Dyne Therapeutics, Inc. (DYN) Q3 2013 Earnings Report, Transcript and Summary

Hello, and welcome to the Dynegy Inc. Third Quarter 2013 Financial Results Teleconference. [Operator Instructions] I now would 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 third 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 today. Before I introduce the executive team, I would like to first announce that this Laura's final earnings call as the Managing Director of Investor Relations. Laura will be moving within the company to Corporate Strategy, working for Mario Alonso and will continue to be a very important part of our Dynegy team. I want to recognize and thank Laura for the excellent work she has done in IR, and I look forward to continuing my work with her in our corporate strategy-related activities. Replacing Laura is Andy Smith, who joined Dynegy this week and is in attendance. With Andy's long history on the sell side with JPMorgan and, most recently, with Drexel Hamilton, he's a familiar name to investors in the power generation sector and to many of our shareholders. From our executive management team with me this morning are Clint Freeland, our Chief Financial Officer; Hank Jones, our Chief Commercial Officer; Catherine Callaway, our General Counsel; and also in attendance for her first Dynegy earnings call is Sheree Petrone, our Vice President of Retail, who joined Dynegy in August of this year to run the Retail business being acquired from Ameren. Our agenda for today's call is located on Slide 3. I'll provide an overview of the third quarter results followed by an update on recent significant events, including the Ameren Energy Resources acquisition; the labor agreement reached for the Coal segment union employees; the multi-year supply agreement Moss Landing units 6 and 7 recently entered; and a review of our operating performance during the quarter, including our PRIDE continuous improvement targets. Hank Jones will provide an update on our commercial hedging activities; plans for our California portfolio, including retirement of the Morro Bay plant; and an update on potential transmission projects. Clint will review the third quarter financial performance liquidity in our 2013 guidance. I will close the discussion by highlighting themes for upcoming Analyst Day planned for the first quarter of 2014. And with the remaining time, we will open the discussion for the Q&A session. An overview of the third quarter results is shown on Slide 4. The third quarter was injury-free, furthering this year's significant improvement to our total recordable incident rate. Year-to-date, our recordable incident rate stood at 0.7, down from 0.99 through the end of June. For the first 9 months of the year, we had 11 recordable injuries, down from 26 injuries during the same period last year. The Gas segment continues its excellent safety performance with only 1 employee recordable injury year-to-date. Our goal is to make every quarter like this third quarter, injury-free. Generation from our gas fleet declined 24%, primarily due to lower spark spreads. Coal-powered [ph] generation increased 11%, primarily due to lower planned outages versus the third quarter of 2012. Adjusted EBITDA for the Coal segment declined $5 million compared to last year due to several factors, including lower realized prices on our hedged and unhedged volumes, although this was partially offset by fewer planned outages and lower coal prices. More than offsetting the Coal segment decline was a $64 million period-over-period improvement from our Gas segment. This improvement was primarily due to the absence of legacy commercial positions that negatively affected 2012 results and improved capacity pricing. Finally, we are reaffirming 2013 guidance for adjusted EBITDA and free cash flow that we provided on our previous conference call. Slide 5 highlights several significant recent developments. First, on October 11, we received FERC approval for our proposed acquisition of Ameren Energy Resources, or AER. This leaves only the Illinois Pollution Control Board approval, which we have petitioned for a variance that would allow AER to delay full compliance under the state's Multi Pollutant Standard to January 2020. This request is consistent with the variance previously granted Ameren and voluntarily provides additional restrictions beyond the variance granted to Ameren. We expect a decision from the IPCB on or before November 21, and we remain confident that it will result in the requested variance being granted, in which case we intend to close the acquisition in December. Secondly, in August, we reached agreement on a new collective bargaining contract with IBEW Local 51, which represents approximately 400 employees at our 4 Illinois coal plants. This new agreement runs through mid-2017. And as a result of this agreement, we recorded a $71 million reduction in pension and other post-employment benefit liabilities associated with the existing plans for these employees. Hank will cover the third event in additional detail, which is the resolution with Southern California Edison of the early termination dispute between the 2 companies dating back to 2012. This commercial resolution resulted in 2 new energy and capacity contracts for Moss Landing units 6 and 7, a great outcome for both the company and the State of California. The first contract is for 2014 and 2015, and the second contract covers 2016. The energy toll is for the entire 1,500 megawatts for each of the 3 years, while the amount of capacity contracted under these arrangements increases over the contracted period. These agreements improve the financial viability of these 2 valuable, fast-ramping units. While we have successfully contracted the Moss Landing units, current market conditions within the California marketplace remains weak, and in response to the lack of commercial opportunities, we are initiating the retirement process for Morro Bay units and are exploring alternative uses for the site. Slide 7 highlights the third quarter fleet performance. With the lower spark spreads in 2013, the capacity factors for all of our combined cycle units were down quarter-over-quarter. Most of our plants experienced lower on-and-off peak spark spreads across the fleet. However, despite the reduction in spark spreads, our independent and Ontelaunee facilities continued to have capacity factors over 70%. We are anticipating that the very low capacity factor experienced by our Casco Bay plant will improve with the expected expanding access to natural gas supply. Capacity factors for our Coal segment were higher, primarily due to fewer planned outages this quarter. During September of last year, 1 Baldwin unit was in outage for the final leg of its Consent Decree work. The in-market availability, or IMA, and equivalent availability factor, EAF, for our Gas segment were virtually unchanged in the mid-90% area or higher. For our Coal segment, the EAF improved due to fewer planned outages, but the IMA declined due to an increase in unplanned outages. Notwithstanding the additional unplanned outages, we still had an IMA of 90% for the quarter. Slide 8 highlights the latest update on our PRIDE program. This program continues to generate positive results with forecasted earnings improvement of $43 million this year and over $190 million in balance sheet efficiencies. With lower outage costs, reduced gas supply cost and improved heat rates, our gas fleet is driving our 2013 PRIDE earnings contribution, while balance sheet improvements are far exceeding our initial projections after the renegotiation of a service contract, the successful conclusion of the Coal segment labor contract and our continued focus on first lien usage. The addition of the AER portfolio will open up new opportunities to drive cash improvements through our PRIDE program into 2014. I will now turn the call over to Hank for a review of our commercial activity.

Thank you, Bob. Slide 10 provides an update on our hedging activity for our power generation and fuel supply. Our hedge level for the Coal segment for the balance of this year has increased slightly quarter-over-quarter and is presently at 60%. The overall hedge levels for the Coal segment reflects our hedging optimization strategy, which utilizes busbar sales and FTRs to mitigate basis risk to maximize the effectiveness of our hedges. In order to mitigate correlation risk between INDY Hub and the LMP, we keep a portion of the fleet open to market. Approximately 36% of projected 2014 Coal segment production volumes are hedged in 2014, which is a slight increase over the 34% reported as of July. Approximately 70% of the 2014 hedge volume is matched with either FTRs or busbar swaps. Hedges for our Gas segment in 2013 are virtually unchanged from our previous call with 77% of our output hedged for the balance of this year. Hedge volumes decreased slightly for the Gas segment in 2014 on a percentage basis. This percentage change is a result of an increase in our expected generation rather than a reduction in absolute hedge volumes. 2015 hedging levels are currently 4% and 6% for the Coal and Gas segments, respectively. We have purchased and fixed the price on approximately 11 million tons of coal for 2014 delivery, which represents approximately 93% of our projected annual volume requirements. And we have purchased approximately 6 million tons or 53% of our projected annual volume requirements for 2015 delivery at an index price subject to a price collar. Our rail transport contract price is fixed through 2015 and beyond, and our natural gas supply position is consistent with our forward power sales with 37% of our projected natural gas needs purchased under fixed price swaps and physical contracts in 2014. Looking at Slide 11. With the completion of the Mt. Vernon transmission work in June and a lack of major transmission outages during the summer months, as anticipated, the basis differential between INDY Hub and the busbar prices in the Coal segment improved during the third quarter, resulting in a generation-weighted basis of $5.17 per megawatt hour. Although our October gen-weighted basis has increased to $7.58 per megawatt hour due to generation and transmission outages around our fleet, we expect the last 6 months of 2013 to be in line with our updated basis expectation of $6.70 per megawatt hour that we provided last quarter. We have approximately 900 megawatts and 650 megawatts of around-the-clock basis hedges in place in the form of busbar swaps and FTRs in November and December of 2013, respectively. Turning to Slide 12. As we discussed during our last earnings call, we continue to pursue multiple transmission solutions that would reduce congestion near our facilities, thereby improving market access. We continued work on 2 potential transmission debottlenecking projects, which are not part of the 2013 MISO Transmission Expansion Plans and will require -- and would require funding by Dynegy. A proposed project near Baldwin would relieve congestion for the Baldwin and Wood River plants through a transformer replacement and transmission line upgrade. Preliminary cost estimates for this project are in the range of $15 million to $20 million, with potential completion in the summer of 2015. Another proposed project to benefit the Dynegy legacy fleet, as well as the AER plants, involves a transmission line upgrade near the Indiana border. This project would address potential future congestion that will occur during various construction phases and on completion of MISO's Illinois River Project beginning in 2017. The preliminary cost estimate for this project is $30 million to $40 million, with completion targeted for summer of 2017. As these projects would benefit other generators as well as Dynegy our development efforts will include seeking third-party capital investment from the beneficiaries of these projects. We also have several transmission service requests pending with various transmission operators to evaluate the feasibility of exporting capacity to PJM, and we expect to receive preliminary cost estimates early next year. Turning to Slide 13. As discussed last quarter, there are a series of developments impacting the planning and operating reserve margins in MISO, 3 of which I will highlight. First, the MISO independent market monitor provided recommendations for improvements to MISO's capacity market design in order to send appropriate price signals to market participants to ensure investment and grid reliability. As referenced in MISO's resource adequacy framework from the markets committee of the Board of Directors dated October 23, 2013, MISO accepted 1 of the IMM's recommendations, which is to remove its previous reliance on external demand side management resources and to only account for summer peak hours to determine import limits when calculating operating reserve margins. Acceptance of this recommendation has decreased the total of accounted imports by approximately 4.5 gigawatts of resources in MISO's operating reserve margin calculation for the 2014 summer assessment. Second, MISO's recent Loss of Load Expectation study for the 2014 planning year utilizes a revised methodology to calculate the import and export capabilities between local resource zones within MISO and import-export capabilities with external entities, which may have an impact on intrazonal balances, resulting in a higher local clearing requirement in several zones versus the 2013 planning year. And finally, MISO has raised the reserve margin target from 14.2% in the 2013 planning year to 14.8% in the 2014 planning year to reflect the adoption of a more conservative approach to operating reserve margin calculations. This requires 600 megawatts in addition to the 4,500 megawatts that I noted above. Incorporating these revisions with the effect of projected 2015 generation retirements, net of new builds, plus nominal load growth of 0.8% per annum, implies a MISO operating reserve margin of approximately 19% in 2015. In 2009, reserve margins in MISO were approximately 18% and capacity traded at $2.00 per kw-month. If the 2014, 2015 auction would clear at this price, Dynegy would receive incremental earnings of approximately $72 million in the 2014, '15 planning year for the Dynegy legacy fleet. Applying the balance of MISO-forecasted generation retirements and netting out confirmed exports to PJM in 2016 results in a potential shortfall below the planning reserve market requirement of approximately 6 gigawatts of generation capacity and yields a potential reserve margin of approximately 8%, which is well below MISO's target reserve margin of 14.8%. Under this scenario, we would expect not only an increase in capacity prices in 2016, but also scarcity premiums attached to energy and ancillary services prices during times of peak demand or tight supply. In summary, based solely on MISO's exclusion of non-firm imports and the confirmed exports to PJM, MISO's operating reserve margin in 2016 would be approximately 19%, which is only 4 to 5 gigawatts over the stated target reserve margin of 14.8% before accounting for retirements, net of new build and forecasted load growth. As a point of reference, MISO forecast retirements, net of new build, of approximately 8 gigawatts and load growth of 0.8% per year. Turning to Slide 14. As Bob mentioned earlier in the call, we have had several positive developments regarding our California portfolio. At Moss Landing 6 and 7, we've reached a significant agreement to resolve our early termination dispute with SCE, ensuring the plants' financial viability for the next few years with 2 combined energy tolling and RA transactions. The first transaction covers tolling and RA capacity for 2014 and 2015. The second transaction is for 2016 and is subject to approval by California's Public Utilities Commission. At our Moss Landing 1 and 2 units, we have sold approximately 690 megawatts of RA capacity for next summer and 200 megawatts for the summer of 2015. We will continue to pursue RA sales on remaining available capacity at Moss 1 and 2, as well as Moss 6 and 7. Our Oakland Facility operates in the Bay Area Load Pocket. We are currently working with Starwood Energy Group regarding potential development alternatives at the site, which may include a combined heat and power project, energy storage or a combination of the 2. And at Morro Bay, we are initiating retirement proceedings for both units with an expected shutdown in the first quarter of next year. In addition to our Oakland site, we are also exploring development opportunities with Starwood at Morro Bay, which may utilize alternative technologies at this site while maintaining our existing transmission rights. Before I pass the call over to Clint, on Slide 15, I want to highlight a few fuel supply initiatives that are underway. First, due to declining production at Sable Island and delays in the expected ramp-up in production at Deep Panuke, it has been historically challenging to procure economic gas supply for Casco Bay. However, we are beginning to see improvements as the Deep Panuke gas supply is coming online and producing greater volumes. As Bob mentioned earlier, we expect to see higher capacity factors from Casco Bay in the future as a result of improved gas supply for this location. Second, at Investor Day, we discussed the improvements in gas supply for Independence as the increase in Marcellus gas being delivered to the region allows us to reduce reliance on a more expensive Canadian gas supplier. We have beaten our original 2013 targets of 75% by providing 82% of our gas supply from Marcellus. And by 2015, we expect Independence will be running 100% on lower-cost Marcellus gas. Lastly, our Coal team has been exploring the viability of installing refined coal facilities at our coal plants that would clinically treat our coal to lower emissions. If implemented, installation of these refined coal facilities will result in a savings of $1 per ton or $12 million annually and require no capital investment by Dynegy. Should we decide to move forward, our target would be to have these facilities in place and operational in the first half of 2014. I would like to now pass it over to Clint for a financial review.

Thank you, Hank. The company's third quarter and year-to-date financial summary is outlined on Slide 17. And as you can see, the third quarter consolidated adjusted EBITDA totaled $113 million compared to $50 million in the third quarter of 2012, as a meaningful improvement in Gas segment results more than offset weakness to the Coal segment. Despite a 24% decline in total generation volumes and generally lower spark spreads, the Gas segment adjusted EBITDA more than doubled to $121 million, primarily due to higher capacity and resource adequacy payments and the absence of negative financial settlements on legacy commercial positions, which adversely impacted results last year. The Coal segment, on the other hand, remains under pressure as lower realized prices and higher rail transport costs more than offset higher generation levels and lower coal commodity costs. Year-to-date, consolidated adjusted EBITDA totaled $164 million compared to $99 million during the first 9 months of 2012. The significant reduction in negative financial settlements year-over-year was primarily responsible for the $111 million improvement in Gas segment earnings, while lower realized prices and higher rail costs resulted in a $52 million decline in Coal segment results. Total liquidity as of Monday, November 4, was $891 million, including $597 million in unrestricted cash and $294 million in unused availability under Dynegy's corporate revolver. As we've spoken about before, a meaningful portion of the company's liquidity has historically been dedicated to supporting its hedging activities, both in the form of outstanding collateral postings to hedging counterparties and contingent collateral needed to protect against unforeseen liquidity needs caused by extreme commodity price volatility. One of our priorities has been to reduce the collateral intensity of our hedging program, and we continue to make progress on this front, which I will go into in more detail in a moment. And finally, as Bob mentioned earlier, we're reaffirming our 2013 guidance today. At this point, we expect consolidated adjusted EBITDA to be comfortably within our guidance range and consolidated free cash flow to be at or near the top of its range. Moving to Slide 18. Third quarter adjusted EBITDA for the Coal and Gas segments totaled $127 million compared to $68 million for the comparable period in 2012, as a more than doubling of Gas segment earnings offset a slight decline in Coal segment results. Gas segment adjusted EBITDA totaled $121 million during the third quarter of 2013 compared to $57 million during the third quarter of 2012. Last year's results included $69 million in negative financial settlements, compared to $16 million during 2013, providing a meaningful uplift in comparative results this year. Additionally, stronger PJM capacity prices at Kendall and Ontelaunee and higher resource adequacy payments in California contributed an additional $23 million in revenues compared to last year, which more than offset a $7 million decline in energy margin associated with lower quarter-over-quarter spark spreads and resulting run times. Adjusted EBITDA at the Coal segment fell to $6 million for the third quarter of 2013 versus $11 million the previous year, as lower realized prices on both hedged and unhedged generation and higher rail transport costs more than offset higher generation levels and lower coal commodity costs. For that portion of the generation that was hedged in the third quarters of both 2012 and 2013, realized prices fell by $4.35 per megawatt hour, as average INDY Hub hedge price levels declined from $30.74 per megawatt hour to $27.04 per megawatt hour and average around-the-clock basis widened by $0.65. This, together with the $2.04 per megawatt hour reduction in average realized prices on that portion of the segment generation that was unhedged in both years, led to a $14 million decline in energy revenues. Partially offsetting the impact of lower realized prices was a 560,000-megawatt hour increase in total generation period-over-period and a $3 million reduction in the delivered cost of coal. Year-to-date, Gas segment adjusted EBITDA totaled $235 million compared to $124 million during the first 9 months of 2012. Similar to the quarterly results, a $130 million reduction in negative settlements associated with legacy commercial position accounted for the difference in the year-over-year variance and was only slightly offset by an $11 million decline in energy margins, as lower spark spreads across the fleet resulted in a 26% drop in generation volumes. At the Coal segment, a $3.05 per megawatt hour decline in average realized prices on the hedged portion of the fleet led to a $31 million reduction in energy revenues, which, together with $11 million of higher rail transport cost and $6 million in higher O&M costs related to outages, drove the $52 million reduction in year-over-year segment results. As I mentioned earlier, Dynegy's liquidity has continued to improve, as reflected on Slide 19. Since the end of the second quarter, total available liquidity has increased by almost $150 million, as cash generated by the business and collateral returns boosted unrestricted cash balances. Availability under our corporate revolver remained fairly steady at just under $300 million, but I would expect some level of improvement over the next couple of months, as previously issued letters of credit in support of certain commercial contracts are returned. While overall liquidity has been improving, we have remained focused on streamlining our collateral program to minimize the amount of liquidity needed to support ongoing commercial activity. Over the past year, our outstanding collateral has been cut in half. And since August 2011, approximately $630 million in previously posted cash and letters of credit have been returned. That, in of itself, is significant. But on top of that, we've been able to dramatically decrease the amount of liquidity needed to be held in reserve to protect against commodity price volatility and the collateral calls that could potentially be made. Over the past 2 years, we have been able to reduce that required cushion by 80% by meaningfully reducing our exchange-based hedging activity, which typically requires upfront cash collateral and daily margining and, instead, using more efficient bilateral first lien arrangements, where there are no cash or LC requirements. By doing this, we've significantly reduced the collateral intensity of our hedging activities and provided more certainty around our liquidity requirements, while at the same time, maintaining our ability to manage the risk of the business through an active hedging program. While we have made significant progress to date, I expect to continue improving our liquidity program, by not only further reducing collateral requirements where possible, but also pursuing alternative sources of liquidity to further diversify our program and reduce dependence on balances for contingent collateral needs as we move forward. And finally, as I mentioned earlier, we are reaffirming our 2013 segment and consolidated guidance ranges, which are outlined on Slide 20. The Gas segment is currently trending to the top end of the segment range, as both spark spreads and resulting generation remain strong. Coal segment results also remained within the segment range, although I would note that recent unplanned outages have somewhat offset higher LMP prices, causing segment results to trend toward the bottom half of its range. On a consolidated basis with corporate level expense and other income factored in, we expect to achieve our targeted adjusted EBITDA results for 2013 and with lower-than-expected CapEx at both Coal and Gas segments to be at or near the top of the consolidated free cash flow range. With that, I'll turn the call back over to you, Bob.

Dynegy intends to host an Investor Day in early March of 2014 in New York City. We will provide more details about the event as it gets closer; however, highlighted on Slide 22 are several of the topics we plan to cover. With the expected closing of the AER transaction late in the fourth quarter, we intend to utilize Investor Day to provide 2014 guidance numbers for Dynegy and each of its segments, including IPH. We will also discuss the post-closing capital allocation opportunities planned for 2014, as well as launching the next generation of PRIDE that will target further synergies of the newly combined portfolios. Since the addition of the IPH fleet is new to our portfolio, the event will include a detailed review of the IPH asset base, as well as the IPH retail business. Members of the leadership team will also review the commercial and operational strategies planned and in place for 2014 in the medium to longer term. We look forward to seeing everyone in March. And Shirley, at this point, I'd like to open up the phone lines for questions.

[Operator Instructions] And our first question comes from Paul Zimbardo with UBS.

My first question was about the Moss Landing at 6 and 7. I appreciate it's sensitive, but is there any kind of insider data points you could give us to look into for pricing there?

Yes, Paul, I knew this would be a topic of great interest and we are, as you can expect, very constrained on what we can say about it by contract, but maybe a little bit more color. With the contracts in '14 and '15 in particular are summer-shaped. Each year, the amount contracted under the RA portion of the contract gets progressively higher. So we do have additional length in '14, less in '15 and far less in '16 for potential additional RA capacity sales. And when you think about the value of the -- of this agreement, really, the only thing I can say at this point is that we've outlined on prior calls kind of the range of the dispute around the contract value of the early termination. And in our view on the value of this new contract over these 3 years is that it fairly compensates us, and we viewed it was a reasonable outcome to go this route on the commercial settlement rather than continuing through a legal and arbitrating type of solution.

And a quick second question. In terms of M&A, what kind of further asset additions to the portfolio would be ideal for you? If you could just give some clarity there.

Well, I think -- M&A, I think our view really remains pretty consistent with what it's been for the past couple of years. I mean, we're a more efficient buyer of a portfolio assets rather than individual assets. You can see even like with Ameren, even though it's only 4,000 megawatts, they have synergies -- of $75-plus million of synergies, really drives the value of the combination. Our platform here at Dynegy is well developed, and we can certainly handle a larger portfolio than what we have today. So as we look forward down the road, it would be -- what's ideal for us is a portfolio of assets and a little bit, obviously, market diversification will be helpful being that we're -- we've got -- we'll have 70,000 -- 7,000 megawatts in MISO, so obviously, looking for markets outside of that. So I think the key thing is that, it's looking for a portfolio that kind of looks like us that has both coal and gas and would fit in nicely with what we have.

Our next question comes from Michael Lapides with Goldman Sachs.

Guys, stepping in for Neil Mehta today. First one, Bob, you just mentioned this a second ago when talking about Moss Landing that you all had previously disclosed what the dispute of [indiscernible] was regarding their early termination. My apologies, can you first just kind of restate what that was? I know you publicly put that out in the domain before. And second, thinking longer term, with the potential reversal of the Rockies Express Pipeline to bring gas, Marcellus gas into kind of the Chicago or Upper Illinois area, can you talk about how that would impact energy margins and spark spreads for your coal fleet?

Okay, Michael. So on your first question regarding Moss 6 and 7, in the early days when the contract was terminated and we started heading down the -- both litigation and arbitration, depending on which facility you're referring to, we -- the overall bookends were -- kind of the low was, from SCE's position, was about $5 million and we were talking order of magnitude of $90 million was kind of the original bookends of the original value associated with the dispute. So that's -- hopefully, that answers that question. And Hank will talk about the gas supply.

So the large amount of Marcellus gas that's trying to move east to west because of pipeline capacity constraints is -- would expect it to expand spark spreads. As the fuel price drops and power prices probably won't drop as quickly. The Marcellus gas is helpful to us at Independence and Ontelaunee and Sithe [ph] and Kendall. The -- we have good access to inexpensive gas at all 3 of those locations and expect that part of our fleet to remain competitive and to benefit. And as we move from east to west, there's less of a gas orientation and of a more coal orientation. So it has a precipitous drop and less impact moving west than it does in the eastern end -- the eastern part of our fleet.

Got it. And one follow-up. I know somebody earlier asked about M&A. Are there any type of assets you simply would not want to own, whether it's -- meaning, that you have an aversion for your company in terms of owning or operating, whether it's renewable assets of different type, whether it's nuclear or anything else other than the kind of the gas, coal and oil type that you run today?

Mike, on M&A, I mean, we try to keep our -- the ear to the ground and look at all the different things that are out there, so we're at least aware. I think the one thing that certainly has sensitivity to is any investment that requires a lot of incremental CapEx that would draw along the liquidity of the company is something that I would be -- have some level of aversion to. So a fleet that can, again, I think ideally looks like ours that has both combined cycle and coal generation is a good balance. But I don't want to get into a situation where there's just really significant long-term CapEx that you made that could impact the company's liquidity going forward.

Our next question comes from Keith Stanley with Deutsche Bank.

Is it possible that the Illinois Pollution Control Board could decide today at their meeting on the variance request? It looks like it's on the agenda. Or are you still thinking the 21st is most likely?

Well, first, I would say that we have -- obviously, we see the agenda and we see that it's on there towards the latter part of the day, although I'm not sure if it's there to actually go into a level of discussion or to just be there as a reminder that it's an open item that requires resolution. We have no contact or discussion with the IPCB. So we don't necessarily know what goes on behind the closed doors. They meet today and their next meeting is November 21. Our expectation is it's the 21st, but I guess there's some level of possibility that it could be today. But I do view that as unlikely.

Okay. And one other, if I can just clarify the comments on Moss 6 and 7. So I believe you said, and correct me if I'm wrong, that over 3 years you believe this fairly compensates for the contract cancellation and that the contract cancellation or the value of the contract that was canceled was in the range of $5 million to $90 million. Is that all correct?

Well, I'll take the latter part of that first, and when each company computed what they viewed the settlement under the termination was the kind of the bookends on that settlement was ranging between the $5 million and $90 million. And yes, our view on the 2 new contracts, which takes us through 2016 is that is, in light of where we were, it's -- our view is that it's a reasonable outcome for us.

Okay, but should we tie those 2 together? And I know it's a big range, and say that the contract payment through 2016 is in the range of $5 million to $90 million.

Keith, I don't want to get any more specific than that. I mean, it's kind of the $5 million to $90 million, kind of gives you an idea of what we've always talked about before, what the dispute was. And again, with the new contracts rather going litigation and arbitration, which I have an aversion to also to be in a dispute with customers, I view that this was the appropriate outcome for us, all things considered and that's really as far as I can go.

The next question comes from Amer Tiwana.

My first question is, are there any costs associated with Morro Bay going forward that we should consider? That's my first question. And then secondly, on just the CapEx for the company, maintenance versus environmental, can you give us some guidance around 2014?

Yes. I think as we look at Morro Bay going forward, I think the real cost at Morro Bay really is going to be kind of the ongoing operating expenses at the facility. I think those costs should go down materially, down into kind of low-single digits as kind of remaining costs include insurance, property taxes and so forth. So I think there should be minimal cost related to the facility going forward. As far as maintenance and environmental CapEx for 2014, I don't think we're in a position right now to comment on that. Obviously, we will provide that when we provide 2014 guidance. But this year, we had -- just for comparative purposes, we had estimated that our maintenance CapEx in total between coal, gas and corp would be about $110 million. I think we may come in slightly below that. But I think that's a reasonable type of level going forward for maintenance and then environmental really will be more regulation-specific and year-specific going forward.

Sure, just one more question. You talked about Casco Bay capacity factors increasing in 2014. Can you give us a sense of the magnitude by which you expect them to increase by?

Our expectation is that our capacity factors at Casco Bay will increase to about 25%.

[Operator Instructions] The next question comes from Paul Patterson with Glenrock Associates.

Just to circle back on the reserve margin outlook that you guys are seeing. I'm just wondering, how do we think about regulated utilities responding with respect to RMRs or increases in generation? Just in general, how do you guys look at that happening over time if, in fact, there's a perception that there's a reliability issue in MISO?

Well, I mean, around the retirement process, there'll be the Attachment Y or the filings for retirement and then MISO will have to do their analysis, whether it's needed for system reliability or not. So that's to be seen, and that process is underway. And so far, I guess, they've received -- MISO's received about 4,000 -- the equivalent of 4,000 megawatts of Attachment Ys that are in that process. So there could be some of that for a period of time. Regarding new build, there's just not much new build that's on deck there at this point in time. So in terms of responding to the local zone requirements, as well as backfilling for retirements and increased requirement, reserve margin, all of that, I mean, we're now outside the window where new builds could come in and impact that. So as Hank had highlighted in his discussion that we're becoming -- I would say this is the most bullish that I've been on for planning year '14, '15 capacity prices, which would get better in '15, 16, and then on energy prices, we're becoming certainly much more bullish on the '15, 16 timeframe as we see the changes happening in the marketplace within MISO. So it is getting tighter. And everything that we've seen to date, and even going back a year and looking forward, it's pretty much gone the way we thought it would and then maybe even more so. So we'll see what happens, but markets are getting tighter, and I think we're in a very good position.

Okay. Just in terms of -- in that forecast, you show confirmed capacity exports to PJM. I'm just wondering, there's quite a bit of discussion about improving market to market, MISO to PJM for the most part, the congestion with transmission projects, new transmission projects and what have you. And I just was wondering what you see in terms of the opportunity there to perhaps further increase imports. I know that there's a 3,000 megawatts stuff and what have you. But I'm just saying, in general, what do you see in terms of the potential for the seams issue, so to speak, to improve from a MISO perspective or from any perspective, I guess? Any thoughts on that?

So there's clearly some rumblings that were going in PJM to hold a -- to develop a higher standard for accepting imports into their system, in terms of reliability criteria. So there's a -- just as with demand response in several regions, the import-export views are coming under closer scrutiny. So we think the standards will be held higher. And -- but I think it's fair to say, without meaningful infrastructure development, the rate of growth in exports would slow down.

And I think the other part, Paul, around the seams issue is that MISO is certainly an advocate of portability and having more megawatts float freely across between the seams. PJM, on the other hand, is doing everything they can to not let that happen. So there seems to be this continual standoff between the 2 ISOs, where MISO wants to have more portability and PJM is not wanting to have any portability. So I think when we think about the exports that are going there, I mean, we certainly have within -- with the arm and fleet expectations that will be continuing to export into PJM how much more can actually get from MISO into PJM, I'm relatively pessimistic that much can move across beyond where it is today.

Okay, without, I guess, transmission, if I understand you correctly. Is that...

Right. That's right.

Okay. But depend -- just getting back to this '14, '15 sort of dip that you guys are looking at, a lot of that seems to be sort of weather-constrained or at least weather-influenced pretty substantially is from what I understand. Do you see the potential, though, I guess, if in fact, there's a perception that there's a -- I mean if you're talking about these really low reserve margins that you won't get a supply response. Maybe it won't show up in the '15, 16 year, but perhaps after that. Do you follow what I'm saying? I mean, what's the long range sort of outlook when -- do you follow me? I mean...

Well, Paul, no, I think you're right. A couple of comments to all of that. First of all, I think when we see these tightening reserve margins, it's -- I wouldn't say necessarily it's weather-driven. It's really enhancements that they've made in the calculation of reserve margins where non-firm imports on how they're calculate it cannot be used when they're doing the planning resource margin. And that's taking 4,500 megawatts out of the supply side, and the retirements is pretty much an agreed-upon number across the industry. And how much goes out in '15 and how much goes out in '16, there's maybe a little bit more of differing views on that, depending who gets 1-year extensions or the like. But it's pretty hardcoded on what's coming out. So that reserve margin gets tight. I don't think there's a lot of variables that can influence it where it doesn't happen. But I think your second point, I completely agree with you. It does and can trigger a supply side response, and -- but it's very, very important for us here at Dynegy is to make sure that we are aggressively out in the marketplace with any load-serving entities, whether it's municipalities, utilities or other load-serving entities just to continue to work with them on providing access to capacity access to supply, and we're out looking doing origination. We're in a competitive process right now for a very long-dated capacity contract. And so we're starting to see the market's starting to take notice of this. And one of the things that's really important to us, long-term strategic objectives within the company, is to be very customer-facing and bringing a supply solution to them to ward off any type of new build that's not needed in the market. So I mean your point is, I think, is relevant and it's something that we see and something that we're aggressively making sure that we manage the best we can.

Our next question comes from Mitchell Moss with Lord, Abbett.

Just a question on your retail strategy and any progress you've made in that area?

Mitchell, I'm going to let Sheree comment on that briefly.

Yes, so we have started working on the strategy for retail and we're looking forward to acquiring AEM. It's certainly a well-book-built organization and is quite focused on the customer, has a strong reputation. So we're making plans to leverage their position in the market and to expand the presence, not only in MISO, but further up into Northern Illinois as well. And we'll be looking further at other areas of PJM [indiscernible].

And Mitchell -- I mean, Sheree has been -- she joined the company in August and Sheree's background comes from Exelon, has worked in retail in the past. And she's been pretty much resident at the Ameren retail headquarters, which is in Collinsville, since August. So she's been working with the team there. So we view on day 1 that we'll be well positioned to continue the good work that Homefield Energy and the team at Ameren has done in building that retail business and continuing on with it and we view it really complements our existing fleet. Not only does it complement the generation assets of Ameren, but certainly power coal generation assets, as well as our combined cycle units in the side of Chicago and also in Pennsylvania.

Just to follow up on that, I know that when you had originally discussed having a retail strategy it was to address the negative bases -- basis, more negative than anticipated. And it sounds like this is a bit of a broader strategic objective, speaking about Northern Illinois PJM business. Could you just discuss that a little bit more about, I guess, this changing or evolving strategy?

Sure, that's a fair point. And I didn't mean to create any confusion there. The focus of the retail business that Ameren has -- Homefield has, I mean, virtually, all of their load that they serve today is in the Southern Illinois marketplace. So it is all in and around all of our assets. And so that's the vast majority of the effort is around building up the market share there and how that helps with supplying energy locally. And our plants can take advantage of the fact that they're very close to where the load requirement is. And that is the key principle of having this retail business. We happen to have generation assets just to the north where Ameren currently has developed some retail C&I-type business. And so the fact that we actually have the Kendall unit up there outside of Chicago, it's a natural extension to do more work up there because we have the generation backing that as well. So it's very much to complement the generation portfolio that we have. I didn't mean to -- if I gave the indication that we're suddenly trying to do a national retail program, that's not what we're doing.

Okay. And just looking out at the coal basis -- at the pricing basis, is the 2013 revised guidance level -- I mean, should I think of that as sort of a going-forward level of basis as well?

Yes. I mean, we obviously talked about this an awful lot internally as well. And looking at '14 versus '13, can't say there's a whole lot that's going necessarily to be different. So we would expect, and we'll come out obviously when we have Investor Day with more fine-tuned guidance. But I would -- I view it to be relatively the same in '14 as we experienced in '13, overall.

Our next question comes from Michael Lapides.

Bob, my apologies, one follow-up real quickly. When thinking about the retirement or the shutdown of Morro Bay, I want to make sure I understand what this means for the broader grid. Is Morro Bay physically located in a constrained portion of the grid, where something's going to have to go on that site or a site very close to it, or otherwise, you'd be in kind of -- the local utility would be in kind of grid violation? Or is that now less constrained or -- I'm trying to think about this relative to what happened a year or so ago with the Sutter plant where an original plan was made to retire the unit and then an alternative was found to keep it online.

Yes. I mean, I think the challenge for Morro Bay is the fact that it's not in a constrained area. It's Central California, coastal plant. There's not a lot of demand nearby, and it's not in northern. It's not in southern. So it's not a constrained area. Now we'll see when we go through the retirement process whether it's deemed needed for reliability or not. But our view is that it's not.

At this time, I'm showing no further question.

Great. Well, thank you, everyone, for joining us this morning.

Thank you. This does conclude today's conference. We thank you for your participation. At this time, you may disconnect your lines.