address the financial results.

Thank you, Hank. First quarter consolidated adjusted EBITDA totaled $43 million compared to $38 million in the first quarter of 2012. Although I would note that last year's results reflected here exclude negative $14 million in first quarter adjusted EBITDA of DNE as it was moved to discontinued operations last fall and deconsolidated from Dynegy's results. Quarter-over-quarter, consolidated adjusted EBITDA rose by $5 million as a meaningful improvement in Gas segment results more than offset the Coal segment decline. Despite a 25% decline in total generation volumes, Gas segment adjusted EBITDA rose by over 50% to $61 million, primarily due to strong market prices, improved fuel sourcing and higher output at our Independence facility in New York. The Coal segment, on the other hand, continued to experience meaningful negative basis differentials, which together with higher rail transportation expenses and lower generation volumes led to an $18 million decline in first quarter 2013 segment adjusted EBITDA compared to the same period last year. Cash flow from operations for the first quarter totaled negative $7 million as interest payments, collateral outflows and working capital requirements together exceeded adjusted EBITDA for the period. Total liquidity stood at $715 million on April 23 and include $420 million in unrestricted cash and $295 million in unused revolver capacity. You may note that the unrestricted cash balances are somewhat below what we've spoken about previously, but that's primarily a timing issue as we needed to post $70 million in cash collateral to certain non-bank first lean counterparties until we were able to migrate them to a first lean position in the new collateral trust agreement as part of the refinancing. As of today, we have received half of this cash back and anticipate the balance to be returned over the next week. Additionally, the company recently posted $20 million in cash collateral to Midwest ISO in order to participate in the annual FTR auction for the coal business and has experienced normal intra-month working capital fluctuations as well. Moving to Slide 16. Adjusted EBITDA for the Coal and Gas segments, before the allocation of corporate G&A expense, totaled $65 million, slightly up from $62 million during the same period last year. But as you can see, segment results were uneven as strength in the Gas segment was largely offset by weakness in the Coal segment. Gas segment adjusted EBITDA before corporate G&A allocations totaled $61 million during the first quarter of 2013 compared to $40 million during the first quarter of 2012. While total segment generation volumes fell by 25% quarter-over-quarter as a result of lower spark spreads, planned and extended outages at Kendall and Ontelaunee and fuel supply issues at Casco Bay, Gas segment results improved primarily due to strength at our Independence facility. Compared to the first quarter last year, average around-the-clock spark spread at Independence rose by 79% to $13.73 per megawatt hour, which together with a 22% increase in generation volumes and improved fuel sourcing, contributed an incremental $17 million in net energy margin compared to last year. Otherwise, most factors impacting the segment were generally offsetting as the absence of legacy put option settlements and lower O&M were offset by lower capacity revenues primarily at Kendall and loss revenues from the SCE contracts, which were terminated last year. Coal segment adjusted EBITDA before corporate G&A allocations totaled $4 million during the first quarter of 2013 compared to $22 million during the first quarter of 2012. While average around-the-clock INDY hub prices rose by $3.43 per megawatt hour compared to last year, the Coal segment was roughly 75% hedged during the period. So it only realized roughly $0.75 per megawatt hour of that uplift. Despite slightly better prices net of hedges, however, a $1.78 per megawatt hour increase in average around-the-clock basis reduced gross margin by $8 million. And this, together with a $5 million increase in rail card lease expense as part of the rail contract modification signed last year and a 10% reduction in generation volumes, lead to the segment's weaker results. Dynegy's cash flow results are outlined on Slide 17 and as you can see, enterprise cash flow from operations for the quarter was negative $7 million, while free cash flow totaled a negative $14 million. With many of the nonrecurring items that impacted 2012 behind us, such as the settlement of legacy put options, restructuring expenses and Consent Decree CapEx, cash flow results presented going forward will be more in line with the recurring operations of the business. Through the first 3 months of 2013, cash interest payments decreased by $10 million compared to the same period last year due to the $325 million paydown of debt in November 2012. Going forward, cash interest will decrease even further due to our recent refinancing and more favorable interest rates. Working capital and other charges also improved period-over-period due to coal inventory management initiatives and the absence of bankruptcy advisor costs. Finally, 2013 saw a reduction in environmental CapEx spend due to the material completion of Dynegy's Consent Decree project in 2012. As outlined on Slide 18, our PRIDE program continues to be an important part of the financial management of this company. As previously discussed, the company is targeting $42 million in cash cost savings and gross margin improvements through initiatives such as vendor optimization, improved outage management, heat rate improvement, capacity upgrades and enhanced ancillary services. A further $83 million in balance sheet efficiencies are targeted for this year as we continue to focus on reducing the collateral intensity of the business and managing fuel inventory to optimal levels. In fact, we have already made significant progress on this front as collateral associated with our existing long-term service agreement at GasCo was recently reduced by $59 million. We will continue to drive toward our PRIDE goals, and we'll provide regular updates as we move forward throughout the year. In addition to these balance sheet improvements, the company has also been focused on streamlining its balance sheet and liquidity program through refinancing its outstanding CoalCo and GasCo term loans and establishing a new corporate level revolver. As previously disclosed, we completed the first step of this process on April 23, and the results are outlined on Slide 19. The GasCo and CoalCo term loans will refinance with 2 new term loans at Dynegy Inc., an $800 million 7-year Term Loan B and a $500 million 7-year Term Loan B. We structured the financing this way to provide the company with the flexibility to move forward with the refinancing quickly while retaining the ability to refinance the smaller term loan with the proceeds of an unsecured debt offering once the requisite documentation, including pro forma financial statements with AER and its subsidiaries, is available. At this point, we expect to complete this work and launch the bond offering later this month. As a result of the refinancing, Dynegy no longer has any restricted cash on its balance sheet and the unused collateral accounts have been closed. The company's liquidity is now centrally managed at the DI level and all Letters of Credit are now issued under the corporate revolver instead of under cash secured facilities. On April 23, the date that the refinancing closed, the company's liquidity increased to $715 million. However, this is after posting approximately $70 million in cash to bridge the transition of certain first lean counterparties from the previous collateral structure to the new collateral structure, some of which has already been returned with the balance expected in the near term. Pro forma for this collateral return, total liquidity at April 23 was $785 million with net debt of approximately $810 million. As Bob mentioned earlier, we are reaffirming our 2013 adjusted EBITDA and free cash flow guidance today. There are a number of factors that are both positively and negatively impacting our business, and they are outlined on Slide 20. Beginning with our Coal segment. Basis differentials between the liquid hubs and our plants have continued to be an issue so far this year. In January, basis was in line with our expectations. However, we saw a meaningful increase in basis as a result of transmission line and substation work at West Mount Vernon, which was then exacerbated by outages at certain Central Illinois plants. As a result, we are currently trending toward the bottom end of the Coal segment's adjusted EBITDA and free cash flow range. As Hank mentioned, we expect some level of improvement in basis going forward as a result of the West Mount Vernon transmission work, but we will need to monitor this as that infrastructure comes back into service. This, together with historically tighter basis during the summer, stronger prices for the unhedged portion of our generation and potential benefits from FTR purchases, may provide some level of offset to the negative basis we've seen, but we'll need to watch this in the months ahead. The Gas segment on the other hand has had a strong start to the year and is trending toward the top of its adjusted EBITDA and free cash flow range. With better-than-expected results at Independence in the first quarter and higher-than-anticipated resource adequacy sales for this summer at Morro Bay and Moss Landing, the Gas segment is in position to have a solid year. And finally, the refinancing is expected to positively impact Dynegy's cash flow this year. However, since we have not yet completed the second stage of the refinancing, the issuance of unsecured bonds, we have not yet updated guidance for this. Those factors positively impacting results include higher-than-expected amount of restricted cash returned to the company and the reduction in the amount of debt repaid. In our guidance, we expected approximately $300 million in restricted cash to be returned to the company this year, and that $150 million of that would be used to pay down debt. Instead, we have freed up $330 million in restricted cash and used only $60 million to repay outstanding debt, providing a meaningful uplift on a net cash basis. A portion of this improvement, however, is offset by a higher make-whole payment as a result of refinancing earlier in the year and higher transaction fees given the larger term loan, larger revolver and the addition of the bond issuance, which was not previously envisioned. So in summary, both the Gas segment results and the refinancing are expected to positively impact results for the year, whereas basis at the Coal segment is putting pressure on Coal segment earnings. With that, I'll turn the call back over to Bob.

Thanks, Clint. Our 2013 priorities are summarized on Slide 22. Operationally, we're preparing for the summer season and in completing our spring outages. The AER integration will accelerate over the summer months as we prepare for day 1 and a fourth quarter closing. Commercial focus centers on basis management and managing our commercial position. Regulatory activities over the next several months will be at the federal, state and ISO levels to address issues relevant to our portfolio of assets. Financially, in addition to achieving our financial targets, once our financing activities are completed, we'll further our plans on the best use and highest return opportunities for our excess liquidity. And finally, on Slide 23 is our investment thesis updated for the recent debt refinancing. Through debt management and refinancing, Dynegy equity holders gained additional downside protection from exposure to low natural gas prices to approximately $100 million in ongoing annual cash interest savings. In addition, the more efficient capital structure and the release of previously restricted cash provide additional liquidity and capital allocation opportunities that will be utilized for the benefit of our shareholders. At this point, Marianne, I'd like to open up the line for questions.

[Operator Instructions] Our first question comes from Jon Cohen of ISI Group.

I just had a couple of questions on basis. It seems like every quarter there's some sort of transitory transmission outages that kind of pressure basis. Have you updated your thinking on what the long-term sort of steady-state basis should be from Southern Illinois to INDY Hub?

Well, we continue to do our work around the analysis of the transmission system around Baldwin, around Prairie States. We've been utilizing Quanta to help us in that analysis, and we've identified several projects over the next couple of years that can help relieve some of the congestion we're seeing. So when you take into consideration the work that's just finished around Mount Vernon line, or finishing during the month of May, the upgrades that are happening as a result of that upgrade, we'll see some level of improvement. But time will need to go on a little bit before we get a true sense on how much relief that actually generates from what we've been seeing. As we said during January, the basis was pretty much in line with our guidance. February, it widened a bit. And then March, once that line came down, it exaggerated from the prior month. So we continue to believe it's going to be somewhat volatile. Certainly, all the transmission work is completed now for the most part for the balance of the year as we enter the summer season. So we would hope for the balance of the year that it would settle down more in line with our guidance number. But again, as that line comes back up, we'll have to monitor that and see the impact. Also longer term in addition to the potential upgrade that we see in the existing network, certainly, with the acquisition of AER, which has a very good retail base, we'll be looking to provide more of our hedging for Baldwin with local load, which should also help from a risk management standpoint around that.

And these projects that you've identified to debottleneck the transmission flows, would those be merchant projects that you would have to pay for?

What we're looking at is projects that have been identified within MISO transmission that are on their list and there are certain ones that we've gone through, we've done the analysis. And while they may not be on their near-term list, if we participate with some level of financial contribution and then also look for others that will benefit from the upgrade as well, then you can move it to an A-level project and accelerate its implementation rather than having it further down the queue. So we can influence that but it would take some level of capital. And the type of projects that we're talking about, and I'll ask Hank in a moment to give a couple examples, but these aren't large CapEx projects. And from our analysis, the payback period would be relatively swift as well, so they seem worth pursuing. And maybe, Hank, you can give a couple examples of the kind of projects that we're seeing?

Sure, Bob. The types of projects that we're looking at to debottleneck the system would include things such as replacing the transformer at Baldwin, increasing the ground clearance on 2 segments of transmission line, that type of work that the -- increasing ground clearance can actually occur without taking lines out of service. There are other more expansive projects that could be considered, but several of these are not monumental tasks.

Okay. Great. And one other quick question on -- you showed a little bit more information on your gas price sensitivity calculation. It looks like you're saying a $1 move in gas is $7 of ATC power price. How is that compared to the historical correlation between gas and power in MISO?

That is intended as an example and basically, the -- we do see some heat rate compression as you move up the gas price curve. But we think that, that compression is going to be impacted by changes to the GenStack. So as you start to see some retirements come in place, the historical relationship, we think, is going to improve.

And one other thing that as you look at the sensitivities to keep in mind, and I think maybe this is kind of where your question is going, is that we provide the $150 million change in adjusted EBITDA -- or gross margin as for every dollar move in natural gas. On top of that, you also need to observe the heat rate movement as well. And if we look at first quarter of last year and where the average gas price was versus where it was first quarter of 2013, there's about a $1 difference on average between the 2 quarters. But at the same time, what you've seen is heat rate compression of about 2 turns. And so on a net basis when you look at the change in average MISO price, it's about $3.50. And so as you think about what assumptions are that you're using going forward, you need to use those -- both of those sensitivities to come to a better view. And like Mike said, depending on people's views of retirements and how the stacks change over time and the impact that, that has on heat rates, obviously, that will play into that calculation as well.

We also did a regression analysis where we looked at different gas prices and different heat rates, and it seems as though the heat rate tends to bottom out at around 7,000 when you're getting to the higher gas prices. So that's where our sensitivities are based on.

Our next question is from Julien Dumoulin-Smith of UBS.

So going back to the whole coal ash discussion here for a second, can you talk for a second about the Illinois PCB and some of the filings back and forth with Ameren and the potential costs associated with that and how that might be different from what's required from EPA thus far on the effluent and CCR side?

Sure. Well, both the Dynegy fleet and the AER fleet have groundwater monitoring around the ash pond impoundments. And from a Dynegy perspective, we're working with the Illinois EPA on how we propose to work through that in the future. Ameren went a different path where they're working through the PCB. The EPA deal's more with enforcement where we deal with coming up with a solution that works between the 2. What Ameren proposed through the PCB is more around rulemaking. And what they proposed is the different classifications for ash ponds and depending on what grade or what classification given would be the remediation timeline, if you will. But I think when you look at all of it in the timeline, it all is somewhat coinciding in the same time levels towards the end of the decade or into the next decade, and we're really all talking about the same thing. So the groundwater issues around Baldwin, around some of the AER plants is more around going through and monitoring the groundwater, recirculating the groundwater. And again, from the time line on compliance, it's all around the same time frame.

And that's pretty much a good summary, Bob. I think it's over a decade period we're looking at.

And that's Dan Thompson speaking from -- who runs our coal operations.

Great. And just maybe to contrast that, I mean, I think the PCB number was $120 million for AER, ballpark. Can you give some sense as to, on the Dynegy side, what kind of a comparable kind of initial set of CapEx might be over that 10-year period?

You're talking overall for the proposed effluent limitation guidance, or you're talking about just the ash ponds?

Well, I suppose on the ash pond side, there was a number thrown out as part of the PCB filings with -- on the Ameren side. But in aggregate, kind of consolidated Dynegy versus Ameren, how much would you imagine on each side through the decade?

At this point, Julien, I wouldn't put too much credence in any of the -- in the numbers because we got to work through which rules would apply. We don't see it as a particularly significant cost from our side. I think the main thing for us as we go forward is working through the rulemaking process. And then the same issue applies with the effluent guidelines. It's just working through that. But I don't think it's going to be as -- it's not the hundreds of millions of dollars that we've seen certain numbers put out into the marketplace around this. These are manageable things and for us, probably the one that we have to work through and watch the most is really just around bottom ash transport, and that's the one that has a little bit more of a capital involve versus any of the other things that we're talking about. So we don't see it as particularly significant or difficult issue to deal with. It's more around rulemaking and then implementation over the next decade.

Great. And going back to another success of late, talking about PJM exports. You've alluded to essentially putting down some of your own capital to expand your, I suppose, existing right of ways to get into PJM. Can you talk about, one, the timeline for that and the opportunities potentially, or in terms of putting down incremental capital to get more exports of capacity?

Specifically to the Dynegy fleet, the studies being done both on the MISO and the PJM side, MISO has recently gone back to refresh their analysis taking into consideration a lot of the planned upgrades that are scheduled in the system during the time period. So we won't know till about the September time frame the outcome of the studies on both the Ameren or both the PJM and MISO side. So it's probably a little bit early to talk about what and how much. But our feeling is with the amount of transmission that Ameren has been able to move into PJM as we talked about before, incremental transmission above and beyond that will likely require some level of CapEx. But the whole cost benefit analysis that will be done once we get firm numbers from both the MISO side and PJM. And that's, again, probably not till towards the end of the third quarter.

And just magnitude here, it seems pretty good bang for the buck, It's tens of millions that we're talking about, correct, I mean, just magnitude wise?

Yes, well I think it's a sliding scale because we talked about our filing, it takes everything from our whole portfolio to some smaller portion of it. And I think what has been explained to me by our transmission team here is that getting a small amount in may not be a very large capital investment. Whereas if you start talking about hundreds of megawatts, then the capital becomes -- could become very significant. So it's depending on ultimately the number of megawatts you want to move will impact the amount of capital. And certainly, as you'd expect, smaller movements in require smaller levels of investment because you have existing network services that can be upgraded as compared to requiring a new line, if you will, for something much more substantial.

Great. And just a very quick last one, contracting Morro Bay and Moss Landing going forward on the capacity side, any other opportunities? Obviously, PG&E has got an RFO out there. Anything else we should be tracking? Any other opportunities?

Yes, right now PG is what we're focused on. We've got both Morro and Moss Landing bid into that, and I guess the results on that we should know just sometime during the second quarter.

[Operator Instructions] Our next question comes from Angie Storozynski of Macquarie.

I wanted to start with the whole discussion about capacity payments and your perception of the future of MISO capacity payments versus your attempt to move capacity into PJM, and also how it ties into the last dismal results of the MISO capacity auction and also some bilateral contract -- capacity contract transactions that we've seen after that auction. It doesn't seem like the pricing in the MISO market is moving in the direction that you've been anticipating. And granted, we're -- it's still early into the process. We've heard from some fully integrated regulated utilities that they have plans to build additional generation assets, which do not seem to be reflected in the MISO supply demand study. So if you could give us an update on your views on future capacity prices in MISO.

Sure, Angie. And I think a lot of what you said is -- you made [ph] the right observations in that. The way that the capacity market works there now, it's not a particularly good forward-looking functioning capacity market. You're either long or you're short, and sitting at 8,000 megawatts long in the last auction, no one was expecting the auction to produce much, particularly when it's voluntary on the load side to participate. What is -- remains to be seen is how much appetite public utility commissions are going to have to investing dollars into new build or dollars into plant controls, which even at this point in time, plant controls is probably off the table because you're running out of time versus utilizing capacity that's available in the system. And that's going to be the tension point, new build versus utilizing existing capacity. And working with MISO, we're going to be doing as much as we can to work throughout MISO with bilateral agreements, having our generation ready. And as Hank showed on his slides, and particularly Slide 13, when we get to 2015, 2016 time frame, we expect a market that's no longer long, that it's much tighter. And as MISO would say, they have not seen a market this tight. Whether that's going to prompt new build or not, I'm sure it will prompt some. But even to meet the 2015, 2016 time frame between permitting and construction, you're typically talking, give or take, a little bit but 4 years. So you're well outside the compliance date for MATS. So we expect the tightening market. Our view is really unchanged since our Analyst Day meeting that we talked about last January where generation is going to come out of the stack. It's going to shift the clearing prices for power, and capacity is going to get much tighter. So still a consistent view, and the things that you outlined around potential self-build is a possibility, but we haven't seen much of that yet.

But we haven't seen any signs of that tightness in those initial bilateral transactions and capacity, and some of them are further out than the next, say, 1 or 2 years. It seems like the market is -- does not recognize the similar supply-demand fundamentals that you're talking about.

Well, I mean, the deals that we see going out beyond this auction is dealing with '14 and then into '15 and really MATS comes up, in earnest, April of '15. So I don't think there's a whole lot of bilateral capacity contracts being done for 2015, 2016 or those periods. I think it's really folks feeling out what next year would probably -- another auction, maybe not a $0.03 per kW-month, but it's not fully going to reflect the tightening market yet. So there's folks -- there are some deals being done out there at these lower levels.

Okay. Moving on to the -- this discussion about the sensitivity of your earnings to gas. I mean, when we look at the, say, the last 2 or 3 years, the sensitivity that would be implied from correlations of especially either NI hub or AD hub, the power prices with gas, implies more like a 50% of the sensitivity that you are showing. And the biggest, obviously, differential is the negative basis, negative power basis. When you're showing us that gas sensitivity, do you assume historical basis, or do you assume current basis between especially Baldwin and INDY Hub?

Yes. Angie, what we try to do is to provide sensitivities to the 3 primary legs of the realized power price: one is gas, 2 is heat rate, 3 is basis. And so what we've tried to do -- and of course, the basis sensitivity that we provided is for every $1 change in around-the-clock basis, it equates to about $22 million gross margin to the company. So I think when you think about the sensitivity of the company to the different variables, I think you need to use all 3 of those in -- together in order to forecast what the performance of the company would be. I think by just focusing on gas alone, I think you're not including a couple of pretty important data points.

But this $1 change increase in basis is versus the last observable basis?

Well, it's from one period to another period, whichever period that happens to be. We generate about 22 million megawatt hours whole year around-the-clock. So on a gen-weighted basis for the fleet, a gen-weighted $1 change in around-the-clock basis would equate to about $22 million in gross margins.

Okay. And then lastly, you have made the Ameren filing with FERC. I mean, purely looking at the math and the number of assets you will own -- will potentially own in Southern Illinois, it begs the question with the market power issues. Should we be worried about it? And have you had any discussions with FERC about it?

Well, I don't think you should be worried about it. I mean, with the amount of import-export capacity through the zones, we don't see a market power issue. In fact, the analysis done by our internal and 2 external shows that actually with the deconcentration of Ameren assets, this is actually lower market power than what previously existed. So we really see is a very low probability event that we have any issues there.

How does it -- this export-import capability, I mean, I understand that this is linked to your transmission lines, right, and that -- aren't that the same transmission lines that are causing congestion on the lines and weighing on your basis for your existing coal plants?

That's Baldwin getting power out, but in terms of power moving between Illinois and the surrounding states, there's not really an issue. When you take a look at the size of the reserves today, we don't see the issues. Yes, it's a MISO-wide analysis.

[Operator Instructions] Our next question is from Andy Bischoff of Morningstar Financial Services.

I was wondering if you could provide a little clarity on the Illinois Pollution Control filing for the Ameren transaction, when you might expect a decision, and any contingent planning or options you have should you not get the variance?

Well, if -- regards to the Ameren filing on the Illinois Pollution Control Board, we haven't -- we're not involved in that. They've done that on their side of how they want to approach it to the extent that once we closed, if that's still active, then we'll continue down the path. But essentially, we're doing the same things, we're dealing with the EPA. So this might end up converging at one point in time. I'm sorry, are you talking about -- maybe, Andy, I misheard your question. Are you talking about their filing with the Pollution Control Board for dealing with their ash ponds? Are you talking about for the variance for the capital?

Variance for the capital.

Okay. My apologies, I was thinking back to the other question. So no, that filing goes through today -- and sorry, can you repeat the question now that I've answered the wrong one?

That's okay. I was wondering if you could -- maybe a decision, when you would expect a decision and any contingent planning you have should you not get the variance?

Sure. Okay. There's no timing set on when we would hear something back at this point in time. Once it's filed, we'll go in and we'll meet with the Pollution Control Board and others -- well, to the extent we can meet with them, but to find out the feedback and the like. So we don't know yet on the timing. This is kind of new territory for everyone involved, the first time the variance was granted and second of all, a variance granted and then there's a change of control. So we're working through this together with the state, and we'll find out back from them once we make the filing around timing and any feedback. If it comes back with a negative outcome, we have to reevaluate what we do. It's a condition to close that we get the affirmative approval that it transfers over.

And as part of our filing we've committed to ensure that none of the factors that were relied upon in granting the initial variance will change and that we'll live up to all the requirements. So we don't see that there being any substantial impact or reason why they shouldn't approve.

Yes, we view it more procedural than anything because as Catherine is highlighting that, we're not looking to change anything. This is more of just changing the names, if you will.

And at this time, there are no other questions.

Well, great. Well, thank you, everyone, for participating and thank you, Marianne. At this point, we'll conclude the call.

Thank you. This does conclude today's conference call. You may disconnect your phones at this time.