Dyne Therapeutics, Inc. (DYN) Q4 2012 Earnings Report, Transcript and Summary

Hello, and welcome to the Dynegy Inc. 2012 Financial Results Teleconference. At the request of Dynegy, the conference is being recorded for instant replay purposes. [Operator Instructions] I'd now like to turn the conference over to Ms. Laura Hrehor, Managing Director, Investor Relations. Ma'am, you may begin.

Good morning, everyone, and welcome to Dynegy's investor conference call and webcast covering the company's annual and fourth quarter 2012 results, and Dynegy's proposed transaction with Ameren Corp. 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 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 this morning are several members of Dynegy's management team, including Clint Freeland, our Chief Financial Officer; Catherine Callaway, our General Counsel; and Carolyn Burke, our Chief Administrative Officer. As we announced in January, Kevin Howell, our Chief Operating Officer, stepped down from the COO role, but continues to support us in advisory capacity. He will also aid in the transition of his commercial responsibilities over to Hank Jones, who will be coming on board as Chief Commercial Officer at the end of this month. Our agenda for today's call is located on Slide 3. We'll follow our traditional agenda with a somewhat scaled back discussion of our 2012 annual and fourth quarter highlights in order to spend time reviewing the Ameren transaction. I'll cover 2012 operational and commercial results, including recent events affecting our California assets. Clint will review the fourth quarter and full year financial performance, as well as provide an update on our PRIDE results for the year. Our final and main topic this morning is our proposed acquisition of Ameren Corp.'s merchant generation and retail businesses, Ameren Energy Resources or AER. This transaction builds upon our investment thesis of creating significant upside opportunities for our shareholders while carefully managing downside risk. Due to the amount of material to be covered this morning, we will extend this call by an extra half-hour, if necessary, to allow ample time for the Q&A discussion. Highlighted on Slide 4 are several of the significant accomplishments during 2012 that will benefit the company for years to come. Dan Thompson, our Vice President of CoalCo Operations, and his team successfully completed the 7-year $1 billion Consent Decree program that positions our coal fleet to be in full compliance with all current environmental standards and requirements. Our commercial team successfully executed the new long-term rail contract during the third quarter at rates significantly below what had been forecasted. By repaying $325 million of GasCo's and CoalCo's term loan debt, we reduced the annual cash interest cost by $30 million and expect to generate further savings through a full refinancing of our term loans during 2013. Across the company, we continued our emphasis on improving the company through our PRIDE initiative, with the priority on improving fixed cash costs and gross margin and implementing balance sheet efficiencies. Finally, on October 1, 2012, Dynegy successfully completed its restructuring effort, reducing our net debt by approximately $4 billion and providing a strong foundation to meet today's challenges associated with the current low power and capacity price environment. It has been a significant and busy year for the company. Each of these accomplishments by our team along with many others has strengthened the company and set the stage for Dynegy's next chapter. Slide 5 highlights our operational and financial performance. Production volumes for the year were up approximately 20% over the prior year driven by the 70% increase in generation from our gas fleet as a result of improved spark spreads experienced throughout the year. Volumes for the coal fleet declined 10% primarily due to lower off peak pricing in the region and an increase in planned outages period-over-period. Despite these changes in production levels, both the coal and gas fleet maintained the reliable track record, achieving in-market availability of over 90%. Our fourth quarter and full year 2012 financial performance is in line with our Analyst Day guidance provided in January. Clint will provide additional detail, but the variance to the prior year's principally driven by lower realized power prices for the Coal segment. The annual results were also impacted by lower financial settlements due to the legacy gas put option liabilities. Our PRIDE efforts met and exceeded our targets established for 2012, and our 2013 guidance remains on track. Clint will cover both of these topics in his prepared remarks. Coal production on Slide 7 decreased 10% due to lower on- and off-peak pricing in the region and an increase in planned outages, while gas production increased approximately 70% and is attributable to higher on-peak spark spreads for Kendall and Independence, and higher off-peak spark spreads for Ontelaunee. IMA and EAF results for both segments were relatively flat period over period. While our 2012 safety performance has yet to reflect the improvements made during the course of the year, such as reestablishing plant safety council as well as increasing emphasis on job safety analysis, our year-to-date 2013 performance has shown substantial improvement with only 1 employee recordable [ph]. Safety continues to be a top priority in 2013 as we continue to strive each and every day for an injury-free environment. Our current hedge positions are shown on Slide 8. As market prices and spark spreads improved, our commercial team layered in more hedges and will continue to do so opportunistically. We continued to maintain a fairly open portfolio in 2014 for the Coal and Gas segments in order to capitalize on what we anticipate will be improved power prices in spark spreads compared to trading values today. Throughout the year, we've updated investors on capacity factors by a facility due to the significant increase in run hours the gas units are experiencing in this gas price environment. Slide 9 shows the capacity factors for the Gas segment continued to be higher than prior periods, merely due to improved spark spreads in the on- and off-peak hours. Plans for the largest spark spread improvement are Kendall's off-peak spark spreads improved almost $7 per megawatt hour and Moss Landing's on- and off-peak spreads which improved approximately $5 and $10, respectively. Casco Bay's plant spark spreads continued to compress period over period due to localized gas supply constraints. The Coal segment capacity factors were reduced from prior period primarily due to planned outages in addition to lower power prices. However, when removing the impact of outages, the fleet average capacity factor would have been above 85%. Recent developments impacting our California assets are highlighted on Slide 10. In February, a settlement [ph] was held by the California Public Utilities Commission, California ISO and the California Energy Commission to discuss the need for forward RA procurement as well as operational flexibility necessary to integrate and mitigate the intermittency caused by renewable resources. As we covered at our January Analyst Meeting, the unreliable nature of wind and solar generation requires support from fast-ramping gas-fired resources. The current Cal ISO market design does not provide the compensation needed either to incent new generation or prevent the retirement of existing facilities that have these desired capabilities. Without quick ramping resources, integrating the growing supply of renewable generation becomes more challenging for the state. The meeting concluded with the California ISO volunteering to implement a stakeholder process to design a framework necessary to create a viable capacity market. We intend to be a proactive participant in this process and the design. Jason Cox from our Regulatory Affairs team sits on the board of Western Power Trading Forum, much has been actively engaged in the development of a forward capacity proposal and we are fully supportive of that proposal. Key items we would like to be addressed include a forward resource adequacy market that is 3 to 5 years forward of the delivery year; incremental capacity options held once a year to allow for additional capacity to be bought or sold as needed due to changes in load forecasts; the RA market should be centrally administered and allow for bilateral agreement and self-supply with all resources being put into the market; finally, but equally importantly, a centralized auction should place a premium on flexible capacity to accommodate demand swings, and should provide additional compensation compared to non-flexible or intermittent capacity. There is broadening support for these market changes, and we currently anticipate these market design changes could be operational by the 2015, 2016 time frame. With these changes, Moss Landing and Morro Bay facilities, with their fast-ramping and low-turndown capabilities and Oakland with its black start [ph] capabilities will continue to play a key role in meeting the energy needs of California. In connection with our Morro Bay and Moss Landing contractual dispute with Southern Cal Edison, we initiated an arbitration to settle the Morro Bay tolling agreement and expect to have a resolution during the first quarter of 2014. In connection with the Moss Landing RA capacity dispute, we initiated litigation to resolve the matter. The litigation schedule is expected to be set during a hearing in the second quarter of 2013. I'll now ask Clint to address the financial results.

Thank you, Bob. As outlined on Slide 12, the company had a disappointing finish to 2012, generating consolidated adjusted EBITDA of negative $42 million during the fourth quarter compared to negative $14 million for the same period last year. As in the first 3 quarters of 2012, lower prices net of hedges at the Coal segment and the settlement of legacy option positions negatively impacted results. However, in the fourth quarter, there was additional downward pressure on Coal segment earnings as a result of higher basis differentials between our plants and their nearest liquid trading hubs. These 3 factors reduced gross margin by $91 million compared to last year. However, this was somewhat offset by higher Gas segment net energy margin and a lack of a fourth quarter commercial losses experienced in 2011. Year-to-date, consolidated adjusted EBITDA totaled $57 million within the $50 million to $60 million range provided at Dynegy's Analyst Day in January compared to $281 million in 2011. The year-over-year decline in results was primarily driven by 3 factors: lower realized prices at the Coal segment, settlement of legacy put options at the Gas segment, and the cancellation of tolling and resource adequacy contracts at our Morro Bay and Moss Landing facilities. Together, these items reduced gross margin by $305 million and were only partially offset by higher net energy margin at the Gas segment, the site amortization add back and lower O&M expenses. Total available liquidity at March 8, 2013, excluding DNE, stood at $592 million, including $370 million in unrestricted cash, $69 million of restricted cash in our unused collateral accounts and $153 million in the revolver and letter of credit capacity. As previously disclosed, GasCo entered into a new 364-day $150 million revolver in early January, and as of today, remains undrawn and fully available. Looking to Slide 13, adjusted EBITDA for the Coal and Gas segments before the allocation of corporate G&A expense totaled negative $19 million during the fourth quarter, down from a positive $15 million during the same period last year. As you can see from the segment breakout, the quarter-over-quarter decline was due to weakness at the Coal segment, primarily due to a $12.65 per megawatt hour decline in realized prices, which led to a $62 million reduction in gross margin. While average INDY Hub day-ahead prices remained relatively flat between the periods, 2 factors contributed to the weakness in realized prices: a significant decline in the average hedge price realized during the period, and a further reduction in the price of power received as a result of basis differentials between the liquid hubs and our plants. During the fourth quarter of 2011, hedge settlements added on average $7.41 per megawatt hour to the Coal segment's earnings as most of the hedges settled during the quarter were initiated during 2010 and the first half of 2011 when prices were considerably higher. Conversely, a majority of the hedges, which settled during the fourth quarter of 2012, were initiated during the first half of 2012 when power prices were much weaker, locking in average prices which were $4.24 per megawatt hour lower than market during the quarter. The change in average hedge prices alone accounted for a $51 million decline in segment results. Additionally, the average basis differentials between the liquid hubs and our plants increased by $3.41 per megawatt hour from $5.02 during the fourth quarter of 2011 to $8.43 during the same period in 2012, negatively impacting results by $11 million. These gross margin impacts were partially offset during the quarter by a $7 million reduction in O&M expense. Gas segment adjusted EBITDA before corporate G&A allocations total negative $2 million during the fourth quarter of 2012 compared to negative $22 million during the fourth quarter of 2011. As previously disclosed, results for the fourth quarter of 2012 were negatively impacted by $29 million in legacy put option settlements. Excluding these settlements, adjusted EBITDA for the quarter would have been positive $27 million or $49 million higher than the fourth quarter of 2011. Higher spark spreads, improved hedge prices, the add back of site amortization and the absence of a fourth quarter commercial loss more than offset lower capacity revenues at our Kendall facility and the loss of tolling and resource adequacy revenues at our Morro Bay and Moss Landing facilities. For full year 2012, adjusted EBITDA for the Coal and Gas segments before corporate G&A allocations totaled $142 million, down from $398 million in 2011. The $256 million reduction in results was primarily driven by the same factors that impacted the fourth quarter. Coal segment adjusted EBITDA declined by $223 million, as an $8.70 per megawatt hour decline in average realized prices led to a $191 million year-over-year change in adjusted EBITDA. Additionally, generation volumes were down 10% as a result of 2 large planned outages at our Havana and Wood River facilities, and lower off-peak generation in response to market pricing, leading to an additional $29 million decline in year-over-year adjusted EBITDA. Gas segment adjusted EBITDA declined by $33 million during the year ended 2012 compared to the same period in 2011, primarily as a result of $77 million in legacy put option settlements and $58 million in lower capacity, tolling and resource adequacy revenues. These items more than offset a $27 million improvement in net energy margin, $38 million in site amortization add backs, $20 million in lower hedging costs and $10 million in lower operating expenses. Slide 14 details the company's continued progress in driving both cash flow and balance sheet improvements in its business. During 2012, the company met or exceeded its stated targets for the year, with $31 million in incremental fixed cost reductions through various efforts, including a reduction in the use of activated carbon injections at Baldwin, various procurement initiatives throughout the company and, of course, our headquarters relocation. We also realized $13 million in gross margin enhancements, primarily through modest improvements in our in-market availability and gas resourcing at Independence, while generating an additional $148 million in balance sheet efficiencies with reductions in cash collateral, improvements in our days payable and successful inventory management. We will continue to focus on improving how we do business to increase the company's cash flow in 2013, and remain committed to delivering an additional $42 million in cash cost savings and gross margin improvements, along with an incremental $83 million in balance sheet efficiency. In January of this year, we initiated segment and consolidated adjusted EBITDA and free cash flow guidance for 2013, and as outlined on Slide 15, we are reaffirming that guidance today. While we have seen some downward pressure at our Coal segment due to higher-than-forecasted basis differentials in February and the first part of March, this has been partially offset by higher-than-forecasted balance of the year INDY Hub prices. The Gas segment, on the other hand, has benefited from stronger-than-anticipated pricing for our Independence facility. Taking these factors into consideration, we remain comfortable with the adjusted EBITDA and free cash flow guidance ranges provided both at the segment and consolidated levels. However, I would note that our current guidance does not incorporate any impact from the transaction announced today. Any updates related to this will be evaluated at the time of closing. With that, I'll turn it back over to you, Bob.

Turning to Slide 17, I'll address today's announcement of our planned purchase of Ameren Energy Resources or AER. This acquisition process occurred over several months, and required thoughtful and careful structuring decisions by both parties to ensure all stakeholder interests were considered and appropriately addressed. I want to thank Tom Voss and his team at Ameren for their dedication and hard work to consummate this transaction and for fostering a very professional and productive relationship between our 2 companies. Dynegy's CoalCo and Ameren's AER coal portfolios are interconnected through the Ameren Illinois transmission system, and building and strengthening our relationship with Ameren is very beneficial for Dynegy. The portfolio we are acquiring includes all coal generation plants held by AER subsidiaries, Ameren Energy Generating Company or Genco, and Ameren Energy Resources Generating or AERG. In addition, Ameren Energy Marketing or AEM is part of the transaction and includes Ameren Energy Marketing and Homefield Energy. AEM provides Dynegy with an immediate and substantial retail and commercial and industrial business, a strategic goal we have previously established for ourselves. The addition and fit of this acquisition to our current portfolio is also compelling due to the operating synergies and the risk adjusted rate of return profile of this opportunity. The acquisition of AER is being accomplished through a newly created subsidiary of Dynegy, Illinois Power Holdings or IPH, which will be a ring-fenced, nonrecourse subsidiary other than a $25 million Dynegy guarantee that will observe corporate separateness formalities. In structuring the transition, we established and followed these principles: IPH must stand on its own and be a viable self-sustaining business; Dynegy cannot and will not put its balance sheet at risk; and there is no intent, no plans and no reason to engage in any type of financial restructuring of Genco's public debt. Prior to covering the transaction details on Slide 18, I'd like to demonstrate the investment thesis for our shareholders. As we covered in our January 2013 Analyst Meeting, the upside embedded in our equity is primarily through our coal portfolio. This transaction requiring minimal to no capital from Dynegy dramatically magnifies our upside leverage for the same fundamental value drivers to which our investors want exposure, tightening reserve margins resulting from retirement, higher power prices, increasing capacity payments and a strengthening national gas curve. I've illustrated the risk/reward profile point using our sensitivity to natural gas as an example. The chart on the left depicts this asymmetric risk. A $1 move in natural gas for the combined portfolio is 2.2x more leveraging than stand-alone Dynegy, whereas there is no incremental downside due to the ring-fence structure and minimal or no capital being deployed by Dynegy. To further illustrate the point, a positive $1 per million BTU move in natural gas prices increases annual EBITDA by $150 million or $1.50 per share for Dynegy's stand-alone portfolio. Adding AER to the portfolio more than doubles the uplift to $332 million or from $1.50 to $3.32 per share. This upside leverage cannot be replicated on a stand-alone basis. Theoretically, to obtain this leverage, our outstanding share count would have to be reduced by 55 million shares from 100 million to 45 million shares outstanding, which would require over $1 billion of capital, which obviously is impractical, and you would still retain an equal amount of downside risk. Creating this asymmetric risk return profile while protecting our balance sheet and maintaining our capital allocation flexibility is what makes this opportunity so compelling. Slide 19 shows a side-by-side comparison of the 2 coal fleets. And as you can see, the portfolios are geographically in the same region, are similar in technology, utilized Powder River Basin coal as the main fuel and will be compliant with the Mercury and Air Toxics Standards in 2015. In addition, both portfolios have maintained high-capacity factors throughout the recent low natural gas price environment. One difference between the fleets, however, is the gen-weighted average dispatch cost, which is primarily attributable to the difference in the cost of delivered coal. I would note, however, that AER's more favorable base position partially offsets this economic impact. Slide 20 lists the steps that will occur prior to closing. First, Genco and Ameren will exercise the existing put option agreement that enables Genco to sell their natural gas plants, including Elgin, Grand Tower and Gibson City, to a subsidiary of Ameren. Ameren's purchase of these 3 gas facilities will be at a minimal price of $133 million, which is calculated using the average of 3 appraisals for these assets. These appraisals are required to be updated prior to exercising the put option. And any change in the updated average valuation results in the following treatments: as the updated valuation is less than $133 million, Genco will receive $133 million at closing. If it is greater than $133 million, Genco will receive the higher amount at closing. Furthermore, if Ameren subsequently sells these assets within 2 years after closing, any after-tax proceeds in excess of what Genco received from the appraisal process will be remitted to Genco. Dynegy's newly formed subsidiary, IPH, will then acquire AER. Slide 21 highlights several of the key transaction terms by counterparty. In addition to the put option agreement just discussed, an additional incremental $60 million in cash will be funded by Ameren to AER and subsidiaries for general corporate purposes. AER and its subsidiaries will also retain $25 million in existing cash, plus $8 million from expected land sale proceeds. Of this total $93 million in incremental cash, $70 million will be at Genco and the remaining $23 million, shared by AERG and AEM. Ameren has also agreed to provide collateral support to these entities for all outstanding contracts and hedges for a 2-year period from the date of closing. In addition to the cash and 2 years of collateral support to AER from Ameren, AER's consolidated net working capital at closing will be approximately $160 million, which has been determined using historical operating needs and practices. With $226 million in cash, $160 million of working capital and 2 years of collateral support, we believe that AER and its subsidiaries will have the financial resources they need to operate successfully and independently from Dynegy. Regarding environmental issues, the general principle followed with some exception is that Ameren retained responsibility for all inactive sites and risks outside of the operating plant locations, while the IPH subsidiaries retain responsibility for everything on site of the operating locations. The 2 exceptions to this principle are first, IPH will provide Ameren an indemnity for a potential off-site liabilities associated with coal combustion byproducts up to a maximum of $25 million; and second, Ameren will provide an indemnity to IPH associated with the Dove Creek rail embankment exposure. Dynegy, for its part is providing a $25 million guarantee extending for 2 years beyond the closing date for certain pre-closing payment obligations of IPH and certain post-closing indemnification and reimbursement obligations of IPH. The transaction benefits are highlighted on Slide 22. Carolyn Burke, our CAO, will lead our integration team, and momentarily will review in more detail the operational benefits and synergies targeted at a $60 million run rate in 2014 with significant upside potential thereafter. Our experience with our PRIDE initiative over the past 18-plus months combined with the diligence we performed gives us the confidence that these synergies are obtainable. Furthermore, this transaction spreads our current general administrative costs as well as additional operations support costs, over a much larger base benefiting our existing business. Prior to the synergies discussion, I want to highlight the excellent work Ameren has done on moving a substantial portion of its generation from MISO to PJM on Slide 23. Ameren has previously disclosed that Ameren Energy is in the process of expanding its transmission position into PJM. There is approximately 800 megawatts of transmission available to Ameren with no upgrade cost. This newly available capacity, along with the existing 150-megawatt of transmission capacity from the Edwards facility in the PJM, results in Ameren's ability to deliver over 900 megawatts into the PJM energy markets and the ability to participate in the upcoming 2016, 2017 base residual auction. With this capacity potentially leaving Miso for the PJM market, the Ameren coal fleet will benefit from the higher price markets for both energy and capacity, improving earnings and providing greater visibility of capacity payments available in the PJM market. The estimated impact of energy delivered into the PJM market through this transmission is approximately $1.25 per megawatt hour, improvement in busbar prices based on a comparison to busbar LMP pricing during 2011 and 2012. This uplift, assuming full utilization, equates to approximately $10 million per year for the megawatts delivered in the PJM. The approved unit contingent capacity after adjustment for historical average [ph] rates associated with this available transmission is about 840 megawatts for planning year 2016, 2017. This capacity is eligible to be offered into PJM capacity options. The estimated uplift for capacity payments in 2016 and 2017 versus what the facilities received today would be approximately $35 million based on the 2015, 2016 PJM auction clearing price of $4.14 per kW a month. In addition, the departure of these megawatts from MISO would further tighten reserve margins within MISO. A significant benefit of this transaction, Ameren's retail business covered on Slide 24. In AEM, we are acquiring an established retail marketing platform that currently reaches customers of MISO, as well as PJM. The customer base is diversified, including municipals, co-ops, commercial, industrial, small business and residential sectors. The Homefield energy brand markets to residual and small business customers and serves 141 communities and nearly 500,000 homes and small businesses. AEM provides much of what we are seeking to accomplish through our own grassroots retail offering but on a much larger and established scale, something we cannot replicate. Not only does retail realize the benefits from competitively priced retail products backed by owned generation that provides the ability to better manage basis exposure across the Illinois coal assets. We see growth opportunities in residential sales as the Ameren Illinois market has only seen 20% of residential customers switching to retail providers through 2012, leaving a large pool of available customers. We also see retail growth opportunities in PJM with our existing generation presence in PJM plus additional MISO capacity we'll be placing in PJM, we'll be able to offer very competitive pricing in the combined [ph] territory to grow our presence there. Carolyn Burke will now address the synergies of the transaction.

Thanks, Bob. One of the significant value drivers of this transaction is simply the combination of 2 exceptional coal fleets. Benefits increase exponentially when you combine 2 of the strongest portfolios in the MISO region. On the Dynegy side, we are able to leverage our very scalable infrastructure across another set of assets and gain an established retail business. As you know, we only just announced our intention to enter into the Illinois retail space in January. This transaction not only saves us the time and costs of building a new business, but we gain a high-quality seasoned team that will be able to take advantage of its new larger portfolios of AER and Dynegy assets. The AER business, on the other hand, will benefit from our relentless focus on continuous improvement through our PRIDE program. We have a proven track record of driving margin and cost improvements. As Clint discussed, PRIDE has driven over $82 million of fixed cash cost improvement and $25 million in gross margin improvements in just its first 2 years. We are committed to delivering similar results at AER. Together, our combined operational expertise in safety, environmental and engineering will deliver real value to shareholders. On Slide 26, we have laid out that real value and what we expect to deliver in year 1. $60 million in total EBITDA run rate improvements through margin, O&M and G&A enhancements. We will be driving increased margin through EFOR improvement as we have with our end market availability improvement programs at Dynegy. We will also look at fuel procurement practices and bring our success and expertise at CoalCo to AER. On the O&M side, we expect significant synergies through the combination of our engineering, maintenance and outage planning expertise. Our vendor optimization program, successful here at Dynegy, will be rolled out to AER. Finally, G&A. Our existing infrastructure has managed 20,000 megawatts in the past. It can easily support an additional 4,100 megawatts now. Real programs, real initiatives and real savings. And as is our practice, these are conservative estimates. Once we close the transaction, we expect our combined teams will identify further improvements. And with that, I'll turn it over to Clint.

Thanks, Carolyn. As reflected on Slide 27, AER's 3 subsidiaries have separate and distinct financial profiles. Of the 3 businesses, Genco is the only one with third-party debt, which today totals $825 million and requires annual interest payments of $59 million. With the earliest maturity date being 2018, Genco has 5 years before any refinancing will be required. Maintenance CapEx requirements for the Genco fleet are relatively modest. However, we do expect an uptick in 2016 and 2017 as certain projects previously deferred are pursued. On the environmental side, most of Genco's CapEx requirements relate to the installation of a scrubber at the Newton facility, which requires an investment of $15 million to $20 million per year through 2017, then ramping up in 2018 and 2019 as major construction takes place. With the debt and CapEx requirements at Genco, liquidity is at a premium, so the transaction has been structured to ensure that the company has over $200 million in cash and sufficient working capital deployed to support the ongoing financial requirements of the business. With only 2 plants, minimal CapEx requirements and no debt outstanding, AERG's liquidity needs are more modest and will be supported with existing working capital deployed in the business at closing and cash balances currently estimated at $23 million, which will be shared between AERG and AEM in an intercompany money pool. With a significant portion of the working capital volatility at AERG and AEM tied to purchases and sales of power between the 2 entities, the money pool arrangement should help even out and reduce intra-month liquidity needs between the companies. We continue to evaluate the need for additional working capital for AERG and AEM, and should additional financing be required, we will consider putting in place a secured working capital line either through a third-party financial institution or, perhaps, by DI. As Bob mentioned earlier, we expect this transaction to be accretive to adjusted EBITDA in 2014 and free cash flow in 2015 based on what we view to be very reasonable assumptions, as outlined on Slide 28. In addition to using the current NYMEX natural gas curve, our analysis uses heat rates in line with current market implied levels; synergies of $60 million per year, with 80% realized in 2014 and 100% realized in 2015; and CapEx levels outlined on the previous slide. We also assume that MISO capacity prices converge with PJM capacity prices over the medium to long term, but I would note that a majority of that convergence is assumed to take place post 2015 and is not instrumental in achieving our free cash flow accretion target. And with up to 900 megawatts of the AER fleet moving to PJM by 2016, our expectation for MISO capacity price recovery to levels comparable to PJM are at least partially hedged for this fleet. One of the central themes to Dynegy's value proposition is the company's upside exposure to market recovery and pool retirements in the Midwest. Earlier in the presentation, Bob walked through the asymmetric risk-return profile of the AER acquisition as it relates to improvements in natural gas prices. But as Slide 29 reflects, this is not just a natural gas dynamic. The same asymmetric relationship exists for other market factors as well, including power prices and capacity prices as coal plant retirements occur over the next several years. With little to no capital allocated to this transaction upfront and no new shares of common stock issued, the acquisition of AER provides current Dynegy shareholders with substantial additional upside potential and, with the transaction structure as described earlier, significant downside protection. Bob, I'll turn it back to you.

Thanks, Clint. Slide 31 summarized how we approach this transaction: protect our equity against downside risks, strengthen both portfolios to create upside leverage for our shareholders and preserve Dynegy's balance sheet and capital allocation opportunities. At this point, Wendy, I'd like to open the line for Q&A.

[Operator Instructions] Our first question today is from Brandon Blossman with Tudor.

Let's see. Just touching on the AER debt a little bit, any covenants that should be of concern over the next 2 or 3 years, and any -- and I assume it's not amortizing debt, correct?

That's correct. They're bullet maturities. As it relates to covenants, there really are no financial covenants. The only ratios that are in there really deal with debt incurrence, as well as the ability to make restricted payments out of the entity. But as far as financial covenants that could be triggered, there are none.

Great. And then I guess also just from the purchase and sale agreement perspective, the $25 million guarantee, is that the absolute limit to Dynegy parent liabilities here?

That's correct, and that expires 2 years after closing.

Okay, great. And then just one more, and I'll get back in the queue. As far as the hedge profile at AER, I assume it's a fairly big hedge book right now. Do you intend to roll that off as the guarantee from Ameren rolls off?

Well, it's roughly 50% hedged for 2014, I guess about 20% hedged in 2015. Our plan would be to, as those roll off, to look to see if there's a way for us to provide -- if there's available credit in the marketplace, do a first-lien type structure. We'll work through that as time goes on. Also, their retail book offers some level of hedge protection for the portfolio as well.

Our next question is from Jon Cohen with ISI Group.

A couple of questions. First of all, does -- on your conditions to close, does the Illinois Commerce Commission have any ability to review the deal?

No.

And how do you think FERC will look at market power issues? It looks like 7,000 megawatts of merchant generation in MISO Illinois. I mean, that's a pretty big chunk of that market, right?

Yes, and we've looked at it with our internal experts, as well as 2 external experts, and all of our analysis shows that this should not come close to creating a market power issue. Actually, we'll ask Catherine Callaway to comment, on our General Counsel.

Yes. We've looked at it preliminarily and done as much analysis we can. We intend to make our filings very quickly. We expect the transaction to meet FERC's Section 203 market power test and that we can maintain market-based rate authority.

Okay. And then one other question on the synergies. So the $60 million, does that -- can you break down a little bit of what that includes? Does that include some upside on the rail contracts to Ameren's facilities in line with what you guys were able to get? And does it also include the capacity revenue from that increased sales into PJM?

The $60 million is all cost-based synergies. There's no revenue synergies included in that. A good portion of that number is the corporate allocation that comes from Ameren, so that will go away rather swiftly. There is some level of rail procurement synergy in there. There is one contract, one rail contract expiring in the near future. So that's included in there, and then the rest are generally more traditional operating and overhead-type G&A synergies.

Okay. And then I guess one last question on the retail business that you bought. Have you looked at what the retail price that Illinois customers in MISO are paying, the generation component of that relative to what your plant LMPs are? And how much of an uplift is there?

I'm going to ask Brian Despard, who manages our coal portfolio, to comment on that.

Yes. Without going into detail about what is included in the Ameren portfolio, what we're seeing in Illinois is C&I rates that are roughly $2 in margin, and residential, we expect is a bit higher than that. So it's fairly competitive in the state, but we're looking at margins probably in the $2 to $3 range.

But is that to INDY Hub, or is that to plant busbar [ph]?

Plant.

Our next question is from Brian Chin with Citigroup.

On the competitive retail component, can you give us a sense of what the margin is per megawatt hour and retail sales is?

Yes. As I just mentioned, looking at the market, not necessarily at the Ameren portfolio but just what we're seeing out in the market, $2 to $3 depending on customer class. The C&I usually has tighter margins. Residential will have a little bit higher margins, so $2 to $3.

Okay. And what is the level of volume that the retail business is selling at current level?

The Ameren volume is about 50 million megawatt hours a year.

And then just to be clear in case I might have missed this earlier. For the PJM RPM uplift, the $35 million, that uplift is relative to what those plants are currently capturing and whatever bilateral and capacity contracts are in place right now, so that's a net uplift?

Yes, that's correct.

And then as part of the deal, do you have any commitments to keep any of the plants in operation for a period -- for a certain period of time, or do you have maximum degree of flexibility to...

We have [indiscernible].

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

First question here on environmental. Just with respect to Illinois MPS averaging policies, do you expect to be able to realize some of the uplift, if you will, from your existing portfolio over to Ameren? And how does that impact the need to pursue environmental retrofits on the Ameren side?

Julien, all of our assumptions and our planning is that each of the portfolios are standing on their own. There is no ability to do that. Ameren has their existing variance with the Illinois PCB and will continue to operate under that variance assumption.

Okay, fair enough. And then you mentioned that the EBITDA is only accretive in '14. Is that meant to suggest that EBITDA is negative in '13 and is comparably for free cash flow in '15? How do you think about that? What are the year-on-year drivers that we should just be aware of that might not necessarily be intuitive?

Yes. The only reason we started with '14 is just we're assuming this transaction takes pretty much through the end of the year, so we haven't even thought of it in the context of '13. So when we think about first full year of operation, which would be '14, that's where we view EBITDA will be accretive.

Got you. And then with respect to the PJM capacity revenues, just to be clear, how much cleared the last auction, if you will? I think it was only about 100 in change, if you will, or about 100 megawatts, and so incrementally, we're going to see up to 840 in this next auction. Is that the right way to think about it?

That's correct. I mean, the capacity has been granted and offered, if you will, by MISO at PJM, and it's subject only to Ameren's confirmation of the capacity.

And so from your perspective, is there any opportunity for further exports? I mean, this is arguably the second or third time this has happened. What's that maximum theoretical, if you can kind of provide some -- quantify?

We haven't reached beyond that number in terms of looking at the growth. There is, I think, a larger volume than that available on the MISO side. But it would require basically a restart on the PJM side of the entire analysis and modeling process to look for additional capacity at PJM.

But Julien, I would add that there are requests both that Ameren has in as well Dynegy has in the queue to try to find those opportunities, and both companies are waiting to hear the results of that work and what, if any, capital would be required to expand that number to something greater than the 900 megawatts. So that's under review as we speak.

Great. And then something a little bit further field, California, going back to that for a quick second, what's the latest as it relates to Moss and Morro here? As you look at the portfolio, how much have you been able to contract on Moss 1 and 2 for this year and then your re-contracting efforts in '14 on both VO [ph] units?

Well, for Morro, at this point, we actually have been dispatched. We're operating under CPM at the moment, and Moss Landing continues under its existing contract, but we have not re-contracted that capacity beyond the expiration of the contract at this point in time.

Not in terms of the toll, but there is -- RFO just came out for summer [ph] capacity, RA capacity, and we'll be participating in that.

How long is the existing Morro Bay CPM commitment? I will assume you're getting the full price CPM, but for how long should we be modeling that this year?

It was just through -- it's 60-day CPM, and we've got for 50 megawatts, it's going in the -- here, I believe about mid-April.

Our next question is from Stephen Byrd with Morgan Stanley.

As you look at the fleet of Ameren's assets, you've laid out the environmental spend. Is there a potential for us to be thinking about some asset retirements within the Ameren fleet over time? I think you had a general question on it before, but I just want to understand this. As you assess the fleet here, is there anything that strikes you that you might change in terms of how you approach it versus how Ameren approached it?

I think when we look at the forward curves and the economics right now at our planning -- and I would say in our planning, we also assumed incremental CapEx to work on increased reliability in EFOR rates and made some assumptions around potential future capital associated with even coal handling and issues such as that, but when we layer all of that in and look at the existing natural gas curve that exists out there using market implied heat rates and our view around capacity, for the foreseeable future, we see all plants as being economic to run. And that decision, obviously, will continuously be evaluated, and we'd make the right decision at that point in time. The real ramp-up in capital spend really starts in the 2017 time frame. So I think what we'll see as a company is that we'll certainly continue on with the assets as long as they're economical, which, again, we see that being the case. And certainly, in a post-MATS compliance world, we certainly expect stronger capacity payments, higher power prices, so furthering the economic viability of these plants from even what we've built into our base level assumptions.

Understood, great. And then just thinking about the put option, the minimum is $133 million. Given those assets, there certainly seems to be a reasonably good chance that the price is higher than that, potentially significantly higher. What would your -- assuming that it were higher, what should we be thinking about in terms of the usage of that cash? Or would that just basically stay within the Genco for liquidity purposes? Or if it were significantly higher, would you think about other uses for that capital?

No, that cash goes into Genco for Genco operating needs.

Our next question is from Terran Miller with Cantor Fitzgerald.

I might have missed this, but in terms of the $60 million of synergies, what is the breakdown between what's going to be realized at the individual businesses? Does the bulk of that accrete to Ameren gen, or does a significant portion of that go to Dynegy?

Well, those synergies, the $60 million within AER and its subsidiaries, now some of that, again, relates to a fairly substantial corporate overhead charge that will be replaced with a Dynegy overhead charge, if you will. So that will be spread amongst the entities. How that $60 million ultimately breaks down between the various subsidiaries at this point in time, we don't want to get that granular until we spent a lot more time around specific identification and how we want to organize things as we go forward. That's as close as I can get for you, Terran, on that.

Okay. Just a follow-up then. They have talked about $30 million to $35 million of corporate allocation, so are you saying that the $60 million includes that going away and it will be replaced by an allocation from Dynegy? Or is the $60 million net of that savings for what the Dynegy allocation will be?

The allocation that we've done our planning around is not quite as high as that number, but that -- but your statement is correct that that number would go away. And then as Dynegy looks to reallocate its corporate overhead to GasCo, CoalCo and now AER, we need to come up with the right fair arms-length methodology in all 3 of those units.

Okay. So that is gross before the Dynegy allocation, so that will be an offset to that $60 million?

Yes, that's correct.

Our next question is from Lance Ettus with Tuohy Brothers.

Obviously, I think you'll be up to close to 14 gigawatts of capacity, but you have a decent amount of that in the Midwest, obviously. So does this preclude you? And there's tremendous synergy opportunities, sorry about the long-winded question here. But can you guys do more deals potentially in the Midwest after this? I know that Mission Energy is bankrupt, so maybe that's in play. I guess comments on that, and also, I have one follow-up question.

Lance, I actually don't know the answer to that question. I presume it depends on the specific market as to what level of market power would exist there, so that would have be an analysis to an asset-by-asset basis, and I -- we haven't looked at that, so I don't really know the answer to that. I have to say that right now, particularly after spending the last 3 months working on this, I can't even think about another one at this point in time. I mean, the priority for us is to run and execute the Dynegy businesses really, really well and integrate this acquisition quickly, efficiently and run it very, very well. And to even think about anything, I mean, I'm speaking from my perspective, for us to think about anything beyond that at this point in time, I just haven't even begun to think that because these 2 priorities are so significant to make sure we get this done right and we have the successful enterprise is where my priority is completely focused on from this point forward.

Okay. And is there -- obviously, the synergies, the larger you get in merchant generation, but is there increased synergies to be more concentrated in more fuel types in more coal plants versus a diverse mix, or does it not matter?

I think it absolutely matters. I mean, you've got the skill set. You've got similar technologies, your central engineering units, your scale on working with coal providers or coal transport companies, so it makes a big difference. The one other thing to your earlier question that we haven't really spoke about yet on this call, when we think about priorities for 2013, we talked about, obviously, running Dynegy well and being very successful on integrating this transaction. Doing our corporate level refinancing is a priority that immediately takes center stage now. We've been delaying that because of this acquisition. Now that this acquisition is announced, we're prepared now to move forward very quickly on our refinancing, which is a critical priority as we go forward. Substantial value creation is on the table by getting that done quickly.

Our next question is from Jason Mandel with RBC Capital Markets.

I just want to make sure I clarify and understand best what the cash is going to look like at Genco and AERG. I realize you've provided some good information, but there's some bits and pieces floating around. Can you talk about -- you guys have mentioned the $70 million of cash in Genco. I presume that's in addition to the $133 million that comes in from the asset sale? And as a separate comments about the $60 million contribution, and then of course, there is the $60 million expected from tax sharing during 2013 from Ameren, and given this isn't going to close until the end of the year, just curious how all those play into sort of pro forma year end.

Yes, Jason, let me just -- because we did throw a lot of numbers out there. So total cash at AER and subsidiaries will be $226 million. Of that $226 million, $203 million would be at Genco, and then $23 million would be shared between AERG and AEM.

Okay, perfect. And just to clarify, for any differences that occur throughout the year, that would just be sort of settled up at the end of the year, and those are going to be the balances for the purchase and sale agreement.

That's correct.

Our next question is from Jon Cohen with ISI Group.

I just had a follow-up on the dispatch costs. I think your fleet was $17 a megawatt hour, and you're saying Ameren's is $23. Can you give us a sense of what the differences are? Is it just rail transportation? And if you were able to renegotiate...

The $17, we're still operating under our legacy coal transportation contract that goes back quite a few years. Theirs have been more recently priced to market in the past several years, so that's the primary difference. Also, the coal commodity cost for Ameren's fleet tend to be higher because they do more longer-term purchasing. We've done more -- we tend to do our pricing in the prompt year. PRB coal has the history of having the contango that disappears each time they get towards the prompt year. So it's really when you think about coal transportation and coal commodity costs, that's the difference. When our new rail contract starts in '14, that will take our number from $17 upwards to between $19 and $20, so then the difference narrows. But then the other point that I made, even though that our dispatch costs would be still a few dollars lower, their basis is lower than ours, so they have an economic advantage there where their plant, in general, dispatch at a differential to the hub of $2 to $3, where we're right now, $4 to $5 to $6, depending on what month you're talking about. So when you take all of those factors into consideration, 2014 and moving forward, that difference on a kind of a gross margin basis really flattens out pretty close.

Okay. And to the extent that some of that $60 million is for rail transportation cost synergies, that will reduce their dispatch cost and presumably increase their capacity factors?

That's our goal.

[Operator Instructions] Our next question is from Stephen Byrd with Morgan Stanley.

Just one follow-up. Just thinking about that gas asset, could you just talk to the rationale for not acquiring the gas assets?

Sure. From the Dynegy perspective, the one thing that we found very difficult to address was the put option structure that was embedded between Genco and affiliated companies. And to try to work through that put option structure and getting in the middle of that is not something that we felt comfortable doing. So the arrangement that we worked out with the Ameren team is that they would handle the put option, so that was really the driver between separating the gas and coal. And also, what we're really interested in here, too, was obviously taking a coal fleet that's almost identical to our coal fleet and realize the benefits of the scale of putting those 2 together. So it made for a cleaner, more easily executed contract.

Our next question is from Terran Miller with Cantor Fitzgerald.

Just a separate question. On Newton, do you have an updated estimate of what you think the scrubber is going to cost going forward?

I think our estimates around that is that the absolute cost is about $500 million, of which about $200 million has been spent. I have Dan Thompson from CoalCo here, who can comment on that.

Yes. Bob, the total direct cost is right there at -- you figure $500 million -- excuse me, $450 million. And then you have another $50 million of other costs. And then on top of that, you got the AFUDC [ph], so our modeling reflected the Ameren estimates.

And of that amount, approximately $200 million has been...

Yes. Bob, about $230 million, $240 million has been spent and maybe north of that at this point, but about $240 million has been spent to date.

Okay. And you’re comfortable at this point that that number doesn't go up if you continue to spend the $15 million to $20 million a year through 2017?

That $15 million to $20 million that Clint referred to is in the plan, and that's consistent with our view and what Ameren's plan is.

Okay. And those numbers were as of year-end '12, I assume, right, the $200 million spent?

Yes.

Fairly close to that. I'm not sure if some of that...

Okay. But that's the approximate date for the number?

Yes.

Our next question is from Amer Tiwana with CRT Capital.

I wanted to sort of confirm that you're still planning on refinancing at the DI level, and you had given an estimate for additional liquidity that would come onto the balance sheet from the restricted cash becoming unrestricted, if that's still true.

Yes. I think this transaction really does not change our thinking around the refinancing. So I think at this point, our plan would be to still target refinancing at the DI level. And as you said, our plan is to refinance it in a way that does free up the restricted cash that's currently on our balance sheet and make that unrestricted and available at the DI level. So from my perspective, nothing really has changed on that front.

Thank you. And I'm currently showing no questions.

Okay. Well, I'd like to thank everybody for dialing in, and that this point, I'll conclude the call. Thank you, Wendy.

Thank you. This does conclude today's conference. Thank you very much for joining. You may disconnect at this time.