Dyne Therapeutics, Inc. (DYN) Q2 2013 Earnings Report, Transcript and Summary

Hello, and welcome to the Dynegy Inc. Second Quarter 2013 Financial Results Teleconference. [Operator Instructions] I'd now like to turn the conference over to Ms. Laura Hrehor, Managing Director, Investor Relations. Ma'am, you may begin.

Good morning, everyone, and welcome to Dynegy's investor conference call and webcast covering the company's second quarter 2013 results. As is our customary practice, before we begin this morning, I would like to remind you that our call will include statements reflecting assumptions, expectations, projections, intentions or beliefs about future events and views of market dynamics. These and other statements not relating strictly to historical or current facts are intended as forward-looking statements. Actual results, though, may vary materially from those expressed or implied in any forward-looking statement. For a description of the factors that may cause such a variance, I would direct you to the forward-looking statements legend contained in today's news release and in our SEC filings, which are available free of charge through our website at dynegy.com. With that, I will now turn it over to our President and CEO, Bob Flexon.

Good morning, and thank you for joining us today. With me this morning are several members of Dynegy's management team, including Clint Freeland, our Chief Financial Officer; Hank Jones, our Chief Commercial Officer; and Catherine Callaway, our General Counsel. Our agenda for today's call is located on Slide 3. I'll provide an overview of the second quarter results, including changes to our 2013 guidance, our progress towards closing the Ameren Energy Resources acquisition and follow it with an update on operational results for the quarter. Hank will provide the update on our commercial activities, followed by a discussion on the state of the MISO market in light of the recent report from MISO's independent market monitor. Hank will conclude his remarks with a review of how changes in natural gas and heat rate sensitivities impact Dynegy's portfolio. Clint will review the second quarter financial performance and discuss the drivers behind the changes to our 2013 guidance. I will close the discussion, and with the remaining time, we will open the discussion for a Q&A session. An overview of the second quarter results is shown on Slide 4. During the spring of significant planned outages, the safety-oriented efforts of our employees, supported by our safety programs and company-wide engagement, resulted in significantly improved year-to-date safety performance. For the first 6 months of the year, we had 6 recordable injuries, down from 11 recordable injuries versus the same period last year. The Gas segment incurred 1 employee recordable injury, while the Coal segment had 5 employee recordable injuries. Generation from our gas fleet declined 28%, primarily due to outages and lower spark spreads. Coal-based generation was down slightly, primarily due to increased planned outages during the second quarter. Adjusted EBITDA for the Coal segment was down $29 million compared to last year due to several factors, including the impact on realized pricing of widening basis between INDY Hub and local busbar prices, planned outages and higher coal transportation costs associated with the rail contract modification entered into during 2012. The basis or price correlation change with INDY Hub was driven by congestion due to transmission maintenance outages, certain planned outages near the Indiana border and the impact of generation from the Prairie State generation facility. Hank will review these items in further detail and the associated commercial issues and actions. Offsetting the Coal segment decline was a $26 million period-over-period improvement at the Gas segment. This improvement was primarily due to improved hedge pricing and the absence of legacy option positions that negatively impacted 2012 results. Finally, we are revising 2013 guidance for adjusted EBITDA downward and free cash flow upward. Adjusted EBITDA is being revised downward primarily as a result of revising the full year outlook for basis between INDY Hub and the locational marginal prices, or LMP, of our coal fleet. Our full year estimate for basis between INDY Hub and our LMPs is being revised from the original guidance estimate of $4.36 per megawatt hour to $7.11 per megawatt hour. This difference of $2.75 per megawatt hour applied to the 22 million megawatt hours of coal-based generation has an impact of approximately $60 million. As a result of this and other factors that Clint will cover, adjusted EBITDA guidance for the Coal segment is reduced by $70 million to a revised outlook of negative $10 million to a positive $15 million. Partially offsetting this is an increase in the Gas segment's adjusted EBITDA guidance due to the strong first quarter at Independence and summer resource adequacy sales for Morro Bay and Moss Landing. The net result of these changes for 2013 adjusted EBITDA guidance for the enterprise is $200 million to $225 million, down from $250 million to $275 million, as previously reported. 2013 free cash flow guidance is being revised upward to $190 million to $215 million, a $50 million improvement due to the financing activities completed during the second quarter at interest rates lower than projected and with more restricted cash release than previously forecasted. Slide 5 provides a status update for the closing and integration planning of Ameren Energy Resources, or AER. On July 26, 2013, we received communication from the FERC on our April 16, 2013, filing requesting additional information. FERC requested copies of AER sales contracts with 2 municipal electric agencies and additional transmission analysis on imports from first-tier areas. As requested by FERC, we reran a simultaneous transmission import limit study, including the information requested, and updated our market power studies to incorporate this data. After including this information, we have reconfirmed that the market power conclusions presented in our original FERC application remain unchanged. We'll provide the additional information to FERC within the 14-day time period, as requested by the commission. In connection with the Illinois Pollution Control Board, or IPCB, our request to transfer Ameren's variance that allows AER to delay full compliance with the state's multi-pollution standard was denied in June due to procedural matters. In the ruling, the IPCB stated that Dynegy subsidiary making the request to Illinois Power Holdings, or IPH, to make its own variance filing, which IPH did as co-petitioner with Ameren on July 22. The IPCB has 120 days from the filing date to rule on the request, while the Illinois EPA is required to file their recommendation regarding our request within 45 days of our filing. The Illinois EPA has indicated they expect to make their final recommendation of the variance on or before September 5. The IPH filing is consistent with Ameren's current variance. And since the economic environment and circumstances haven't changed, we remain confident that IPH will receive the requested variance. During the second quarter, we advanced our integration planning across all fronts. The 3 primary areas for synergies are in procurement, including delivered coal costs, allocation of the overhead associated with AER's parent company and operating expenses within AER. Based on our detailed work during the quarter, the expected synergies estimate has been increased from $60 million to $75 million. The steps needed to secure the vast majority of these synergies are expected to be completed by the end of the first quarter of 2014, assuming the transaction closes during the fourth quarter of 2013, which remains our estimated closing timeframe. Slide 7 highlights our operational performance for the second quarter. As indicated earlier, our safety performance has improved significantly during 2013. These results are encouraging, as our entire team and organization maintains continuous focus and emphasis on safety behaviors, practices and procedures to achieve our target of 0 injuries each and every day. Production volumes for the quarter declined approximately 17%. The Coal segment was down slightly due to more planned outages this spring compared to last year. Gas segment volumes were 28% lower primarily as a result of the planned Ontelaunee outage and decreased spark spreads. The increase in planned outages in both segments adversely impacted equivalent availability factors, or AAF. However, end market availability for both segments was above 90% for the quarter. Turning to Slide 8. The period-over-period view of our combined cycle fleet capacity factors provides the impact from planned outages and lower spark spreads. Capacity factors declined for Kendall, independence and Casco Bay due to the lower pricing, as the Gas segment spark spreads were adversely affected by affected by higher gas prices. Off-peak spark spreads were impacted most, making it uneconomic for the plants to run in the off-peak hours. The planned outage in Ontelaunee also reduced the capacity factor period-versus-period. Capacity factors for the Coal segment were slightly lower period-over-period, despite higher power pricing. During the quarter, the segment experienced more planned outages at Baldwin, Independence, Havana, as several of our major outages last year occurred during late third quarter and early fourth quarter to complete the consent decree work. As outlined on Slide 9, we continue improving the company through the PRIDE initiatives and remain on track to exceed targets established for the year. We are expecting to exceed our gross margin improvement target by $10 million due to our team's continued efforts to increase sourcing for Independence gas supply from the Marcellus region, as opposed to the historical Canadian supply source. The target for balance sheet efficiency is also expected to be exceeded by almost $80 million, due to collateral reduction for amendments to our LTSA agreements that occurred during the quarter and increased first lien usage. The target of $22 million for fixed cash cost has been lowered to $10 million, primarily due to increased costs associated with certain employee-related costs and legal expenses. I'll now turn the call over to Hank for a review of the commercial activity.

Thank you, Bob. We have quite a few things to discuss in this so section, so we provided an overview of the discussion on Slide 11. First, I will provide a regular update on our hedging activity for our power generation and fuel supply. Next, I'll discuss why and how we adjusted our hedging strategy around the Coal portfolio due to the basis issues we've experienced this year. We will also -- I'll also provide an update on our transmission upgrade studies and request to gain access to PJM for our coal fleet. After discussion of basis, we'd like to provide additional insight into the MISO supply-demand balance based on the perspective of the MISO independent market monitor, as well as the impact of the exports of MISO capacity into PJM into 2016. Lastly, I will walk through the adjusted EBITDA sensitivities for the Coal segment to provide additional insight on how to utilize the sensitivity variables we've historically provided. Please turn to Slide 12. Due to a reduction in the inter-month correlation versus historical levels between our busbar prices and INDY Hub prices year-to-date and our expectation that this will continue for the balance of the year, we have reduced our balance of the year hedge levels for the Coal segment to 57% of expected generation. This leaves the portfolio more open to plant busbar pricing in 2013 while protecting a portion of the remaining hedges with financial transmission rights, or FTRs. Hedges for the Gas segment have also been slightly reduced for the balance of 2013 to account for any potential operational disruptions during peak periods. Hedges continue to be layered in for both portfolios in 2014, with hedge levels currently around 34% for the Coal segment and 41% for the Gas segment. We've initiated hedging our portfolios in -- for 2015 at 3% and 6% for the Coal and Gas segments, respectively. 71% of our coal is priced for 2014. And although 53% is contracted in 2015, none is currently priced. Our rail transport contract price is fixed through 2015 and beyond, and our natural gas supply position is consistent with our forward power sales. Dynegy participated in PG&E's energy and resource adequacy RFO process this spring. Moss Landing 2 was awarded 500 megawatts for Q3 2014 resource adequacy and 200 megawatts in 2015. PG&E has initiated an additional RFO process solely for the 2014 timeframe. Offers have been submitted to PG&E for all of Dynegy's uncontracted units in California, and we expect feedback early in Q4 of this year. Please turn to Slide 13, where I will discuss changes to how we are managing the Coal portfolio. As we discussed on the first quarter call, the Indiana Hub has been a relatively liquid trading location for buyers and sellers of financial power. Dynegy has historically hedged the coal fleet at this location. However, as the chart indicates, the correlation between the power prices received from MISO at the busbar versus the hedged price at the Indiana Hub has eroded significantly in the past year and most particularly, over the past 6 months. We attribute this breakdown in correlation to significant scheduled line outages close to our Baldwin facility, as well as unplanned transmission and generation outages in Indiana in June. In addition, the proximity and the dispatch patterns of the Prairie State's units have magnified basis impacts at Baldwin. The diminishing correlation between our busbar prices and prices at the INDY Hub reduced the effectiveness of hedging at INDY Hub. As the correlation has decreased with INDY Hub, the commercial team has reduced hedging positions at that location. We are purchasing a firm transmission rights and busbar sales to improve the effectiveness of our remaining INDY Hub hedges to reduce the impact of swings in basis on our earnings. There is a significant amount of work that will be done by MISO over the next several years associated with its MISO Transmission Expansion Plan, or MTEP, which includes projects that will ultimately relieve congestion across the MISO system to some extent. Because of the transmission upgrade projects scheduled to occur over the next few years and the previously mentioned factors influencing basis, we will continue to evaluate the relationship between our facilities' LMP and Indiana Hub, adjusting our hedging strategy based, in part, on the correlation between our facilities and the INDY Hub. Please turn to Slide 14. Last quarter, we devoted some of the discussion to the Coal segment's basis issues that have resulted from transmission work on the Mt. Vernon substation and transmission lines in the southern part of Illinois. This work created additional congestion, as Baldwin and the nearby Prairie State facility had less transmission capacity available to move their combined 3 gigawatts of power to the load centers. The timeline provided on this slide details the basis differential the Coal segment has recently experienced. We had several periods of increased basis differential, the first during the Mt. Vernon substation outage, and the second in June, when there were multiple unscheduled line outages and generation outages along the Indiana-Illinois border. It's important to note that many of the basis disruptions were reflected in the higher prices at the INDY Hub, as opposed to a decrease in the Coal segment's busbar prices compared to our plan. As the timeline also indicates, the coal fleet experienced several periods of improved basis when the Mt. Vernon substation work was complete and when the Prairie State units were in outage. As I mentioned on the previous slide, we will continue to manage the Coal portfolio to protect the value of the fleet from these basis swings while the grid is being updated to relieve congestion. Please turn to Slide 15. We have shifted our commercial hedge strategy in several ways in order to manage the LMP price risk at the Coal segment more effectively. First, we have participated more aggressively in annual and monthly FTR auctions. In the annual MISO FTR auction conducted in May 2013 for the 2013, '14 planning year, we secured FTR volumes equal to approximately 17% of the around-the-clock output of our coal facilities on an annualized basis. Second, we have executed a total of 500 megawatts of around-the-clock busbar basis swaps for 2014, which allows us to perfect hedges put on the INDY Hub for that period. Third, we have bought back a portion of our unperfected hedges at the INDY Hub that are not supported by busbar sales or FTR positions. Through implementation of this strategy, we have mitigated a substantial portion of the basis risk associated with our hedging activity. This does leave us with a larger open position at the plants, which exposes us to market risks at the busbar but substantially reduces our exposure to the risk of a price increase on our hedges at the Indiana hub without a corresponding increase in price at our generation LMPs. Over the mid to long term, we will continue to aggressively pursue additional busbar basis swaps for 2014, 2015. We have begun a process of customer outreach through our origination efforts, which should provide us with the opportunities to diversify our LMP and basis risk across a broader set of market participants. We will also seek to optimize our LMP pricing and basis risk management through energy sourcing for AEM's retail portfolio post-closing. As mentioned in previous earnings calls, we are evaluating multiple transmission infrastructure upgrades to reduce congestion around our coal facilities. Please turn to Slide 16. We continue to pursue multiple transmission solutions to reduce congestion in our facilities and to improve market access. Through our third-party transmission study, we have identified 19 primary contributors to constraints that adversely impacted congestion at our coal facilities in 2012. These constraints were also studied in relation to the MISO Transmission Expansion Plans to determine if the planned projects would relieve congestion at our facilities. The study indicates that 17 of the constraints will be relieved through a series of planned transmission projects as part of MTEP, with completion dates scheduled between 2013 and 2018. Two promising projects were also identified that are not part of the MTEP process, which will relieve congestion for Baldwin and other coal facilities. These prospective projects require funding by Dynegy, as opposed to the MTEP process. These projects include a transformer replacement, increasing ground clearance and replacement of the conductor on certain transmission segments. Additionally, we have identified another potential Dynegy-funded project to mitigate potential future congestion that may result from completion of MISO's Illinois River Project in 2018. We have engaged Ameren transmission to develop a project plan and cost analysis for these projects. Upon completion of the planning and cost analysis phase of the project, we intend to make a formal request with MISO to approve the projects. We estimate completion of the project that reduces existing congestion to be in 2015 and the completion of the project mitigating future congestion to be in 2017. In effort to gain potential PJM capacity and market access, we have transmission service request in place with MISO and PJM to evaluate the economic feasibility of up to 3,000 megawatts of transmission capacity to PJM. The requests are under evaluation by both MISO and PJM, and we expect responses to our requests in Q4 of this year. Additionally, we have a generator interconnect request pending with PJM to study the economics of connecting Baldwin to PJM through incremental investment in transmission. Turning to Slide 17. The MISO independent market monitor, Potomac Economics, recently stated in the 2012 State of the Market report that MISO's 2013 reserve margin may actually be tighter after accounting for non-firm imports and realistic projections for wind and demand response contributions. If an unusually warm summer was to occur, MISO would be relying on imports from sources that could be committed elsewhere during times of peak demand. The IMM also made a case that wind and demand response contributions were overstated, which results in overstated reserve margins and send a distorted price signal to the capacity markets at a time when coal plant owners are making decisions whether or not to invest in environmental retrofits. The IMM report determined that when including these reductions from MISO's official reserve margin of 28% for 2013, the actual reserve margin should be closer to 19% during normal load conditions. Taking the recommendations from the MISO market monitor into account and adding MISO's additional net retirement projections and confirmed exports to PJM implies the potential reserve margin of 6% by 2016. The market monitor has also stated that MISO's capacity market design does not send adequate price signals for new investment and has recommended the following changes. First, the vertical demand curve should be replaced with a sloped demand curve. The vertical demand curve does not assign value to capacity above and beyond MISO targeted reserve margin and, therefore, does not provide adequate economics signals to market participants until reserve margin deficit occurs. Second, given the intermittency associated with wind energy, the IMM has recommended that a more realistic view of wind capacity availability be employed by MISO in their capacity options and reserve margin calculations. The IMM has suggested that the wind capacity used in MISO reserve marketing calculations may be overstated by as much as 3x. The third recommendation of the MISO IMM is that barriers to efficient transfer of capacity between ISO should be removed to broaden the economic signals required to enhance rig reliability. We fully support the recommendations of the MISO IMM, we will continue to be an advocate for system reliability and efficient market design through industry group participation and regulatory outreach. Please turn to the next slide. MISO has recently published more detailed information about zonal resource adequacy in their 2013 summer resource assessment. Although the MISO capacity market is a systemwide market, it is helpful to look at zonal resource assessments when building a forward view on capacity markets. Zone 4, where our coal fleet is located, currently has a 25% reserve margin. However, taking into consideration the MISO market monitor's adjustments for wind and demand response, as well as the 850 megawatts of capacity that will most probably be exported to the PJM market, the projected reserve margin is 12% in Zone 4 by 2016. Please turn to Slide 19. We have previously provided EBITDA sensitivities for 3 variables: the effect of a 500-point movement in market applied heat rates; a $1 per MMBtu change in the price of natural gas; and a $1 per megawatt hour change in basis. As noticed -- as noted in previous presentations, the calculations associated with these sensitivities are very straightforward when simplifying assumptions are made and other variables are held constant. For example, if we hold the gas price constant at $3.46 per MMBtu, a heat rate change of 500 points results in a change in projected EBITDA of approximately $39 million for the Coal segment. This is computed by taking the difference between the current market price of power at the INDY Hub and the price following a market applied heat rate extension of 500, and then multiplying that difference by our estimated annual coal-based generation volume of 22 million megawatt hours. Because our natural gas sensitivity assumes each $1 increase in natural gas prices results in a $7 increase in the price of power, the impact is simply our coal-based generation volume multiplied by 7, which results to an EBITDA impact of $153 million. In practice, the appropriate application of these sensitivities is to view and apply them as interrelated variables. A practical application of these sensitivities requires a view on the interaction between the variables, as increases in natural gas prices are typically viewed as having a dampening impact on market heat rates. Please turn to the next slide, where we describe our recent internal analysis of the relationship between forward natural gas and INDY Hub prices to validate these sensitivities. We performed a historical analysis to study the relationship between the movements of prompt calendar strip prices for both NYMEX Natural Gas and INDY Hub power prices since January 1, 2010. Our analysis yielded the following results: a $1 per MMBtu increase in the forward calendar strip of natural gas prices implies a change in price for on-peak power at INDY Hub, ranging from $5.40 to $7.20 per megawatt hour; and a change in price for off-peak power at INDY Hub from $1.90 to $3 per megawatt hour. The results are consistent with what we'd expect, in that natural gas-powered facilities are often the marginal priced heating unit during on-peak hours, while the coal-powered generation typically sets the price in off-peak hours. This is also consistent with data suggesting combined cycle plants are operating in MISO's central region at a 30% to 35% annual capacity factor, and gas is on the margin systemwide within MISO during a significant number of on-peak hours. The conclusion we draw from this analysis is that, with the $1 per MMBtu increase in natural gas prices from finished price levels, we can expect a heat rate contraction of approximately 500 points to 700 points. Further, using the midpoint of the ranges of both on- and off-peak prices implied by our historical analysis suggests that when applied to an unhedged Coal segment fleet and holding basis constant, Dynegy's adjusted EBITDA should change by approximately $100 million for every $1 per MMBtu change in natural gas price due to the observed relationship between natural gas prices and heat rates in the forward market. Turning to Slide 21. We then tested the natural gas price and heat rate sensitivities previously provided to determine if they provide the same outcome as the forward analysis. A $1 per MMBtu increase in natural gas price yields a $153 million positive change in adjusted EBITDA. Assuming an implied heat rate degradation of 600 points at a rate of $39 million per 500 points, this equates to a $47 million reduction in adjusted EBITDA. Our estimate is that when taking into consideration the expected inverse relationship between natural gas prices and market heat rates and holding basis constant, a $1 per MMBtu upward move in natural gas prices results in a change in adjusted EBITDA of approximately $100 million when implied -- applied to an unhedged Coal segment fleet. At this point, I'll turn it over to Clint for our financial review.

Thank you, Hank. The company's midyear financial summary is outlined on Slide 23. And as you can see, second quarter consolidated adjusted EBITDA totaled $8 million compared to $11 million in the second quarter of 2012, as a meaningful improvement in Gas segment results was more than offset by continued weakness at the Coal segment. Despite a 28% decline in total generation volumes and generally lower spark spreads, Gas segment adjusted EBITDA nearly doubled to $53 million, primarily due to the absence of negative settlements associated with legacy put options and other out of the money commercial positions, which adversely impacted results last year. The Coal segment, on the other hand, experienced a $29 million decline in quarter-over-quarter results, as outages at Baldwin and Hennepin, together with negative hedge settlements and higher rail costs, put downward pressure on quarterly results. Year-to-date, adjusted EBITDA totaled $51 million compared to $49 million during the first half of 2012. While year-over-year consolidated results were not materially different, segment results were, as a $47 million increase in Gas segment adjusted EBITDA offset a similar decline at the Coal segment, with a difference in consolidated results primarily attributable to lower G&A expenses period-over-period. Similar to the second quarter, the Gas segment benefited from the absence of legacy commercial positions, while the Coal segment expensed higher outages, higher transport costs and lower realized prices due to hedges being at lower prices than those in 2012. As previously disclosed, Dynegy completed its balance sheet restructuring during the quarter by refinancing its CoalCo and GasCo term loans with both secured and unsecured debt at the parent company level and replaced the subsidiary level revolver at GasCo with a larger parent company revolver at DI. We executed this refinancing earlier in the year than planned. But in so doing, we were able to lock in interest rates well below what we have targeted at the beginning of the year. Additionally, the amount of restricted cash release at closing was significantly higher than previously expected. Total liquidity as of Friday, July 26, was $787 million, including $500 million in unrestricted cash and $287 million in unused availability under Dynegy's new revolver. In addition to the impact of the refinancing, Dynegy's liquidity has improved as the collateral intensity of the business has been reduced. Aggregate cash and letter of credit postings are currently below $250 million, which is the lowest collateral level in 7 years. As Bob mentioned earlier, we are updating our adjusted EBITDA and free cash flow guidance today. While Gas segment earnings and results from the refinancing have exceeded our expectations, weakness at the Coal segment, driven primarily by significantly higher-than-forecasted basis differentials and the impact this had on our net realized prices, has negatively impacted guidance. Because the Coal segment decline is more pronounced than the uplift at the Gas segment, we are lowering our consolidated adjusted EBITDA guidance range by $50 million to $200 million to $225 million. Despite this, however, we are raising our free cash flow guidance by $50 million to $190 million to $215 million, as the cash flow benefits associated with the refinancing exceeded even our best case scenario. Moving to Slide 24. Second quarter adjusted EBITDA for the Coal and Gas segments totaled $29 million compared to $32 million for the second quarter of 2012. But as you can see, segment results went in opposite directions, as strength in the Gas segment was more than offset by weakness in the Coal segment. Gas segment adjusted EBITDA totaled $53 million during the second quarter of 2013 compared to $27 million during the second quarter of 2012. Last year's results were weighed down by $61 million in negative financial settlements compared to just $2 million during 2013, providing a meaningful uplift in comparative results this year. Somewhat offsetting this benefit, however, was a $19 million decline in physical energy margin as spark spreads at Kendall, Ontelaunee and Independence contracted, leading to a 28% decline in generation volumes. Additionally, capacity and tolling revenue declined by $9 million quarter-over-quarter, driven primarily by the SCE contract termination last year and lower capacity revenues, primarily at Kendall. Coal segment adjusted EBITDA totaled negative $24 million during the second quarter of 2013 compared to positive $5 million during the second quarter of 2012. During the period, the Coal segment saw significant outages at Baldwin and Hennepin, resulting in $10 million of lower gross margin and higher operating expenses compared to last year. Adjusted for lost volumes, realized revenue net of hedges declined by $13 million compared to the second quarter of 2012, as the company was the net payor under its hedges during the period versus being a net beneficiary last year. During the second quarter last year, Coal segment hedges were priced, on average, $0.88 per megawatt hour higher than average market prices during the period, resulting in $5 million of positive hedge settlements. However, during the second quarter of 2013, average hedge prices ended up being, on average, $4.85 per megawatt hour below market, leading to $14 million in negative settlements. This $19 million reduction in hedge settlements was partially offset by a $6 million increase in physical energy margin. As Hank mentioned earlier, around-the-clock basis differentials averaged $8.99 per megawatt hour, a $4.07-per-megawatt-hour increase over the same period last year. However, the rise in INDY Hub prices, compared to last year, more than offset this, leading to a $1.34-per-megawatt-hour increase in realized around-the-clock LMP prices. And similar to the first quarter, rail transport costs rose by $4 million compared to the second quarter of last year as part of the 2012 rail contract modification. Year-to-date, Gas segment adjusted EBITDA totaled $114 million compared to $67 million during the first half of 2012. Last year's results were adversely impacted by $83 million in negative financial settlements compared to $10 million in negative settlements during 2013, providing an uplift in comparative results. However, this benefit was partially offset by an $11 million reduction in capacity revenues, primarily at Kendall, and an $8 million reduction in tolling revenues associated with the SCE contracts. Similar to the quarterly results, year-to-date Coal segment adjusted EBITDA fell by $47 million, as the results were negatively impacted by outages, hedge settlements and rail costs. Higher planned and unplanned outages during the first 6 months of 2013 resulted in the loss of 742,000 megawatt hours of generation compared to the first half of 2012, resulting in $17 million of lower gross margin and higher operating expenses. Excluding the volume impacts, energy margin net of hedges declined by $18 million, as lower financial settlements more than offset an increase in LMP prices. Hedges for the first half of 2013 were initiated at levels that ended up being, on average, $0.98 per megawatt hour below market prices, resulting in net payments of over $4 million, while hedges for the same period last year were initiated, on average, at levels that ended up being $3.15 per megawatt hour above market prices, leading to net settlement receipts in excess of $28 million. This $33 million reduction in hedge settlements period-over-period more than offset a $15 million increase in physical energy margin, which resulted from a $1.45-per-megawatt-hour increase in average around-the-clock LMP prices and, together with the impact of outages and a $9 million increase in rail transport costs, led to the decline in segment adjusted EBITDA. As I mentioned earlier, Dynegy completed its corporate refinancing during the second quarter, and the details of our new credit facility and debt issuance are outlined on Slide 25. We're very pleased with the results and believe that the new capital structure not only dramatically reduces our cost of debt but also provides Dynegy with significantly greater financial flexibility, both in managing and growing the company going forward. As part of this effort, we put in place a new corporate revolver. And as you can see on the right-hand side of the slide, availability under the revolver totaled $287 million on July 26. This, together with the $500 million in unrestricted cash brings that Dynegy's total available liquidity to $787 million. As total liquidity has increased, collateral requirements have decreased with cash and LC postings currently totaling $243 million, down from over $300 million at the beginning of 2013 and down from over $800 million this time 2 years ago. As I mentioned earlier, we are updating our 2013 adjusted EBITDA and free cash flow guidance today, and the details can be found on Slide 26. We've been very pleased with the financial performance of the Gas segment this year and the impact of the refinancing. However, weakness at the Coal segment, specifically around widening basis differentials between our plants and INDY Hub has caused us to reassess our adjusted EBITDA expectations for the year. Beginning with the Gas segment, we are increasing the midpoint of our guidance range by $20 million, as higher-than-expected spark spreads at Independence and Moss Landing have resulted in higher generation and gross margin at those facilities. Additionally, our Moss Landing and Morro Bay facilities will be receiving resource adequacy payments in excess of our original forecast for the year. As you can see, we have also narrowed the range from $25 million to $15 million, as the segment's highly hedged position and strong operational performance has increased our confidence in the segment's full year results. At the Coal segment, the primary driver behind the unit's underperformance is a weakening relationship between INDY Hub prices and our plant LMPs. This has impacted us in 2 ways: at certain times, lowering the prices we receive for our power at our plant LMPs; and at other times, increasing financial settlements as INDY Hub prices rise without a corresponding uplift at our plants. As Bob indicated earlier, we initiated guidance at the beginning of the year with around-the-clock basis of soon-to-be $4.36 per megawatt hour. But given our limited ability to hedge that exposure, we highlighted that a $1 change in this number would translate into a $22 million change in adjusted EBITDA. With actual around-the-clock basis of $7.86 per megawatt hour through the first 6 months, we have reevaluated this assumption for the rest of the year and have reset our around-the-clock basis assumption for the balance of the year at $6.70 per megawatt hour. With this revised assumption, our blended average basis for the year is assumed to be $7.11 per megawatt hour, or $2.75 per megawatt hour higher than originally anticipated. Based on the sensitivity provided, this alone would lower results by $60 million. Half of this has been offset, however, by rise in INDY Hub prices from our original forecast of $30.06 per megawatt hour, on average, around-the-clock for 2013 to $31.46, using actual prices to date and balance of year INDY Hub prices as of July 29. As a result of these factors, our estimated 2013 average around-the-clock LMP price now stands at $24.35 per megawatt hour versus our original forecast of $25.70, leading to a reduction in physical energy revenues of approximately $30 million. Normally, what we would expect to see from our financial hedges would be positive settlements to offset the loss in physical energy revenues. But due to the breakdown in the relationship between our plants and INDY Hub, this is not what has happened. Instead, CoalCo's hedges have moved out the money by approximately $25 million, net of basis swaps and FTR positions, compared to our original forecast as INDY Hub prices have risen. This, together with the reduction in physical energy revenue, brings the total impact of basis differentials net to approximately $55 million for the year relative to our original guidance. The balance of the $70 million change in the Coal segment guidance range is primarily attributable to higher-than-expected outages during the first half of the year and lower capacity revenues compared to our forecast. Before leaving the Coal segment discussion, I would note that our updated forecast in guidance range is as of July 29 and incorporates our hedge profile and forward commodity price curves as of that date. With over 4 million megawatt hours of our expected generation for the balance of the year open to the market, our results remain highly sensitive to market prices for the remainder of the year. Despite the reduced expectations for our consolidated adjusted EBITDA, we are lifting our 2013 free cash flow target by $50 million to $190 million to $215 million, primarily as a result of the timing and structure of the refinancing. In our original forecast, we assumed that the refinancing will be executed in August of this year at an all-in blended rate of 6%. As a result of executing in April and May at an all-in blended rate of 4.72%, our forecasted interest expense for the year has been reduced by $30 million. Additionally, the company was able to free up $335 million in previously restricted cash versus an estimated $298 million, providing an additional $37 million uplift. And finally, we anticipated repaying $150 million in debt so that the refinancing would total $1.2 billion. Instead, we chose to pay down only $61 million using a portion of the $89 million difference to fund the incremental costs incurred as a result of the larger debt issuance, the larger revolver, the bond issuance that was not in the original plan and the incremental make-whole payment due to the previous lenders as a result of repaying their debt before the August call date. These additional costs totaled $56 million, leaving $33 million in additional cash provided by the lower debt repayment, net of additional transaction expenses. This amount, together with the lower interest expense for the year and a higher restricted cash return, accounts for the $100 million cash flow uplift associated with the refinancing and, when netted against the updated consolidated adjusted EBITDA guidance, for the $50 million increase in free cash flow guidance. With that, I'll turn the call back over to Bob.

Thank you, Clint. And for those of you on the call, I know our prepared remarks have been a bit more extensive than historically done, but we had a lot of topics that I thought were worth going to some level of depth on. Prior to beginning the Q&A session, on Slide 28, we just want to reaffirm that our complete belief in the investment thesis for Dynegy, while we are not in the least satisfied with our 2013 adjusted EBITDA performance, the second quarter continued our progress across the company in many areas that positions us for long-term success. And we will continue to advance the actions, projects and investments necessary to address the congestion issues impacting the Coal segment. Transmission network analysis we initiated during the fourth quarter of 2012 provided us the blueprint to address congestion points, both near and longer term. In addition, we remain focused on improving all aspects of the company and capitalizing on opportunities. And, Gwen, at this point, I would like to open up the phone lines for Q&A.

[Operator Instructions] The first question comes from Neil Mehta, Goldman Sachs.

So what's being implied as the basis differential in 2H 2013, implicit in your guidance? And then are you in a position, as you look towards 2014, to guide us to what you think the right level of basis to use in that year is? Is it something closer to 2012 levels?

Well, on the question in terms of the basis for the full year estimate, we have $7.11. And as the estimate for basis with the balance of the year, at $6.70. And when we think about 2014, what Hank spent a lot of time on, it was really to focus on how do we just really take basis, to a larger extent, out of the equation. So to the extent that we're hedging at INDY Hub, we're dealing so where it's perfected. We either have busbar swaps executed or FTRs to take the volatility out of the basis. So for 2014, it's going to be less of an issue than it is in 2013. By the way we've adjusted the way we're approaching our hedging. What we will be doing is leaving more the portfolio open. We're wearing that market risk today anyway, given the correlation reduction between the 2 points. So our combination of -- for 2014 in addressing, perfecting the hedges and having more open -- portfolio more open, we really reduced the basis issues. So what we've seen during the course of this year as well is not that the LMP prices saturated, it's just that the volatility has been more around Indiana Hub, whether it's for planned outages in and around Indiana or transmission line maintenance or outages. The volatility has been at the INDY Hub not at the LMP, and what we're looking to do is take that volatility away from our earnings.

Got it. And on the balance sheet, you're currently sitting on a $500 million of cash, you got almost $800 million of liquidity. Do you have a target cash balance or liquidity level in mind? And can you talk us through how you're thinking about capital allocation?

Well, I'll talk about capital allocation first, and then I'll let Clint talk about how we target the available liquidity and cash on hand. We continue to evaluate all options around capital allocation, and certainly, one of the things we have discussed at the board level is using some of that cash for share repurchases as well. In the very near term, given the way we're readjusting how we hedge the portfolio, we want to make sure that, if we have less hedged, that we have the ample liquidity to support that now, recognize that, that takes less collateral hedge, less collateral, but there will be -- could be more volatility around market prices, so we want to make sure that we have available liquidity to address that. In addition, in the near term, while we're going through the proceedings around the Ameren acquisition, at this point, I'm not knowing the full outcome of that. We want to make sure that we preserve the right amount of liquidity for the operations and not overcommitting any particular area at this point in time. But all those options remain on the table, and once we have, I guess, more clarity and stability in some of these areas, then we will act upon maybe some of the other alternatives that are out there for us. Clint, you want to talk about the balance, as you see it?

Yes, I think, Neil, what we've spoken about historically was, given our -- the existing business, that we felt like we needed somewhere around $500 million in excess liquidity or available liquidity to support things like working capital, fluctuations, collateral needs and so forth. And I think that remains the case, although as we think about going forward, to the extent that we're going to be hedging a little bit less, we may want to be a little bit more conservative on how much liquidity we want to maintain just to be able to -- to be comfortable with the volatility that may be associated with that lower hedge level. I would also note, though, that as you're hedging less at coal, your collateral requirements may go down, at least to some extent. A lot of that is being done by first lien. But in any event, you may see a benefit there, but I would say, relative to what we've said in the past, with a target of maybe $500 million, again, with lower hedge levels going forward at coal, we may want to be a little more conservative on that front.

The next question comes from Brandon Blossman, Tudor Pickering, Holt & Co.

I guess focusing on the basis last -- just issues. One, first half of the year, obviously, transmission outages played a role. Second half of the year, we're still looking up year-over-year on the basis spread. Is that primarily a Prairie State issue or have other things changed in the grid year-over-year?

No, it's primarily Prairie State. What we've seen is that as they have both units running, that puts us into the area of triggering that higher level of congestion. Prairie State operations, from what we can tell and looking at -- for various generation reports, that they still have a lot of ups and downs around their -- around both of their units. But clearly, when they're both running, the level of congestion that's impacting the system and basis is what -- when we think about the second half of this year, that's where I would say that we're most concerned about the impact from that.

Okay, fair enough. And then can you kind of -- maybe not quantify it, but order of magnitude, talk about success in busbar sales, either financial swaps or selling direct to a counter party?

Well, for 2014, like what Hank said in his comments, is that we had 500 megawatts of busbar swaps executed.

That's right.

We had -- Do we have any '13, Hank?

Yes. Yes, we do. 250.

There will be 250 megawatts for the balance of this year in busbar swaps as well. And when you think about pricing and the like, I mean, it's order of magnitude around our levels of guidance to where we think it is. So we view it pretty much as market based. It just gives us the insurance and takes out the volatility. In addition to the busbar sales through the balance of the year and for next year, we also have the FTRs, which also complement the busbar swaps as well. So those 2 together, and you'll see on the 1 slide that we put out there, I think it was Slide 15 that shows the amount we referred to as perfected hedges is significantly greater than what it has been historically. When you think about the balance of this year as well on the coal fleet, we're roughly a little over 50% hedged. And of that, half of the portfolio being hedged, half of that half is protected via busbar swaps and FTRs.

Okay, good color. And then on '14 coal hedges, 34%, you are obviously indicating that it'll be lighter. Will it be that light or will it be more like '13?

No, I think, probably, what we'll end up when you think about 2014, we think we can -- in terms of managing the hedges with perfected instrument around it, we can probably do about half of the portfolio or so, half of the coal portfolio.

Okay. And that's what you'll target?

Yes.

Your next question comes from Jon Cohen, ISI group.

Apologies if you covered this already, but -- so if the -- Illinois Pollution Control Board rejects your revised variance request, what are your options and would you consider waiving that condition to close?

Well, if they were to reject it, I mean, I think it would be an interesting outcome because the plant, in terms of being compliant with the multi-pollutant standards, it's not going to be able to happen by 2015. But from our standpoint, we would have to take it back to the board and discuss, what do we do from here? Do we go forward with it or do we not? If we were to decide to go forward with it, the way that we would have to comply would be to shut down plants, and that's not what we want to do, and that's not what the stakeholders in and around us want to do either. Or it's a condition in the purchase and sale agreement that if we don't achieve it -- if we don't get that variance, then we don't have to close. So we would have to take it back to the board, review the options, review the financial impact, shutting a couple of plants down but not making the investment and scrubber. As to whether or not, that's still is the right financial decision for this company going forward or not, so that's a board level decision that, at this point in time, we have not addressed. But we remain confident that we'll get the variance, and I have to say that the support that we're getting from the communities and from the unions throughout Illinois and the employees has been very encouraging, and we're hoping to be -- to successfully bring this process across the line later this year.

Presumably part of that financial analysis would take into account the potential for pricing uplift in MISO capacity and power pricing uplift or basis reduction from [indiscernible].

At this point in time, we haven't done any evaluation as to result in any other alternatives with it because we remain on path to close it and run all the plants.

Okay. And then one other question on -- I think you said that it's helpful when you're looking at supply-demand fundamentals, and MISO to look also at the zonal capacity versus the zonal supply and demand. So if I look at your Zone 4, it looks like the reserve margins there are actually higher than MISO as a whole. Does that hurt you or would you only benefit if the -- if Eurozone is tighter than the rest of MISO?

I mean, the capacity market for MISO is the entire area, so it doesn't necessarily hurt us. But if you take a look at Zone 4 in terms of what appears to be confirmed exports to PJM, and Zone 4 is a fairly tight market as well, the capacity market is -- the way the construct works is that the folks serving load, they can go into different zones to bid for capacity, those offering capacity can't go to other zones. It's one of the design constructs of the MISO capacity market that we would like to see a bit different.

Your next question comes from Amer Tiwana, CRT Capital.

My question, I know you're sort of busy with the Ameren transaction, but some of the other assets and some regions that you operate are also for sale at this point in time, and I'm specifically talking about Edison Mission. Have you looked at their coal portfolio? I know they're looking for more transaction there. How that fits into your portfolio and whether those would be assets that you would be interested in?

Well, I mean, at this point, I mean, I'd say that we have our hands full between the Ameren acquisition, managing the existing portfolio, we've got our union contract negotiations at the coal fleet going. So our focus is operations, protect this portfolio, be successful with Ameren. Certainly, Mario Alonso, who runs our strategy before, stays aware of what's happening in the marketplace. But right now, our focus is executing well on our operations and getting the Ameren transaction across the line. That's the priority for us.

Your last question comes from Julien Dumoulin-Smith, UBS.

So I wanted us to shift the focus here back to California lastly. Obviously, some great wins in the quarter. I'd be curious, can you speak to what the revenue uplift is from some of these awards, maybe specifically in '13 as it relates to the upside of the Gas portfolio?

Off the top of my head, Julien, I cannot -- Clint or Hank, do you have the revenue lift from the awards? Are you talking about the '13 awards or are you talking about the '14?

Well, I mean, we could use the '13 to back into '14 implicitly, I suppose, but...

So $13 million -- I'm sorry, for 2013, it's about $11 million.

Roughly, yes sir.

$11 million uplift?

Yes. And I think when we think about our guidance, there is an uplift associated with what we've gotten in California, it's probably a little bit more than half of that for guidance purposes.

True. Yes.

Got you. And then just to talk probably about California, how do you think about 6 and 7, given the outcome of the RFO, Morro Bay, et cetera?

Well, Julien, I think -- when I think about 6 and 7, there's a lot of different things that go into the equation. Certainly, we still believe the plant, with its capabilities, the ramping capabilities and flexible capacity, will be a key part of the equation in California for firming up renewables and grid reliability. Also, as we continue to work through a parallel path on our discussions with Southern Cal Edison, on the terminated contracts and with going down the dual path on that: one is litigation/arbitration; the other path is work through a new commercial arrangement. It's a parallel path, and certainly, I would desire the latter to get away from the legal arbitration path. And we're slowly making progress. And whether it comes to fruition or not, time will tell, but having Moss 6 and 7 can play into that as well. So I think there's a bridge for Moss 6 and 7 between now and when the flexible capacity market matures and develops, and Moss 6 and 7, I think, again, is with the best operating capabilities or ramping capabilities in the state. We remain confident and optimistic around Moss 6 and 7.

Excellent. Perhaps a big picture question on the coal portfolio, again. Obviously, we've gotten some drastic coal ash rules for state-specific standards in Illinois. And we've also seen some finalization of 1-hour SO2 standards. I'd be curious, does that change the environmental compliance program that you guys have laid out as of right now?

No. I mean, we've been doing all of our environmental planning and whether it's our fleet or are planning for Ameren, we've -- we stay close to the regulations and understand what's coming. So there's some change in our environmental CapEx spend. Again, thanks, everyone, for joining the call this morning.

Thank you.

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