Dyne Therapeutics, Inc. (DYN) Q3 2012 Earnings Report, Transcript and Summary

Hello, and welcome to the Dynegy Inc. Third Quarter 2012 Results Teleconference. At the request of Dynegy, this conference is being recorded for instant replay services. [Operator Instructions] Now I'd like to turn the conference over to Ms. Laura Hrehor, Senior 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 2012 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 for Dynegy's earnings call. Here with me this morning are several members of Dynegy's management team including Kevin Howell, our Chief Operating Officer; Clint Freeland, our Chief Financial Officer; and our General Counsel, Catherine Callaway. For this morning's call, our agenda is highlighted on Slide 3, and since this is our first post emergence and restructuring earnings call, I won't be following our traditional agenda this call, as I would like first to review the company's longer-term positioning within the IPP sector, why invest in restructured Dynegy and the value drivers in the near to medium term. I'll follow that with our traditional third quarter operational and financial performance highlights for the Coal and Gas segments. Kevin will then follow with a review of our operating performance for the quarter and provide updates on our commercial hedge positions, 2013 commodity price trends and additional commentary on modeling Dynegy's portfolio. Clinton will provide the third quarter 2012 financial results highlighting the key factors impacting the performance for the Coal/Gas and DNE segments. Clinton will also cover the third quarter's 2012 cash flows, liquidity and today's announcement concerning the early repayment of $325 million of GasCo's and CoalCo's term loan debt. I'll close out our prepared remarks with final thoughts on investment valuation considerations for the emerged and restructured Dynegy and why investing in Dynegy today offers an excellent risk/reward profile. With the remaining time, we'll open up the discussion for Q&A with the management team. Starting off on Slide 4, post-emergence, Dynegy's well-positioned for success as restructuring went far beyond the balance sheet. While the bankruptcy process has resulted in Dynegy having the least leverage and best credit profile in the IPP sector, as we enter 2013 we not only benefit from the strengthened balance sheet, but also from a far more streamlined company. Fixed cash costs in 2013 are expected to be approximately $105 million below 2010 levels. Capital expenditures in 2013 are expected to be $54 million and $155 million below 2012 and 2011 levels, respectively, with this month's completion of Consent Decree environmental spending for our coal fleet. The debt repayment announced today will lower annualized cash interest cost by $30 million with further savings possible through potential refinancing in 2013 and legacy option positions that will impact 2012 full year earnings and cash flow by approximately $80 million, all settle out in 2012. In addition to these significant improvements Dynegy's diverse portfolio provides downside protection as the Gas and Coal portfolios provide a natural hedge in changing natural gas environment. As investors begin to familiarize themselves with Dynegy in the asset portfolio, highlighted on Slide 5 are investment considerations, most of which will be covered on this morning's call. The most compelling investment point is our current valuation. If we assume Dynegy's current enterprise market value of approximately $2.5 billion is entirely attributable to GasCo and no value is assigned to CoalCo, it implies a value of $368 per kW for GasCo. Most, I think, would agree that considering the quality of our GasCo portfolio, the markets in which these assets operate, as well as the recent values combined cycle assets have transacted in the marketplace, $368 per kW for GasCo appears to be a conservative valuation. And remember, that assumes no value is assigned to our nearly 3,000 megawatts of our environmentally-compliant coal generation assets that stands to be a significant beneficiary of tightening reserve margins and increasing power prices. Furthermore, our de-levered balance sheet provides us with capital allocation options for pursuing alternative risk-adjusted investments in order to maximize the value of the company. Slide 6 further illustrates the strength of Dynegy's generation portfolio. Dynegy's coal fleet, just this month, completed its environmental retrofit needed to comply with the Illinois Consent Decree, which also enables the fleet to meet the requirements under the Federal EPA Mercury and Air Toxics Standards or MATS. At this point in time, competitor coal generation fleets are either well-advanced in their installation of back-end controls or are likely planning for shutdown prior to the 2015 MATS requirements becoming effective. As shutdowns occur, capacity markets will tighten, and our coal fleet should be a beneficiary of this tightening market. Continued low natural gas prices serve only to accelerate the pace of competitor plant shutdown as evidenced by last week's announcements of nuclear capacity in MISO being retired in 2013. As gas prices rise, Dynegy's coal portfolio is well-positioned to realize significant upside earnings and cash flow from the resulting increase in dark spreads. Our combined cycle fleet continues to set generation records in today's low-gas environment. As long as natural gas prices remain at current levels, we expect these historical-high generation levels will continue and GasCo will provide a stable source to free cash flow for the company. Longer term, we expect both the Coal and Gas portfolio to benefit from higher capacity prices due to plant retirements, which I'll cover next. Slide 7 has additional discussion concerning the outlook for MISO plant retirements and how this may impact capacity prices in the region and, in particular, for our coal portfolio. Currently, our MISO retirement estimates range from a low of 6 gigawatts that had been announced to date to potentially as high as 17 gigawatts. In addition to the 6 gigawatts already announced, there are 7.5 gigawatts considered to be at high-risk, or high probability of retirement, as these facilities are operating without complianced plans, and will likely run until uneconomic to do so, or the MATS compliance date in 2015, whichever occurs first. The additional 4 gigawatts identified on the slide are those facilities that have plans for compliance. However, these plans have not been acted upon, as they lack economic justification to do so due to the low power price environment. For both the 4 gigawatts and the 7.5 gigawatts of capacity, it appears to be more of question as to when the facilities will be retired rather than if they will be retired. Whether it turns out to be the 2015 compliance deadline or lack of economic justification to complete required investments for back-end controls, reserve margins in MISO and PJM seem to be headed to the mid-teens over the course of the next several years, benefiting not only the Dynegy coal fleet, but our combined cycle assets in PJM as well. Forward PJM RTO capacity prices, which are combined cycle units in Kendall County, Illinois receives, reflect this tightening market as the PJM market construct has a forward-looking capacity mechanism unlike the MISO capacity construct. MISO capacity prices, which are Illinois-based coal fleet receives, should converge towards the forward PJM prices, offering considerable upside for our coal portfolio. Slide 8 updates our PRIDE initiative, including targets for 2013. This time last year, we provided guidance that fixed cash costs for 2012 would be $452 million including DNE. Removing DNE's impact, the target was $393 million. Today, our forecast for 2012 is $383 million, $10 million better than planned. For 2013, we're targeting $367 million in fixed cash costs, which is $105 million or 22% below the 2010 baseline. The incremental reductions in 2013 will come from a variety of sources, such as procurement initiatives, more efficient chemical usage at our facilities, lower labor costs and lower office rent. Gross margin improvements in 2012 are on target to contribute an incremental $13 million versus 2011 and for 2013, we've identified an additional $20 million over 2012 through more effective bidding structures and practices at our Kendall, Ontelaunee and Casco Bay facilities. Our balance sheet liquidity contribution target set last year for 2012 was $476 million versus 2010. Our current forecast for 2012 is $512 million, and for 2013 we're targeting an additional $83 million through areas such as additional first lien usage for natural gas purchases, inventory optimization and working capital management. The $325 million in debt repayment Clint will cover has been made possible through the successful achievement of the PRIDE initiatives. Turning to the third quarter highlights on Slide 9 and beginning with safety first, to date we achieved our best quarterly safety performance for 2012. While we have much more we can and need to accomplish in achieving an injury-free work environment, we certainly welcome the quarter's improved results. Generation volumes continued their upward trend, increasing over 14% versus the same quarter last year. This increase was led by the 39% increase in GasCo accomplished versus the same period last year. CoalCo generation levels were slightly lower versus the third quarter last year, as lower pricing resulted in lower off-peak generation. Both segments had excellent operating quarters, with GasCo IMA of over 99% and CoalCo IMA of approximately 93%. The financial performance for the third quarter and year-to-date 2012 continued to be impacted by lower power pricing for the Coal segment, while increased margins for GasCo were offset by legacy option positions settled during the quarter and lower capacity in tolling revenues due to the premature termination of the California contracts. Clint will cover these and additional items in more depth during the financial review. Lastly, our liquidity as of November 2, 2012, was approximately $803 million, which declined from the second quarter, primarily due to the $200 million payment to creditors at emergence from Chapter 11. I will now turn the call over to Kevin for our operations and commercial review.

Thanks, Bob. Please turn to Slide 11 for a review of our operational highlights. As Bob mentioned earlier, our total generation volumes increased 14% period-over-period due to improved spark spreads for a majority of our combined cycle fleet. Our Gas segment volumes increased almost 39% period-over-period, primarily due to higher on- and off-peak spark spreads at Kendall, Independence and Moss Landing. The Coal segment experienced only 4% lower volumes period-over-period due to lower off-peak pricing. I will provide more detail about the impacts of pricing on the capacity factors of the entire fleet in a few slides. The Coal segment performed well, with strong end-market availability of 93% during the quarter. The Coal segment's equivalent availability factor increased slightly due to fewer planned outages taken during the quarter. I am pleased to report the Gas segment had outstanding end-market availability of over 99% during the third quarter. Considering these units have been operating at greater levels than they have historically, this performance is quite an achievement. Equivalent availability factor decreased slightly period-over-period primarily due to forced outages at our Moss Landing and Kendall facilities. Throughout the year, safety has been a top priority for Dynegy employees and the management team. The hard work to improve our safety performance is starting to show results. However, we still have more work ahead as we target top decile performance in 2013. Please move to the next slide, where I'll provide more explanation on the fleet capacity factor performances for the quarter. As the graph on this slide indicates, our gas fleet has continued to see improved capacity factors period-over-period. As in prior quarters, this improvement is due to a combination of higher on- and off-peak sparks spreads in most of the regions. Kendall and the PJM region has seen the biggest improvement in off-peak sparks spreads. In third quarter 2011, the region typically saw negative off-peak sparks spreads; however, during third quarter 2012, on average Kendall saw positive sparks spreads that allowed this plant to operate more frequently overnight. Moss Landing and Independence experienced the most improvement in their on-peak sparks spreads, which translated into stronger run times for these units. Casco Bay continues to have its performance limited due to lower spark spreads as a result of gas constraints in the area. We are continuing to look for ways to improve the gas supply of this facility. Looking at the Coal segment, capacity factors are only slightly lower, primarily due to lower off-peak pricing in third quarter 2012. I'd like to point out that capacity factors in the 70s is not typical for our baseload coal units, especially during the summer. However, remember that in September 2011 and 2012, Baldwin units were brought offline for 2-month major maintenance outages. While it is not standard practice to start maintenance outages during the third quarter, most of these outages included work to tie in the back-end controls for our Consent Decrees to meet the 2012 deadline. Please turn to Slide 13. Our hedge generation positions on our Gas and Coal portfolios reflect the recent improvement in 2013 gas and power prices since last quarter. Our general market view is shaped by the recent recovery of natural gas prices, although we do not believe the rise in natural gas has yet to be fully reflected in forward power prices. While we are still looking for an increase in the forward power markets, we also have to ask ourselves, "What if we're wrong?" This has led us to a strategy of protecting the downside on our coal fleet while leaving the coal portfolio open to upside participation, should prices rise as we predict. To implement the strategy, we have been using the recent uptick in prices to establish floor prices for 2013 through purchasing put options. To partially offset the required premium outlay of the puts, above-market call options have been sold, which not only provide incoming premium, but also allow us to participate in any price improvement up to the strike levels on the call options. If prices do rise to the level of the strikes, the unhedged portion of our generation will benefit as well. The chart at the bottom left shows the trend of INDY Hub and Henry Hub pricing. As I noted, we are encouraged by the upper trend of natural gas prices over the summer and the less bearish view on natural gas storage. Again, we do not believe this has fully shown up in forward power prices, which drives the hedging strategy I just outlined. The spark spreads chart at the bottom right is showing continued improvement in spark spreads in the East. We continue to monitor these trends as we review our targets to increase 2013 hedges on the gas fleet. Before I turn the call over to Clint, I would like to touch on 2 issues that we have seen interest in recently. The first is locational basis, and it's covered on Slide 14. Locational basis has 2 components that we monitor. The first is transmission congestion, which can cause the plant to trade at a discount to major trading hubs in a systemic fashion. The second is correlation risk, where the value of our hedge location can move up or down without a corresponding move at our plant location. As noted on the bottom of the slide, for every $1 change in basis, the coal fleet is impacted by approximately $22 million. On the first issue of congestion, we are working to identify projects on the MISO system that could lessen congestion and improve longer-term pricing at the plants. We are also looking at other potential solutions for optimizing the value of our coal fleet. On the second issue of correlation risk, we have become more active at using Financial Transmission Rights, or FTRs, to protect our hedges at INDY Hub. We are also using tools such as the nodal exchange and forward sales at the plant busbar to eliminate correlation risk. Please turn to Slide 15. Over the past few months, we received quite a few questions on how to think about modeling combined cycle units. I thought it would be worthwhile to spend a few minutes on this call to briefly explain how you should think about the dynamics between capacity factors and the combined cycle fleet. Multiplying an annual average capacity factor by an annual average spark spread is an easy way to model these units, but this method won't accurately reflect the gross margin on these units. For example, if the unit is operating at an annual capacity factor of 55%, it is possible the unit is operating greater than 55% during the summer months and less than 55% during the shoulder months. Additionally, an average annual spark spread mutes the high pricing in the summer months and the lower spreads during the shoulder months. When modeling any of the intermediate generation to improve gross margin analysis, you should increase the granularity by applying quarterly pricing to average quarterly capacity factors. Taking the analysis one step further, combined cycle units have quick startup and shutdown capabilities that allow them to avoid running during uneconomic hours. On-peak prices reflect an average price for a 16-hour period during the day. However, that 16-hour period may include uneconomic hours at the beginning end or middle of the day. Using the graph on the right as an for example, if an average on-peak price was applied to a unit that was only operating during a 12-hour period, the model would yield a lower gross margin because the model included 4 hours that the unit would have generated a loss if it were operating. Combined cycle units have the capability to target their operations during hours when it is economic to run. While I do not want our plant managers upset with me for insinuating these units can turn off and on like a light switch, these units do have the capability to come offline several times during the day if it makes sense economically. I'd like to now turn the call over to Clint for a review of our financial results.

Thank you, Kevin. Slide 17 outlines the company's financial summary. And as you can see, third quarter adjusted EBITDA for the Coal and Gas segments, together, totaled $50 million, down from $102 million last year. As in the first 2 quarters of this year, lower realized prices at the Coal segment and the settlement of legacy commercial positions at the Gas segment negatively impacted results. However, in the third quarter, there was further downward pressure on Gas segment earnings as a result of the contract terminations at Morro Bay and Moss Landing. These 3 factors alone reduced gross margin by $89 million during the quarter compared to last year. However, this was somewhat offset by higher Gas segment energy margin, lower G&A and operating expenses and a reversal in option premiums from a net expense in 2011 to net revenues in 2012. Year-to-date, the Coal and Gas segments generated a combined $98 million in adjusted EBITDA compared to $310 million in 2011. This $212 million reduction was driven by 4 factors: lower realized prices at the Coal segment, lower option premium revenues, the settlement of legacy put option positions and the termination of tolling and RA contracts with SCE. Together, these items reduced gross margin by $227 million. And while there were other variances throughout the year, they generally offset one another in total. Total available liquidity at November 2, 2012, stood at $803 million, including $429 million in unrestricted cash, $13 million in Letter of Credit capacity and $361 million of restricted cash in our segregated collateral posting accounts. As you can see, total liquidity is down by $219 million since the end of September, and that's primarily due to the company paying $200 million in cash to creditors as part of its emergence from bankruptcy, in accordance with its planned reorganization. Since bankruptcy emergence, we have continued to evaluate the company's liquidity needs, and we continue to believe, as we've discussed in the past, that a total of $700 million to $800 million in total liquidity is needed in order to run the business and provide a reasonable cushion against unforeseen events. Our available liquidity today is a little over $800 million. However, this is after already funding approximately $450 million in collateral needs and working capital. As we have expanded our first lien program to support our longer-term hedging activities, we've grown increasingly comfortable that have excess liquidity in the system and can afford to return a significant portion of the restricted cash in the Coal and Gas collateral accounts to our lenders. Under our existing credit agreements, these restricted cash balances may only be used for 2 purposes: either to post as collateral in support of commercial activities or use to repay our term loan lenders. These balances cannot be used for such things as working capital, CapEx, interest expense or other capital allocation initiatives. Given the significant reduction in our collateral requirements over the past year, we do not believe that we need to retain this cash for collateral support. And as a result, we have notified our agent bank that we intend to return a total of $325 million to our lenders, $250 million at GasCo and $75 million at CoalCo. This represents the maximum amount permitted to be repaid at par under the GasCo term loan, and while we can repay up to $100 million of the CoalCo term loan at par, our current collateral account cash balance is only $75.5 million. Given this, we're repaying as much debt as we can without incurring prepayment penalties. And once completed, Dynegy's annual cash interest expense will be reduced by $30 million per year, and its liquidity program will be more appropriately sized to the needs of the company. Moving to Slide 18, adjusted EBITDA for the Coal and Gas segments totaled $50 million during the third quarter, down from $102 million during the same period last year. As you can see from the segment breakout, the quarter-over-quarter decline was primarily due to weakness in the Coal segment. During the period, realized power prices fell by $9.74 per megawatt hour, leading to a $43 million reduction in gross margin as average INDY Hub day-ahead on-peak prices dropped from $46.24 per megawatt hour during the third quarter of 2011 to $39.93 per megawatt hour in 2012. Similarly, average INDY Hub day-ahead off-peak prices declined from $29.58 per megawatt hour during the third quarter of 2011 to $24.34 per megawatt hour during the same period in 2012. In addition to the decline in market prices, the on-peak basis differential between INDY Hub and our plants increased by an average of $3.20 per megawatt hour, putting further downside pressure on realized prices. At the Gas segment, results for the quarter were negatively impacted by contract terminations and the settlement of legacy option positions. The termination of our tolling agreement at Morro Bay and resource adequacy agreement at Moss Landing in May of 2012 resulted in a decrease in revenues during the quarter of $26 million and, together with lower PJM capacity revenues, led to a $32 million decline in gross margin. Also, as we've discussed on previous calls, the company's 2012 financial results have been meaningfully impacted by legacy commercial activities, and we continued to see that in the third quarter. In particular, negative settlements related to legacy option positions accounted for $20 million of the quarter-over-quarter decline in adjusted EBITDA. Partially offsetting these items was a $9 million -- was $9 million in higher net energy margin, $10 million in lower premium expense, $10 million in lower fees, $6 million in lower operating expenses and $10 million in amortization related to the contracts at Independence, which, while treated as an expense in 2011, is now added back for adjusted EBITDA purposes, given that it's a noncash item. While not reflected on the slide, DNE generated adjusted EBITDA of negative $2 million during the period, down $1 million compared to last year. During the third quarter of 2011, DNE benefited from favorable hedge positions executed in previous periods, realizing $14 million in settlement revenue, which was not repeated in 2012 as the company discontinued most hedging activity at DNE once the company entered bankruptcy at the end of 2011. Offsetting this reduction in revenue was a $13 million benefit associated with the absence of operating lease expense as the lease on the facilities was terminated as part of the bankruptcy proceedings. Moving to Slide 19, adjusted EBITDA for the Coal and Gas segments totaled $98 million for the first 9 months of 2012, down from $310 million for the same period in 2011. The $212 million reduction in year-to-date results was primarily driven by the same factors that impacted the third quarter. Coal segment adjusted EBITDA declined by $161 million as a $7.48 per megawatt hour decline in average realized prices, driven by an $8.78 per megawatt hour reduction in average INDY Hub day-ahead on-peak prices and a $5.82 per megawatt hour fall in average INDY Hub day-ahead off-peak prices, resulted in a $123 million year-over-year change in adjusted EBITDA. Additionally, generation volumes were down 11% 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 $25 million decline in year-over-year adjusted EBITDA. This, together with a $9 million -- with $9 million in lower option premium revenues, accounted for most of the remaining change in segment results. Gas segment adjusted EBITDA declined by $51 million during the first 9 months of 2012 compared to the same period in 2011, primarily as a result of $49 million in legacy put option settlements, $38 million in lower capacity and tolling revenues and a $19 million reduction option premium income. Partially offsetting these items was an improvement in energy margin; however, negative hedge settlements and basis changes limited the uplift associated with higher run times and spark spreads. Before hedges and basis, the value of our gas generation rose by $40 million as a result of higher spark spreads and a 76% increase in generation volumes. However, the Gas segment was unable to fully capture this as the company was significantly hedged at price levels more in line with 2011 and experienced an additional $14 million in negative basis changes, resulting in a net $17 million improvement in net energy margin. Operating expenses were $15 million lower during the first 9 months of 2012 compared to last year as costs associated with L-0 blade outages at our Casco Bay and Moss Landing facilities in 2011 were not repeated this year. And finally, the noncash amortization expense associated with the contracts at Independence is now excluded from adjusted EBITDA, leading to a $29 million increase in year-over-year adjusted EBITDA. DNE's adjusted EBITDA for the first 9 months of the year declined by $4 million from negative $18 million in 2011 to negative $22 million in 2012 due to a reduction in hedging revenue and lower market prices. An $18.65 reduction in average on-peak New York Zone G pricing led to a $17 million decline in energy margin. This, together with a $32 million reduction in hedge settlements more than offset the $38 million reduction in operating lease expense associated with the cancellation of the facility lease and a $6 million decline in G&A expenses. Dynegy's cash flow results are outlined on Slide 20. And as you can see, enterprise cash flow from operations for the first 9 months of the year was negative $143 million, while free cash flow totaled negative $94 million. As noted in prior quarters, the company's 2012 cash flow has been significantly impacted by sizable movements in cash collateral, as well as a number of large nonrecurring expenses and investments, such as bankruptcy advisor costs, Consent Decree CapEx and the settlement of legacy put option positions. As you can see on the right-hand side of the slide, cash used in the business during the first 9 months of the year, excluding the $104 million net inflow of collateral, was $198 million. The nonrecurring expenses and investments I just mentioned, however, alone totaled $200 million, meaning that absent these nonrecurring items, year-to-date free cash flow was positive $2 million. With DNE recording negative adjusted EBITDA of $22 million, this means that the Coal and Gas segments taken together, and excluding nonrecurring items, recorded free cash flow of positive $24 million during the first 9 months of the year, despite an average NYMEX natural gas price of $2.53 per MMBtu during the period. Turning to the company's liquidity. It's important to note that when CoalCo and GasCo closed their term loans on August 5, 2011, almost half of the proceeds, or $828 million, were used to post collateral to various counterparties. As shown on Slide 20, we have worked very hard over the past year to reduce the collateral intensity of the business, and as of last Friday, have been able to recover $493 million of the collateral originally posted. As cash and letters of credit were returned, some of the proceeds were converted into unrestricted cash and used for general corporate purposes. But a majority, approximately, $361 million, was deposited into restricted unused collateral accounts in accordance with CoalCo and GasCo's credit agreements. As I mentioned earlier, there are only 2 permitted uses for this restricted cash: posting collateral to third parties or repaying the term loans. With the success we've had in signing up new first lien counterparties, we don't believe we need this cash for collateral support. So we have notified our agent bank that we intend to exercise our right to return this excess liquidity to our lenders. After doing so, we believe that we will still retain more than sufficient liquidity to run the business. As shown on the bottom right side of the slide, a significant portion of our liquidity needs have already been satisfied. And with approximately $478 million in remaining available liquidity, we should be able to comfortably cover any incremental need that arises. This step not only generates significant ongoing cash savings to the company and further enhances Dynegy's already streamlined cost structure, but it demonstrates our commitment to balance sheet efficiency and disciplined capital management. With that, I'll turn the call back over to Bob.

Thanks, Clint. Turning to Slide 23, we recognize success is built upon a foundation of executing well, operating safely and efficiently, hitting our targets and thoughtful capital allocation decisions. While the current market environment presents challenges, our combined cycle fleet is performing particularly well as expected in this environment, while our compliant coal fleet will be the primary beneficiary of tightening markets and rising power prices. As these changes occur, either one or both will likely have a dramatic impact on the company's value, and our job is to ensure the fleet is well-managed and positioned to take advantage of changing market conditions, as well as to realize the full intrinsic value of the fleet today, which is why we remain committed to our PRIDE initiative. Finally, on Slide 24, as I covered earlier, if we allocate today's enterprise value entirely to GasCo, that results in a relatively conservative $368 per kW for GasCo, while CoalCo can be considered an embedded option at no cost to investors, providing significant upside value given the quality of the fleet and market positioning. Again, our focus is to execute well, make prudent capital allocation decisions, and capture the full value for each of these portfolios. At this time, I'd like to open the lines for questions.

[Operator Instructions] Our first question now is from Brandon Blossman, Tudor, Pickering, Holt & Co.

Let's see. How about the -- looks like some nice hedging going on in the quarter on the coal fleet. Can you give us any indication of what -- I assume that they weren't costless collars. What kind of cost associated with those floors?

Well, again, they were not costless because we put the floors in typically at more of a at-the-money-type position, and we were selling out-of-the-money calls to partially offset it, but we had enough liquidity to cover the rest. I don't know if we've actually disclosed the premium outlay, have we?

No, we haven't. But like Kevin said, I think there is a net cost associated with that. But I would say that it's been relatively modest and kind of the single million dollar type of net cost.

Okay, great, that's very helpful. And then just any more color that you can give around the -- Kevin or Clint, around the basis change particularly at INDY Hub year-over-year?

Well, I'd say that year-over-year, the total basis change, as far as a period-over-period adjustment, is not that significant. What we are seeing is that just the periods that it shows up and the volatility around it are what is really -- we're trying to drill in on now and trying to come up with some better solutions to manage that.

Yes. And as Kevin said, I think what we saw, is that year-to-date over the 9 months, I don't think it's been significantly different than what we saw in 2011. I think we did see an uptick, particularly on-peak basis, during the third quarter. But when averaged against on-peak -- excuse me, off-peak basis, it was kind of, say, in the mid-$1 to $2 range around the clock for the quarter.

And finally, I would say that on Slide 14, when you look at the history of basis, it's relatively consistent. And when I think about our priorities for 2013, we've allocated more resources to Kevin and his team to understand the congestion points and what are the alternatives that we can do to try to minimize that basis in the absolute amount, as well as dealing with the risk management objective of those times of high volatility that Kevin was describing. So that clearly is -- when we think about various PRIDE initiatives in 2013, understanding transmission, transmission constraints and how to optimize the coal fleet, particularly for Baldwin, is a top priority for us going forward.

And definitely it's interesting to see how that plays out, and obviously a lot of upside leverage on that play.

Our next request is from Jon Cohen, ISI Group.

I guess, I just had a couple of questions on the MISO power market dynamics. So looking at your Slide 7, I guess most people take it for granted that retirements will necessarily lead to higher heat rates and higher power prices. But I would imagine, most of the retirements are coming in the eastern part of MISO where you have a lot of bituminous coal plants that are unscrubbed. If that's the case, and you're already seeing congestion from Central Illinois into Indiana, wouldn't that just be exacerbated by retirements if they were in the eastern portion of MISO?

I mean, as far as the retirements, I mean we certainly do see it more in the eastern segments. Regarding congestion, Kevin, any thoughts of that?

Well, yes. I think it is something we'll have to keep an eye on. The theory that you're laying out there has some merit to it, and we'll have to look at that. But it's not only in the eastern, I think, we're going to see the retirements. I think as you go further north into MISO as well, you're going to see a lot of retirements.

Okay. And then I guess the other question is, if the retirements are from regulated entities, are you aware of any plans to replace those retirements with new build? Or do we have to wait and see what's retired before they announce plans for new build versus. . .

Yes, I don't think there's any. We don't see anything on the radar in terms of the new build coming in. And when we think about retirements and you talk about energy prices a moment ago with congestion, and again, we're going to do what we can to manage congestion and transmission. One of the main points that I wanted to drive through with that slide as well is the capacity construct in MISO as compared to PJM, and the fact that you don't have the forward capacity market, which leads to your second point that there aren't any signals for new build in these markets. And when you think about the capacity prices that our Kendall facility receives in Illinois just to the north, if we apply that same capacity price that Kendall gets in 2015, '16 timeframe, the impact on the CoalCo fleet is well over $100 million a year in terms of EBITDA versus what we realized today in capacity payments. So when I think about retirements, we certainly do expect there'll be impact on energy revenues and prices that are favorable. But the one thing that we're also trying to get out there and make public is that there should be a dramatic impact on the capacity revenues that the coal fleet receives compared to what it receives today.

But does that assume -- I guess does that assume that regulated entities in the eastern portions of MISO will opt to contract with your assets versus build their own under regulated construct? And the second question, I guess, is if they have to meet a load obligation with capacity, are they able to use contracted plants and parts of MISO that don't necessarily have a transmission path to the load pocket?

Well, on the first question around the new build and whether they build their own or contract with us, remember MATS comes in 2015. And if they're going to go -- if the utilities are going to go for rate review or to get new build approved, permanent, built, operational, you're not talking about 2015. You -- just the construction time period is 36 to 40 months. So in terms of timing, it just doesn't fit with MATS. So you're going to have these tightening of reserve margins that come pretty quickly. And while yesterday I indicated here that we thought it's unlikely that MATS gets repealed, I feel even more strongly about that today, given what happened last night with the election. So that capacity market is going to dramatically tighten in 2015.

Our next request, Ken Miller, Cantor Fitzgerald.

I was wondering if you can give us some insight into the bidding at Danskammer/Roseton and also the extent of the damage. And the third part is what happens to any insurance proceeds and how they would run to the waterfall of distribution value?

Yes. Regarding the bids, the bid deadline was November 5, it was just the other day. And we received a handful of bids. We're going through evaluating them now. Not all the bids were prepared the same way. So we're still going through and understanding all that. And the public process around that is November 15. Regarding the damage, I'll let Kevin give you an update on the damage, and then we'll talk about the insurance after that.

The primary damage we saw at the facility really was from rising water. The staff up there had tried to sandbag the facility ahead of the storm, but just the amount of storm surge they received is greater than anything they've seen probably in the last 35 years there. So we did have an issue at Danskammer where there was water in the basement. I think it was up to 6, 7 feet of water in the basement area, which primarily affects the equipment down in the basement. You've got various pumps, switch gears, stuff like that down there. The turbines themselves really are not impacted. But we're in a situation now of assessing all the damage of which motors we need to pull apart. That's brackish water that came in there, so you basically have to break all that equipment down and clean it up. So that's really the extent of the damage. It was mainly in the basement, on the pumps and switch gear. We've also got a little bit of damage at the dock that we're assessing as well.

Regarding the insurance and the amount of the financial impact of this, early estimates from our facility are in the order of magnitude of the $3 million range. But that's still a very rough estimate being developed. The insurance adjuster, as well as our team, were out at site earlier this week going through that assessment and detailing it. Regarding the coverage, the first million dollars is a deductible on the policy. And then for every million dollars after that, I think we have to meet a 10% co-pay, if you will, requirement. So that would all be funded through DNE. DNE has the cash to make that level of investment. But again, it's too early to conclude what happens next since we're still trying to assess the full extent of the damage.

I would also add that Roseton facility sits up on a little bit higher elevation and was not impacted. It's fully available to the market.

Our next request now from Julien Dumoulin-Smith, UBS.

First question, more of a strategic one. Now having a couple of months under your belt or what have you, what are you thinking in terms of taking the company from a strategic perspective? I suppose scale is always important in this business. Are you more of a buyer here? And perhaps could you talk about the thought process potentially protracted here over what is desirable, when it is, et cetera?

Julien, I'll just talk a little more broadly about capital allocation. We had our first formal meeting with the Board of Directors last week. And we went through these topics. And we've got another meeting with the Board in December where we're going to bring in even more detailed suggestions or alternatives that we think we ought to be looking at. But at this point in time and talking through the various alternatives with the Board, when we think about capital allocation, right now all alternatives are open and on the table and being discussed. And our first capital allocation decision, which the Board fully supported and endorsed, was the repayment of the term debt, the $325 million. In terms of the next type of decisions around capital allocation, we're going to look at everything around adding to the portfolio, we'll look at additional debt restructuring or repayment and we'll also look at share repurchases. So all of it will be considered by the Board. I think we've got ideas in each of those areas that we'll review with the Board. And the bottom line is going to be, we're going to select what we believe is the best risk-adjusted return for the shareholders. So right now, it's all on the table, more work being done and to be reviewed with the Board later in the fourth quarter.

Great. And a complementary question there, you talked about paying down debt. First, why not the full $100 million at CoalCo? And secondly, perhaps, if you could talk more broadly, pulling down the collateral, establishing a new revolver, what is the timeline there just in terms of sort of refreshing your liquidity situation?

Yes, Julien. I think for the first question as far as kind of why we're not repaying the full $100 million. Really the reason for that is that we only have $75 million to $76 million sitting in the collateral account at CoalCo today. And we -- the cash that's in that account is the only cash that we can use to pay down the term loan. We can't use unrestricted cash to pay that down. We can't use the restricted cash that's still remaining over at GasCo to pay down the term loan debt. So we're basically limited to what we have in the CoalCo restricted account, and that's the $75 million today. I think to the extent that we're able to pull some more collateral back in at CoalCo and bring that balance back up, I think we would seriously look at paying down some more of the CoalCo term loan should that occur. So more to come on that. As far as timing of revisiting our liquidity program, to me I think that needs to be done in conjunction with a potential refinancing and maybe a larger type of exercise. To me, that -- given some of the prepayment penalties that we would incur in refinancing early, I think that's probably more likely a 2013 event. And frankly, given kind of where the markets are, where the prepayment penalties are, we would want to wait until we have high confidence that the right transaction can be done, and that it could can be done economically. So I don't know that something will be done in the near term, but it certainly is something that we're continuing to monitor and we'll execute at the right time.

What's the right excess cash balance to think about, just to be blunt?

Well, I think -- I tend to think about it in terms of liquidity and whether that's in cash, whether it's in letter of credit capacity, revolver capacity or so forth. I think kind of where we are, I think, is a fairly good place. We have a little bit more liquidity maybe than we need. What I referenced in the slides here was we'd like to have a total, or we think we need, about $700 million to $800 million in total liquidity. We've deployed about $450 million already. So that would imply -- you'd probably want another at least $350 million in liquidity. We have a little bit more than that today. But again, I think, we want to have a margin of error here. So I'm fairly comfortable with where we are right now.

And sorry, just a real quick last question. We've talked a lot about MISO retirements. Just to follow up on that thesis here, when you look at your own portfolio, how do you think about the timing here? Obviously, we've seen, for example, the NI hubs units haven't come out in 2015, at least per the capacity auction necessarily. What's going to drive or trigger these events ultimately, as you see it? I mean, perhaps as you think about your own portfolio here, I mean, is there a triggering event where it's just we're going to take units the out because they're just not worth the pain?

Well, I think it's 2 things. If the smaller plants, like -- we retired Vermillion. So to the extent you've got plants that are subscale that aren't scrubbed, I mean, even in this gas environment, they're absorbing some level of pain, and there's a point in time that as gas prices start dropping down again, that pain could be sufficient to take them out of the market, just like Dominion did with the nuclear unit just with the announcement last week. So I think the low gas prices will continue to inflict some pain that can cause some of that. Other than that, I think it's the triggering date that there's a compliance deadline. And again, if you're not in the process of installing those controls now, you're not going to make 2015. You're not going to do anything for 2015. So it's either the gas prices, low gas prices, that's going to cause retirements or the MATS deadline.

Our next request now is from Brian Chin, Citigroup.

Most of my questions have been asked and answered, but there's still a wide variety of EBITDA estimates out there. When are you guys thinking of giving 2013 guidance? And to what extent would you consider giving out maybe longer-term gross margin guidance on some of the other IPPs?

Right now our target would be when we do the Analyst Day, which will be in July. We'll give the -- I'm sorry, I was hoping it was July. The January Analyst Day meeting, we'll give out the guidance. And to the extent we go -- we need think to think about, how do we split out that guidance between the portfolios, or do we just give one number? And then at some point in time, we'll need to think about do we go beyond 2013. And all of those decisions and discussions we haven't drawn any conclusions yet. So it's too early for me to say, Brian, whether we would provide something beyond 2013 for gross margin or not. But it's something we'll evaluate and consider as we plan for the Analyst Day in a couple of months.

Great, great. And then just one follow-up question that's unrelated. On slide 18, you've got, in that lower-left side, the coal segment, and you've got outages and volumes $3 million impact year-over-year. Should we assume that, that $3 million isn't the right number to read for the Baldwin planned outage because 2011, you also had a similar outage? And if so, can we get a sense of how big, of that outage, did that have an affect on EBITDA had that outage not occurred in September?

Well, I think the $3 million, some of that, I think, is likely as of the Baldwin outage. But again, because we had a significant outage last year, I think it's probably a small portion of that, if any. I think most of that's probably going to be some of your off-peak volume that's been coming down because of off-peak prices and ramping down the facility in off-peak hours.

So if I can just rephrase my question, what was the impact of the outage for September 2012 in total, with regards to EBITDA, as opposed to a year-over-year number?

Yes, again, the year-over-year will be relatively consistent because of the 2 outages are similar. Yes, I think in total, the -- I would say on an adjusted EBITDA basis, the impact this year -- and I don't know exactly how much would fit before September 30 versus land in October. But for the total outage you've got about an impact of about $5 million between gross margin and OpEx for this outage. That's not in comparison to last year. That just this year's impact of that outage.

Our last request now is from Will Frohnhoefer of BTIG.

I guess most of my questions have already been asked and answered. I guess the one thing I would have left is, what are the prospects? I mean, given obviously where gas prices are, it's kind of a challenge. What were the prospects for new capacity agreements out West on the gas side?

For new capacity agreements for the California fleet?

Correct.

Well, right now, when I think about Morro Bay, we're in the mediation agreements with the SCE that had provided the tolling arrangement that we had in the past. We're going through those discussions now, and we're in the very middle of that. So at this point in time it's hard to say whether or not we'll have a tolling agreement there as part of the settlement or not. So I can't really comment regarding Morro Bay. As far as Moss Landing 6 and 7, the tolling arrangements there are that they end 2014. So our thinking about that is that the capabilities, particularly of Moss 6 and 7, giving the renewable requirements in California and the ramping capability of Moss 6 and 7, that will be a highly desirable plant to have capacity, some type of capacity arrangements. So I'd say we're pretty optimistic for the plant in the north, and Morro Bay, time will tell. We'll see how the settlement discussions go on that. Thank you. And operator, that concludes our call. Thank you, everyone, for participating.

As the conference has now concluded, again thank you for your participation. All lines may please disconnect.