Dyne Therapeutics, Inc. (DYN) Q2 2012 Earnings Report, Transcript and Summary

Hello and welcome to the Dynegy Incorporated Second Quarter 2012 Results Teleconference. At the request of Dynegy, this conference is being recorded for instant replay purposes. [Operator Instructions] I'd now 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 second quarter 2012 results. As is our customary practice, before we begin this morning, I would like to remind you that all our call will include statements reflecting assumptions, expectations, projections, intentions or beliefs about future events and views of market dynamics. These and other statements not relating strictly to historical or current facts are intended as forward-looking statements. Actual results though may vary materially from those expressed or implied in any forward-looking statements. For a description of the factors that may cause such a variance, I would direct you to the forward-looking statements legend contained in today's news release and in our SEC filings, which are available free of charge through our website at dynegy.com. With that, I will now turn it over to our President and CEO, Bob Flexon.

Thank you, Laura. Good morning and thank you for joining us on today's 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. I'll begin with our operational and financial performance highlights of the Gas and Coal segments for the second quarter of 2012, as well as our year-to-date financial performance. I will also review what I hope to be the final stages of our restructuring activities as we draw closer to emerging from the Chapter 11 process. Finally, in response to frequent questions on how Dynegy's value at emergence should be viewed, I'll provide additional data that should aid investors in making their own proprietary view on the value. Kevin will follow with a review of our operating performance for the quarter and describe the commercial and market factors affecting the Coal and Gas portfolio including 2013 commodity price trend. Following that, we'll discuss the dynamics and influences impacting power closed across the grid and how that affects our commercial strategies and actions. Clint will provide our second quarter 2012 financial results and highlight both legacy and current activities impacting performance for the Coal, Gas and DNE segments. Also to be covered is the second quarter 2012's cash flows and liquidity. I'll close out the prepared remarks by emphasizing our go-forward priorities and with the remaining time, we'll open up for discussion and the Q&A session with the management team Slide 4 shows the second quarter marked another period of significantly increased generation. Due to the increased spark spreads at our combined cycle locations. Generation in the GasCo segment increased 80% period-over-period. Coal-based generation was down period-over-period by 20%, primarily due to the planned outages this past spring at and Wood River. While off-peak spark spreads are increasing generation at our combined cycle fleet, the off-peak power prices for our Coal fleet have decreased, which has to a lesser extent also contributed to lower generation for the Coal segments. Both segments have continued their strong operational performance by achieving overall end market availability in excess of 95% for the second quarter. The financial performance for the second quarter 2012 continue to be impacted by lower power pricing for the Coal segment and the legacy commercial positions within the Gas segment. The impact of the commercial positions will be addressed on the next slide and in more depth during Clint's financial review. Our second quarter adjusted EBITDA was $10 million for the Gas and Coal segment down $102 million period-over-period, with $65 million of the decrease attributable to legacy Gas put option liabilities and reduced option premiums versus last year. Lastly, our liquidity as of July 30 continues to be over $1 billion. Our year-to-date 2012 adjusted EBITDA and free cash flow results are shown on Slide 5, considerably lower pricing impacted results for the Coal segment and DNE driven by the 44% decline in Henry Hub natural gas prices that averaged $2.40 in the first half of 2012. Power prices declined over $10 a megawatt hour period-over-period for our MISO fleet and over $20 a megawatt hour low in Zone G. Although, improved spark spreads lead to increased capacity factors for the gas fleet, results for the Gas segment were significantly impacted by the legacy financial put options, which again, Clint will discuss in more depth. Adjusting the year-to-date EBITDA for the put options in the DNA segment, leaves the Gas and Coal segments with adjusted EBITDA for the year of $77 million. Similar to adjusted EBITDA, year-to-date free cash flow of negative $79 million had several items impacting the results for the first half of 2012. Excluding the items highlighted on this slide, it indicates the underlying free cash flow at negative $15 million, which is just short of break even in the $2.40 natural gas price environment. The restructuring update is provided on Slide 6, which highlights recent key events that have moved on as we closed towards emergence from Chapter 11. The deadline for the submittal of proofs of claim in the Dynegy Inc. Chapter 11 proceeding was August 1. A great majority of the claims that were received fall into the convenience or equity class under our plan of reorganization were duplicative. We are evaluating the other claims but did not receive any material unanticipated claims. Until August 24, we are in a period were creditors vote to approve or object to the proposed plan of reorganization. A hearing is scheduled with the Bankruptcy Court for September 5, and if Dynegy receives confirmation of the joint plan of reorganization, we anticipate emergence in the weeks following the court's confirmation. Last quarter, we provided an estimated capitalization and enterprise value at emergence, using quoted market prices for our unsecured debt and equity and similarly, we updated that analysis this quarter for market price changes and included the refreshed analysis in the appendix on Slide 39. For the enterprise value or EV from the analysis, pegs Dynegy's EV at $3.354 billion or $344 per kw, which excludes Dynegy Northeast, Oglesby and Stallings and is highlighted on the top of Page 7. To provide additional perspective on how to assess this EV estimates, Slide 7 separates the Gas and Coal segment to provide a clear view of each portfolio, which should assist our stakeholders in forming their own value assessment. For GasCo, the 2013 adjusted EBITDA used to prepare the disclosure statement consolidated financial projections was $308 million. Using an EV/EBITDA multiple of 9.1, which is representative of a combined cycle Gas portfolio, based on a recent analyst report, translates into an implied GasCo EV of $2.8 billion or $414 per kw. For CoalCo, the implied EV after subtracting the GasCo number from the overall EV translates to $185 per kw for CoalCo's fleet of environmentally compliant coal plants. CoalCo for more than a decade, has made the back end control investment to meet strict Consent Decree and other environmental requirements and is compliant with current federal legislation including the Mercury and Air Toxics Standards. Recent NERC estimates for coal plant environmental control retrofits range from $665 per kw to $1,375 per KW, obviously, well in excess of CoalCo's implied $185 per kw evaluation for the [indiscernible]. During our earnings calls, we routinely highlight the various market changes and other Dynegy initiatives that may impact future earnings and cash flows. While Kevin and Clint cover many of these areas in their section, Slides 8 and 9 provide some additional significant developments in a few key areas. The first item I'll cover on Slide 8 is our delivered Coal costs. Yesterday, August 2, we entered into a new long-term transport agreement for Coal delivery to replace the current contract that expires at the end of 2013. We also signed an amendment to our existing rail car lease agreement that will increase our rail car lease rates in 2012 and 2013 but ensure long-term availability of railcars for our Coal delivery. Also in connection with a cost of procuring PRB Coal, we updated our analysis of the estimated PRB Coal procurement cost versus the Disclosure Statement. The primary items impacting the coal cost were the delay and the Cross State Air Pollution Rule, as well as current supply and demand factors that influence PRB pricing. The net effect is that PRB acquisition costs are now expected to be lower than when the Disclosure Statement was prepared. Combining the impact of the new rail agreements and the updated coal commodity cost, results in over $300 million cumulative reduction in delivered Coal costs versus the Disclosure Statement for the balance of 2012 through 2015. Keep in mind, other factors have also changed since the Disclosure Statement was prepared that are both favorable and unfavorable. The most notable and transparent being the decline in natural gas prices. Secondly, when Dynegy emerges from the Chapter 11 process, we expect the vast majority of existing net operating losses to be utilized against the cancellation of debt income or CODI. We are continuing to work through the tax implications of the restructuring but a preliminary look indicates additional tax attributes will be generated and should more than offset the use of the existing NOLs and other tax attributes for CODI. Finally, as the company emerges from the restructuring, our improved credit profile should generate additional counterparty credit capacity, alleviating the current need for significant cash balances to provide liquidity support for our hedge positions. Once we have more clarity around the ongoing needs post restructuring, we'll work on optimizing our capital structure that should lead to reduced cash interest expense. On Slide 9 is our update per PRIDE, our multiyear endeavor to find ways to improve margins and reduce fixed costs and make our balance sheet more efficient. We remain on target to reach the goals that were established for fixed cash costs, gross margin increases and balance sheet improvements. For our fixed cash cost reduction efforts, we've adjusted our target slightly between OpEx and GA (sic) [G&A] for the 2012 target of $452 million and are now forecasting a $90 million G&A target for the year, down, from $96 million and up $362 million OpEx target, which is up from the $356 million, due primarily to higher outage costs and forecasts during the first half of 2012. Our current G&A run rate is now below $90 million. Our gross margin in 2012 is expected to improve an additional $13 million over 2011 and we are currently on track to meet that target through projects that will increase our in market availability at CoalCo and Gasco in addition to heat rate reduction projects. Lastly, we are on pace to meet an incremental $100 million in balance sheet improvements for 2012 through increased first lane usage and improving our base payable outstanding with vendors. I'd like to turn the call now over to Kevin for the operations and commercial review.

Thanks, Bob. Please, turn to Slide 11 for a review of our operational highlights. As Bob indicated earlier in the call, our total generation volumes were up 12% period-over-period, primarily due to our combined cycle units experiencing improved spark spreads. At Independence and Moss Landing on-peak sparks spread improved an average of $6 period-over-period, while sparks spread improved $10 at Kendall. This translated into an 80% increase in volumes for the gas segment period-over-period. Dynegy swing out of season in 2012 had more planned out that is scheduled for the Coal segment than the second quarter of 2011, which resulted in lower volumes for the quarter. Midwest off-peak prices for the second quarter 2012 averaged around $24, which was $4 lower than the previous period. This also contributed lower coal generation volumes for the quarter. Both segments performed well, with combined end market availability of over 95% during the quarter. The Coal segment's equivalent availability factor decreased due to the planned outages during the quarter. The Gas segments showed an improved EAF for the quarter as EAF for the second quarter of 2011, includes a planned outage at Moss Landing. Safety continues to be an area of top priority for all Dynegy employees, as well as the management team. While we are still short of our safety goals for the year, there are several positives occurring in the fleet. Baldwin, Havana, Hennepin, Casco Bay, Ontelaunee and Danskammer, Roseton have not had a site employee loss time or recordable incident in 2012. In addition, Hennepin, Casco Bay, Ontelaunee, Kendall, Morro Bay, and Danskammer Roseton have not experienced any contract or loss time or recordable incidence in 2012. We intend to build off all these areas of excellent results as we focus on improving our overall safety results and returning the fleet to top quartile in the industry. Please move to the next slide where I provide more explanation on the fleet performance. Similar to last quarter, the capacity factors for the gas fleet continues to show improvement period-over-period. A blanket statement about improved spark spreads would not provide insight into the changing operations that each unit is experiencing. As I indicated on the last slide, Moss Landing and Independence have seen the greatest improvement in on-peak spark spreads. Although, Moss Landing 1 and 2 had a significant plant outage in the spring of 2011, spark spreads were 0 during that quarter and units would not have been economic. Kendall saw some sparks spread improvement in the off-peak -- I'm sorry, in the on-peak. But off-peak spark spreads saw a greater improvement contributing to higher capacity factors. Ontelaunee experience, lower spark spreads on average for the second quarter 2011, however, as you may remember from my discussion last quarter that average continues to be distributed across the day, so there are more hours that can run economically. CasCo Bay's capacity factors have not improved due to the lower spark spreads as a result of Gas constraints in the area. We are monitoring a new gas supply that will start producing over the next few months to see if that will improve gas prices to these units. Looking at the Coal segment, capacity factors are lower primarily due to an increase in planned outages for the second quarter 2012. Without the impact of these outages, capacity factors will be slightly lower than the previous period primarily due to lower off-peak power prices we're seeing in that region. Please turn to Slide 13. Looking at our generation hedged position for our Gas and Coal portfolios, we're maintaining an open portfolio strategy in 2013 for the Coal segment to capitalize on what we anticipate would be improved prices compared to what is currently trading today. As the chart on the bottom left indicates, power prices are following Gas and are traded within a narrow band over the first half of the year. There has been a significant impact from coal to gas switching in addition to the record heating the nation is experiencing, which we believe will help to strengthen the Gas market. While we are keeping the Coal portfolio open in anticipation of starter prices, the other lower Gas prices environment has provided better opportunities to hedge our Gas portfolio in terms of stronger spark spreads. The chart on the bottom right indicates this upper trend in spark spread as gas is traded around $3.50 for 2013. Please turn to Slide 14. Before we move onto the financial review, I wanted to discuss some changes to the power flows being reviewed by our commercial team. Looking at the map on Slide 14, the green arrows indicate typical power flow patterns around the section of the U.S. where significant portion of our fleet is located. Generally, cheaper generation such as collared wind is located further west or south and travels towards the more densely populated low centers in the east. Due to transmission constraints that limit the flow of power, various conjunction points are always expected in certain areas as indicated in the map. However, with low natural gas prices driving retirements of uneconomic units, and the significant coal to gas switching this part of the nation is experiencing, we are noticing that the congestion areas have started fluctuated from the norms or new areas of congestions are being created. What this means for our Dynegy units is the changes in the basis differentials from our plants to where we hedge. It could mean higher prices for our units in some locations, while other locations could receive lower pricing. We expect that power flows on the grid will continue to adjust as we see increased retirements and our commercial team is closely monitoring these events to adjust our commercial strategy accordingly. I'd now like to turn the call over to Clint to review the financial results.

Thank you, Kevin. As you can see on Slide 16, the companies adjusted EBITDA was down significantly compared to last year. With the Coal and Gas segments together, totaling $10 million in adjusted EBITDA, down from $112 million last year. As we discussed on previous calls, we expect the company's 2012 financial results to be meaningfully impacted by legacy commercial activity and we began to see that in the second quarter. In particular, negative settlements related to legacy optimizations and year-over-year decline in options premium income accounted for nearly 2/3 of the quarter-over-quarter decline in adjusted EBITDA. Of the $102 million difference, in aggregate Coal and Gas segments of adjusted EBITDA, $65 million was related to these 2 items with $23 million due to the settlement of legacy option positions and $42 million due to lower option premium income. The remaining $37 million decline in adjusted EBITDA for the period, resulted primarily from weaker prices in MISO and lower Coal segment generation volumes primarily as a result of 2 significant outages during the quarter. Year-to-date, the Coal and Gas segments generated a combined $48 million in adjusted EBITDA compared to the $204 million in 2011. Much like the second quarter, results were significantly impacted by legacy option settlements and reduced option premium income as these 2 items accounted for $71 million or 45% of the year-over-year change. The remaining $85 million reduction in adjusted EBITDA year-to-date was driven primarily by lower generation and realized prices at the Coal segment. Dynegy Northeast results for the second quarter improved by $6 million compared to last year, as lower market prices and run times were offset by the absence of operating lease costs and lower G&A expenses. Year-to-date, adjusted EBITDA in DNE, fell by $4 million as lower power prices and a 61% decline in total generation, more than offset the benefit of lower lease and G&A costs. Total liquidity at July 30, 2012, stood at $1.02 billion including $712 million in unrestricted cash, $16 million in letter of credit capacity and $289 million of restricted cash in our segregated collateral posting account. As you can see, total liquidity has not changed materially as somewhat lower unrestricted cash balances were offset by a higher collateral posting account balance, which increased this cash collateralized position settled during the period and a letter of credit, which was previously posted in support of the Morro Bay toll and Moss Landing RA agreements was returned. Because that letter of credit was no longer outstanding as collateral to a third-party, we were required by our credit agreements to convert that LC capacity into cash and deposit it into their collateral account. Before getting into more detail about the company's quarter-to-date and year-to-date financial performance, one thing that I'd like to note is that when investors review Dynegy Inc.'s '10 Q for the second quarter, it will look like different than our previous filings. As you will recall, Dynegy Holdings along with the Gas segments and DNE would be consolidated for financial reporting purposes, from Dynegy Inc.'s financial performance as of November 7, 2011. And this deconsolidation was reflected in the company's 10-K for 2011 and the first quarter of 2012 10-Q. Under the settlement agreement, reached with creditors and approved by the Bankruptcy Court on June 5, Dynegy Inc. transferred its interest in the Coal segment to Dynegy Holdings. Causing Dynegy Inc. to deconsolidated the Coal segment from its financial statements as of that date. As a result, when investors review Dynegy Inc.'s 10-Q for the second quarter, they will note that the balance sheet no longer reflects any assets or liabilities related to the Coal segment. Additionally, the income statement and cash flow statement will only reflect Dynegy Inc.'s ownership of the Coal business through June 5. We expect this accounting treatment to continue until the company emerges from bankruptcy at which time, the surviving businesses will be reconsolidated for financial reporting purposes. Moving to Slide 17. Adjusted EBITDA for the Coal and Gas segments totaled $10 million during the second quarter down from $112 million in the second quarter last year. As you can see from the segment breakout, both businesses reported significantly weaker results but for different reasons. At the Coal segment, generation volumes fell by 1.2 million-megawatt hours or roughly 20% compared to the second quarter of 2011, primarily as a result of significant planned outages at Wood River and Havana. The lower generation volumes net of the fuel savings due to the lower coal burn, lead to a $15 million quarter-over-quarter reduction in gross margin and together, with an additional $3 million in outage related expenses, brought the total adjusted EBITDA impact to $18 million. Coal segment earnings were further impacted by $5.72 per megawatt hour decrease in realized power prices, leading to a $34 million reduction in gross margin as average INDY Hub day ahead on-peak prices dropped from $43.02 per megawatt hour during the second quarter of 2011 to the $33.99 per megawatt hour in 2012. Similarly, average INDY Hub Day ahead off-peak prices declined from $28.27 per megawatt hour during the second quarter of 2011 to $23.30 per megawatt hour during the same period in 2012. And finally, the company recognized over $15 million in option premium revenue during the second quarter of last year compared to $1 million in the current quarter leading to a $14 million reduction in adjusted EBITDA quarter-over-quarter. At the Gas segment, results were almost exclusively driven by the settlement of legacy financial positions and the significant reduction in option premium revenue compared to last year. During the second quarter of 2011, the Gas segment realized $30 million in option premiums, however, in 2012, the company was much less active on this front generating only $2 million in premium revenues. This $28 million swing, together with $23 million in legacy put option settlements accounted for $51 million reduction in quarterly results compared to 2011. Partially offsetting this was a $10 million -- was $10 million in amortization related to the site contract, which while treated as an expense in 2011, is now added back for adjusted EBITDA purposes given that it is a noncash item. And while spark spreads were generally higher in the second quarter of 2012 compared with the prior year, the company did not realize upside from them due to its significant hedged position which was primarily executed during 2011 when spark spreads were lower. At DNE, second quarter adjusted EBITDA improved by $6 million compared to the same period last year. As we've mentioned in the past, the company discontinued most hedging activity at DNE once the company went into bankruptcy. So the rose in enhanced camera unit were fully exposed to changes in market prices. With New York Zone G on-peak prices falling from an average of $56.09 per megawatt hour during the second quarter of 2011, to an average of $40.03 for the same period in 2012, the units were less economic than they were the previous year, leading to a 15% reduction in total generation. Further, the company recorded $9 million in positive hedge settlements during the second quarter of 2011 which was not repeated in 2012, which when coupled with the lower prices and run times, led to a total gross margin decline of $11 million quarter-over-quarter. Offsetting this was a $13 million benefit associated with the absence of operating lease expense and a $2 million improvement in G&A costs resulting in a quarter-over-quarter change. Given some of the unusual items impacting results this quarter and this year, I thought it might be helpful to provide not only a pro forma look for the second quarter adjusting for these items, but also laying out our expectations for how these same items will impact third and fourth quarter results going forward. As you can see on Slide 18, adjusting for the unusually high level of option premium income recorded during the second quarter of 2011, as well as the legacy put option settlement expense in 2012, a more comparable quarter-over-quarter comparison would reflect a $37 million decline in aggregate Coal and Gas segment adjusted EBITDA, from $67 million in 2011 to $30 million in 2012, instead of the $102 million reduction as reported. As we move into the second half of the year, we expect these same items to impact third and fourth quarter comparisons versus last year. On the bottom half of the Slide, we've outlined our expected quarterly variance as related to option premiums and legacy put option settlements. You'll notice that during the third and fourth quarters of 2011, net option premiums were actually an expense as the company entered into commercial positions and paid out premiums on a net basis, which should translate into a positive variance during the third and fourth quarters compared to the same period in 2011. For this analysis, we have assumed no new option premium or expense in the second half of the year. We also reflect here the forecasted legacy put option settlements over the next 2 quarters with a negative $20 million in the third quarter and negative $31 million in the fourth quarter. In total, we expect adjusted EBITDA in the third and fourth quarters of this year compared to the same period last year to be reduced by a total of $10 million and $23 million, respectively, as a result of these items. I would note however, that the put option settlements are 2012 cash items, so we do expect approximately $51 million in unrestricted cash to be used over the last half of the year to settle dispositions. However, we also expect that cash collateral currently posted in support of these positions to return to the company and be deposited into the unused collateral account. And once dispositions are settled in the fourth quarter, the entire legacy put option position will be behind us, with no go forward impact on a company in 2013 and beyond. Moving to Slide 19. Adjusted EBITDA for the Coal and Gas segments totaled $48 million for the first 6 months of 2012, down from $204 million for the same period in 2011. The $156 million reduction in aggregate results were driven by the same factors as those in the second quarter. A $6.53 per megawatt hour decline in average realized prices, driven by a $10.02 per megawatt hour reduction in average INDY Hub day ahead on-peak prices and a $6.11 per megawatt hour fall in average INDY Hub day ahead off-peak prices accounted for $82 million, or roughly 70% of the year-over-year change in the Coal segment's adjusted EBITDA. Additionally, generation volumes were down 14% primarily as a result of 2 large planned outages, leading to an additional $24 million decline in year-over-year adjusted EBITDA. This, together with $14 million in lower option premium revenues, accounted for most of the remaining 30% decline in segment results. Gas segment adjusted EBITDA declined by $41 million during the first 6 months of 2012, compared to the same period in 2011, primarily as a result of a $29 million reduction in option premium income and $28 million in legacy put option settlements. While spark spreads improved year-over-year, the Gas segments was unable to benefit as the company was significantly hedged at levels more in line with 2011 and experienced an additional $6 million negative basis move primarily at its Ontelaunee facility. Somewhat offsetting these year-over-year declines was a $19 million ad back for the noncash purchase price amortization of the side contracts which is treated as an expense in prior years. DNE adjusted EBITDA for the first 6 months of the year declined by $4 million compared to the same period in 2011. Total generation fell by 61% or almost 400,000-megawatt hours as market prices weakened and the units primarily, Danksammer, were not economic to run as often as last year. Lower generation, together with a $21.63 reduction in average on-peak New York Zone G pricing led to a $15 million decline in energy margin. Together with the absence of $18 million in hedged settlement, the company received during the first half of 2011, more than offset the $25 million reduction in operating expenses associated with cancellation of the facility lease, and a $4 million decline in G&A expenses. Dynegy's cash flow results are outlined on Slide 20. In as he can see, enterprise cash flow from operations for the first 6 months of the year was negative $189 million, while free cash flow totaled negative $79 million. It's important to note however, that the company's cash flow was significantly impacted by sizable collateral movements as well as a number of large nonrecurring expenses and investments specific to 2012. In order to better understand the company's underlying cash flow, it's important to look-through these items to the free cash flow generation of the business segments excluding these variables. As we've discussed in the past, our collateral program has a significant impact on reported cash from operations and the free cash flow, as cash collateral's postings to third parties impact cash room operations and the release of cash from excess letter of credit capacity impacts cash from investing. During the first 6 months of the year, between these 2 accounts, the company freed up $102 million in previously posted cash collateral and excess letter of credit capacity which offset the significant portion of the $181 million in net cash used in the business. Of this $181 million in net cash outflow, $146 million was related to nonrecurring expenses and investments specific to 2012, including $69 million in bankruptcy professional fees, $39 million in legacy commercial settlements and $38 million in Consent Decree CapEx. The remaining $35 million of negative cash flow reflects the financial results of Dynegy's 3 business segments during the first 6 months of the year. With DNE recording adjusted EBITDA for the first half of the year of negative $20 million, this means that the Coal and Gas segments taken together and excluding nonrecurring items, recorded free cash flow of negative $15 million during the first half of 2012, despite the challenging commodity price environment during the period, as well as other factors impacting results for the first half of the year. Moving to Slide 21. Total enterprise-wide liquidity stood at $1.02 billion on July 30, 2012, including $712 million in unrestricted cash, $289 million in restricted cash in our unused collateral account, and $16 million in letter of credit availability. Since our last reported liquidity position on May 4, total liquidity has remained virtually unchanged. However, there has been changes in the mix and location of that liquidity within the Dynegy family. In particular, I would note, that the unrestricted cash balance at Coal HoldCo is approximately $100 million less than on May 4. During the second quarter, Coal HoldCo upstreamed this amount to Dynegy Inc. in order to fund DI's $41 million undertaking payment to Dynegy Holdings in June and to pre-fund estimated bankruptcy expenses as outlined under the settlement agreement with creditors. As a result of receiving the undertaking payment and subsequently paying certain advisory expenses, Dynegy Holdings cash balance has increased by a total of $28 million compared to May 4. Dynegy Inc.'s cash balance is approximately $10 million higher than on May 4, as the company used a significant portion of the cash it received from Coal HoldCo, net of the undertaking payment to fund current and estimated restructuring expenses. I would also note an increase in the company’s total unused collateral account balances as total outstanding collateral with third parties has continued to fall. At July 30, total outstanding collateral was $424 million, and $81 million reduction since the end of 2011, primarily as a result of the settlement for cash collateralized commercial positions and the return in June of the previously posted letter of credit supporting the Morro Bay toll and Moss Landing RA agreements. With almost $1 billion in total liquidity and more modest collateral needs, the company remains well-positioned to meet all commercial, operational and bankruptcy emergence requirements. With that, I'll turn the call back to Bob.

Thanks Clint. Finally, on Slide 23 is an update of our 2012 strategic focus areas. While very good progress is being made on the majority of fronts, we're determined to improve our safety performance to better understand the changing dynamics in the markets in which we operate and translate all of these areas into achieving the financial targets we have set for ourselves. In preparation for our anticipated emergence by the end of the quarter, we'll continue to strengthen operations, execute well and solidify the foundation which can serve as the growth platform for the future. At this time, I'd like to open the lines for questions.

[Operator Instructions] We do have one question, sir. Umesh Mahajan with Bank of America.

So on Page 8 of the presentation, where you talked about the new contract for rail lease. So you talked about the $300 million and you also mentioned that the rail car lease rates are slightly up in 2012 and '13. So how does the -- is the $300 primarily coming from the commodity costs side and are those costs already locked in? Or that's the expectations we have at this point?

There is a mixed bag there and I would say that there's a reason that I combined all of those elements together. Under the new agreements we have, we have pretty tight nondisclosure requirements, so I bundled it all together. But I will say around the Coal commodity piece, as I mentioned in the comments, when we did the Disclosure Statement, we had a higher price in there for Coal and that was largely driven by anticipation of cash per coming in and how that affects the pricing under the Coal contracts. When I looked at where we are in terms of hedging our coal position, particularly on price, I think it was on Page 29 of the presentation where I think, we say we've got about 53% of our coal that's priced, another 32% that's subject to a price collar that we're in that pricing period now. Beyond 2013 though, the Coal is -- from a price standpoint, is open. So when I think about the number, certainly, 2012 is going to add -- have extra cost but I would expect '13, '14 and '15 to be higher than the Disclosure Statement. Certainly, '13 is being driven mostly by the Coal commodity and '14 and 15, it's a combination of both, rail and Coal.

[Operator Instructions]

Well, Pat, if there's no other questions at this time I'll ... [Technical Difficulty]

Yes, and we do have a couple of more questions, sir, that have come in. And our next question is coming from Grab Babar [ph] with Nomura.

I just want 2 quick clarifications mostly. With regards to the Gas segment, if we were to look on it on Page 19, without the impacts of option premium and legacy put options, the year-over-year comparisons would just be down $3 million from the spark spread hedges and the price impact --I just want to kind of verify that I'm reading it the right way?

That's correct. The only other adjustment would be the adjustment for the Sithe amortization which I think in previous has treated as an expense. But since it's noncash, beginning this year, we began to adjust that out. But you are correct. Year-over-year if you remove those 2 items, you would end up at that adjusted EBITDA.

Okay. And that's at the capacity factors that we're reported. But the other question I just wanted to ask is with regards to cash collaterals that comes back, is there a credit agreement requirement for that cash that comes back for the credit -- for the loan amounts to be paid down? Or did that just stay within densities?

[indiscernible] The cash collateral comes down. It does not have to be repaid. We have to keep a certain amount of cash collateral or cash behind it over a certain tract threshold. We have the option to put that cash back up to $350 million between GasCo and CoalCo but we don't have an obligation to do so.

That's right. Under our credit agreements, we've agreed to set amount of collateral outstanding, either with third parties or in the collateral account. So to the extent that our outstanding collateral with third parties is below that target level, we have to put money into that collateral account. Bud like Bob said, there's no obligation to turn that money back to the lenders. We have that option, but not the obligation.

Harlan Cherniak with Venor Capital.

A couple of quick questions. I think it's in the press release, can you clarify the total amount of restructuring fees [Indiscernible] in the G&A line item for the quarter? I think it was $51 million, right?

I believe it is -- I believe it was $69 million in cash, but in the G&A line, I think it's about $57 million to $58 million.

And you talked about the -- I think it was Wood River or Hennepin outages in the quarter that [indiscernible]

They were at Havana.

Sorry, that's coupled with what's transpired in the commodity price environment contribute to significant amount of volume declines, can you bifurcate the 2 and break it out between how much of it was attributable to the outage versus how much of it was attributable to the volume?

I think at the top of my head, Harlan, I think that the -- certainly, the greater number was around the outages. And I thought it's certainly is more than half. I'm not sure if as high as 3 quarters but somewhere between 50% and 75% deals with -- because of outages.

I think if you adjust it for the difference in outages, you're only off about 5% on capacity factor across the fleet, which I would attribute back to the market.

Okay, and with those -- I guess what I'm trying to get to is if you look what adjusted EBITDA would be if -- looking at the portfolio on an open EBITDA basis with the mark-to-market losses, the restructuring charges, the impact on G&A from the bankruptcy and some of the outages, which I know some of them occur in the second quarter and it's obviously a significant part of the business, but I'm trying to get to a more clean EBITDA number in terms of how to think about this going forward.

The way I think about it, Harlan, is we even the put up the slide for year-to-date on Page 38 that tried to strip the put options out and the option premium and the like. So you see an Page 38, you have year-to-date adjusted EBITDA that would be in the $72 million to $77 million range versus the reported, which is $48 million.

And did that -- does that exclude the actual G&A expense that we just talked about?

It does exclude things like restructuring expenses and kind of one-time items running-through the income statement. So what's reflected in the adjusted EBITDA numbers should be more of a recurring G&A type of number.

Okay. And on the NOLs, can you put a little bit more color behind the potential benefit from the tax attributes once the company emerges from bankruptcy? That was on Slide #8.

Yes. The existing NOLs, we would expect to be totally utilized as we emerge and even if they weren't, they're going to be severely limited because of a change in control for tax purposes that happened back in May. But as we go through, our tax planning and take a look there for the DI's, investment in DH, the stock investments as we emerge, we'll be able to get a worthless stock tax deduction and we're working-through the calculation on how much that is. But we expect it to exceed and possibly even significantly exceed the $1.5 billion of NOLs that we have coming into this year. So we're going through the final math round, and I think we feel confident that, that deduction is available, we're just going to the final calculations of the math on the outside basis calculations and the like that need to be done and we're probably about a month or so away from finalizing the math. But from order magnitude, we expect it to be more than -- more NOL than what we currently have and what we would utilize on emergence.

Got you. And then one other quick question, I'll just get back in the queue. On the rail transportation contract, that's pretty impressive and heroic outcome here. Can you put a little bit of color? I mean, obviously, in the front, 2012, 2013, it will be slightly higher than the Disclosure Statement and it will be a lot lower going forward, which is pretty impressive. Can you put some color on how we should think about delivered PRB dollars from MBTu, or a dollar per ton basis on the Coal and the rail side, if possible?

You mean as we go forward?

Yes. Ballpark.

Yes. I mean, I think the kind of way that, I mean, I can do it through the pictures in the slide on Page 34. In the appendix, we have the dispatch cost and kind of showed where we were today, which we're about $16.50 a day and then we have ton at the general PRB at market. We expect as we go through in pricing of our -- the Coal commodity and the new rail agreements and the like, that we believe will be underneath the market on that, when you wrap it all together. So you see the second bar down on that Page that shows a number in the 20s. We believe that we'll exceed that, where you see the favorable side, obviously.

Julien Dumoulin-Smith with UBS.

So first question, with regards to Casco Bay, I would be very curious, any kind of strategic updates, thoughts around kind of getting around assimilation [ph]?

Well I think there's a couple of things going on in Casco. First, I'll maybe take you back to the inception of that project when the Maritimes & Northeast Pipeline that feeds that was built. That pipeline was built to bring down the Sable Island production that Mogul had up there in the mid-'90s. That's Sable Island project has declined significantly over the years and Maritimes is largely dependent now on the Repsol LNG project up in Canada, so with the pricing the weight in North America, there's not a lot LNG deliveries coming in right now, so left the pipeline, kind of scarce on gas. There is a field of their call Deep Panouck [ph], that's scheduled to come online over the balance of this year, which we think will improve the situation in the near-term. But I think longer term, the real issue will be the explosion of some of the production through the shales up in the Northeast is I think a high likelihood that within the next 3 to 4 years, you may seen Maritimes actually switch directions and start flowing south to north rather than north to south.

All right, great. And then maybe secondly, kind of following up on the last question on delivery coal pricing. What would the year-on-year step up be by year, maybe if you can give us a sense for the staircase, if you will, for delivered PRB pricing? [indiscernible] Is there a back way door to get to it?

You're talking about just totally delivered costs by year?

Yes. Or year-on-year changes, whatever might be callable.

I mean, versus the Disclosure Statement, Julien, I'm just struggling a little bit to come up with the best way to answer it. I mean, as we look at the Disclosure Statement, when we look at that $300 million improvement, solely the vast majority of that is in '14 and '15 particularly since '12 is negative. But in terms of just getting a little more granular year-by-year, I struggle how to do that without crossing the line that I don't want to cross. I don't know if -- Kevin, if you can find other comment for Julien or...

No, and again, Bob highlighted the fact that we did amend the existing agreement which will have a slight impact to 2012. It's going to cost us a little bit more. But in aggregate, the pieces, it really starts to step up. So we actually do get benefits in '13 from it, but like Bob said, the real benefit comes in '14 and '15. But on an MPV basis, this is really significant agreement for us.

Yes, the '13 net benefit we'll see, we have higher cost associated with the lease car amendment, but that's more offset when we adjust for the PRB pricing, because Casper had a big influence on how our coal was being priced for '13. So that's -- it's a net positive for '13. Certainly, not a huge number. It's really is, once you take a look at the PRB and the rail agreement, when it fully starts in '14 and '15, relative to what we had assumed in the Disclosure Statement.

So maybe, outside of some earning [ph] the bulk of that $300 million is really reflective over 2 full calendar years in '14 '15. Is that kind of the fairway to characterize it?

That's a fair way to characterize it, but I think, that's again, because you're negative in '12 and maybe positive in '13, the map will take you right to your point.

Great. Maybe last question here on California. So lastly on California here, Morro Bay -- obviously, you can talk a little bit about the future of it. Can you discuss where you stand with regards to recontracting the asset?

Well let me just put some total clarity around that whole issue. When those agreements were terminated, we obviously, took exception to the actual termination. So there's actually a dispute resolution process underway now to resolve those processes. It looks like it's going to head into mediation here in the near-term. And we'll see what kind of work goes from that. The one important thing I would remind everybody is because the contract were terminated, there was payment for what we call the undisputed amounts. We clearly view that we owed significantly more dollars under that, but we've received at least the undisputed amount already. And then we're going to work through resolving the rest of the money. We feel like road, as far as recontracting of the asset, there's actually an open or full process now out in California with Southern California and others that we're actively trying to participate in and hoping that we will be able to get some value out of that as well. And then, once the dust settles on that, to the extent we can contract some of that up, we'll have to make some other assessment. If we don't get anything out of that process, then I think we're really going to have to probably have a discussion about do we take it to an RMR status or what is the long-term viability.

Right. And then, any concerns around or visibility on Moss Landing 6&7 and 1&2 just an ability to contact more in 1&2 and then 6&7? Is there a concern on having the same kind of event take place on both units as did with Morro Bay?

As far as a termination of the agreement on 6 and 7?

Yes. There's no comparable alloc for any counterparty there, correct?

No. And actually in the beginning -- I'll just remind you that the determination even down at Morro, we don't think there's a good determination anyway so...

Right.

And then going back to the Coal contract, I do want to emphasize that -- getting that contract done by Kevin and his team was just an outstanding result for the company and not being phased, we're trying to get it done in '13 when you've got the one expiring and a new one in place. We really came through, in what I believe is just an outstanding outcome for the company. Pat, we have time for one more question.

Our last question comes from Angie Storozynski with Macquarie.

Just looking back on the call contract. So maybe I misheard, but so is 2013 priced? So do I have a price of PRB under the contract?

So for 2013 for the coal commodity under our normal purchasing of coal, we've got 53% of that coal priced, another 32% of that coal under a price collar option that get set during a specific time period this year. We're in that time period. and then the remaining 15% we're open to the market or about 2 million tons of coal. So that dealt with the coal commodity that come. As far as the rail, that stays the same except for the cost of the lease cars.

Okay and then '14 and '15 for pricing of coal, is there -- I mean, it's a similar structure or is it simply undecided at this point?

'14 and '15 from a price standpoint we're completely open...

There's a collar component around about 6 million tons.

But it's not priced yet.

It is not priced yet.

Okay. So the $300 million benefit versus the original estimates that you're quoting, is this just simply price to market? Is that based on the market PRB prices that you're seeing?

Yes. and it's a combination of that and the new rail rate that we have locked in as compared to the rail rate in the Disclosure Statement. So both in the commodity forecasting. In the commodity, what we use...

I'm sorry. Because I'm simply struggling with seeing markets for PRB in '14 and '15. I mean, there hasn't been much of a transactions of any, so I'm just basically trying to figure out how you're estimating the $300 million benefit.

There are broker quotes for that period. I agree with you, there's not a lot of liquidity behind. There's not a lot of trades out there, but there are broker quotes for that period.

And it's against our Disclosure Statement.

Okay, yes, well, but we don't know what the original disclosure assumptions were. [indiscernible] We just don't know what price to see you.

That's right. But you got to remember, when we did that, as well, we had a gas price in 2015 of $5 and the gas price in 2015 of $5 impacts how coal is priced.

Well, I think at the time of the Disclosure Statement, you also have to remember, that I think there was the expectation that Casper was going to go live on January 1 of '12 and at that point, Casper credits has traded as high as $2,000 and that was having an impact on expectation for PRB. Clearly, with delay at Casper and kind of a collapse in the Casper credit, that shifted the thinking on PRB quite a bit.

But Angie, when you think about the $300 million, I would say that most of that over the course between 2012 and 2015, the majority of that is locked in.

So you're basically saying it's the rail really not the Coal?

I'm saying it's both because really I just talk about Coal is priced for '12 and Coal is priced for '13, the rail is priced for '12 and '13. So what's floating at this point is Coal in '14 and '15. But the vast majority of the savings, when you look at the whole picture, is locked in.

Okay. That's fair. Now, you are excluding the losses on the legacy put options and the option premium. Now, I mean, I'm fine with it but should I assume that going forward, you're not using options as a way to hedge? Because I mean, I will probably assume that if you do use options and they are beneficial, they will be included in your adjusted EBITDA going forward, right?

Well, I think the way to think about the legacy opt -- there were really a host of put options that were out there and now that we're trying to migrate more and more to a first lien structure, both of our counterparties don't do put a short put as right way risk, so -- and I think rightfully so. So I think the way -- we will be using options, I'm just not sure we're going to end up using short put options.

Angie, when we do use options, and have either premium income inflow or outflow, to me, that is part of the economics of the underlying hedge and that's why we change our methodology in how we treat that to actually realized that premium income or expense upon exploration of that hedge, which would also line up with the generation. So, I think we should have a better alignment of the economics of that hedge with the generation going forward.

Yes, for the legacy put option, the premium was recognized in '10 and '11 and the liability was left for this year, so we would always match that. But back to Kevin's point, we will not do any commercial transactions where we're going short put. We're not going to do wrong way risks hedging. We use options to define its right way risk.

Okay. Now, I understand how the expanding spark spreads have been helping or have helped your Gas assets. Now, about the Coal assets, it seems like the power prices in the Midwest are really not reacting to the strength in natural gas prices and there are many different opinions why that is. One of the reasons could be the weakness and low growth in the Midwest especially, in Illinois. Casper, the delay in Casper could be -- we have another reason. Now, we are in an environment of some pull back in natural gas prices. Why should we get excited about power prices and the dark spreads for your portfolio, given the backdrop that we're going against?

Yes. And I would say to that, Angie, I mean, the thing, as we look forward and even in the month of July, we've seen some higher peak loads. In what we've seen, I guess, might have set some new peak records in terms of daily peaks. So we have seen some spikes there. We also have some high print pricing as well. We've seen prints with high as $1,000. So we're seeing some of it but I mean, generally speaking you're right what really needs to happens might so over the next several years is -- it's long capacity. You've got reserve margins, that are in the 20s and to the extent, environmental rules stay in place, there's going to be capacity that comes out of that market. So while we're going to see some spikes here and there, what's really going to have to help us is retirements in the market either through lack of economics currently or lack of economics plus the thread of environmental investments that need to be made. So it's probably going to take a little bit of couple of years to sort itself out. But we're seeing some encouraging signs during the month of July on where peaks are and some better pricing.

The only thing I add to that is clearly, over the first half of the year, there was no weather in MISO. We had an incredibly warm winter and not much heat until July. So about the first and second quarter, I think our -- you got to kind of weather normalized us a little bit. Because of that, you actually saw gas prices kind of get as low as $2.20-or-so in the spring. There's been a significant recovery against that. Gas prices still are not anywhere as robust as we think they will be over time. But you've got this kind of overhang of some like $2.20 gas than the first half of the year.

Okay. And my last question, I promise, okay. So you mentioned how much money has been spent retrofitting your coal plants and you showed where is the implied value of your Coal portfolio from where the other debt is trading, which assumes the debt is reflecting the priority [ph] of the company but now, I mean, we haven't really seen any length between the replacement value of assets and where the sparks are trading, right? I mean, if you look at any of your peers, any power producers, they are trading well below their replacement value even though, they also have quality assets. So I mean, why should we even think about how much money has been dedicated to upgrading those assets if the market doesn't seem to recognize it at all?

Angie, what I was just trying to do on 7 because we get the question a lot, probably, from your reports. But to provide some lease on separation in 2013, on what's the gas and what's the coal, to help people think about it and the implied value of $185 a kw, you're right. I really leave that to people to form their own judgments or value at, however, they think most appropriate. And you're right, from replacement cost of a coal plant, with Prairie state invest like over $3000 a kw for a coal plant. I mean, so you don't know -- I mean, you're right, that it doesn't necessarily mean you're going to trade to these levels. But what I was only trying to do on that slide is provide additional details, split out GasCo from CoalCo to get more information to the market to help with the value assessment.

All right Pat, that will conclude today's call. I want to thank everybody for calling in and participating. Thank you.

Thank you. Again, thank you for your participation on today's conference call. You may disconnect at this time.