Dyne Therapeutics, Inc. (DYN) Q4 2013 Earnings Report, Transcript and Summary

Hello, and welcome to the Dynegy Inc. Fourth Quarter and 2013 Full Year Review Teleconference. [Operator Instructions] I now would like to turn the conference over to Mr. Andy Smith, Managing Director, Investor Relations. Sir, you may begin.

Thank you, Shirley. Good morning, everyone, and welcome to Dynegy's investor conference call and webcast covering the company's fourth quarter and full year 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 today are Clint Freeland, our Chief Financial Officer; Hank Jones, our Chief Commercial Officer; Catherine Callaway, our General Counsel; and Sheree Petrone, our Vice President of Retail. Our agenda for today's call is located on Slide 3. I'll begin by providing an overview of our accomplishments and performance during 2013 and our initial financial guidance for 2014. In addition, updates covering synergies achieved from the acquisition of the Ameren facilities will be reviewed, followed by the introduction of our PRIDE Reloaded targets and an introductory discussion of our retail business, Homefield Energy. During our call, our references to the Coal segment pertain to the legacy Dynegy Coal fleet while IPH refers to the acquired Ameren coal plant and retail business. Hank Jones will discuss our commercial activities and additional analysis on the locational marginal prices, or LMPs, realized by the Coal segment and IPH and their relative differentials to INDY Hub. Hank will provide a status update on transmission projects aimed at relieving congestion around our Coal segment facilities. Clint will review the fourth quarter and full year financial performance, liquidity and an in-depth look at our 2014 guidance. I will close the discussion with an overview of our 2014 objectives. And with the remaining time, open the discussion for your questions. An overview of our significant 2013 accomplishments is included on Slide 4. Our safety results during the year yielded Dynegy's best-ever performance and substantially better than the prior 2 years. Our financial results met our guidance range for adjusted EBITDA and exceeded the top end of our guidance range for adjusted free cash flow. We successfully integrated the Ameren acquisition and realized the synergies, which, in total, significantly exceeded our expectation. We also settled a long-standing dispute through a revised long-term service maintenance agreement that lowered collateral by $80 million, resulting in better forward cash flow profile and includes an 80-megawatt upgrade of our Kendall facility through hardware improvements on the combustion turbine. 40 of the 80-megawatt upgrade will be online in 2014 with the remaining 40 megawatts online by 2016. The refinancing completed in May reduced our overall annual interest rate to 4.72% and released $335 million of restricted cash. We ended the year with nearly $1 billion in liquidity at the Dynegy level, which, in turn, provides us with future capital allocation opportunities. 2013 results and 2014 guidance are shown on Slide 5. Our recordable incident rate improved approximately 35% compared to 2012 and reached EEI's top quartile performance level. Recent harsh winter weather conditions introduced additional safety challenges for our employees vigilantly working to keep plants online, and we have taken additional precautions and performed additional training to keep everyone focused and alert. Generation from our gas fleet declined 20% in 2013, primarily due to lower spark spreads. Coal-fired generation was flat as increased generation followed a major planned outage at Baldwin in 2012 was offset by higher-than-anticipated forced outages. Adjusted EBITDA for the Coal segment declined $24 million compared to last year due to several factors, including lower realized prices on hedged volumes, basis impacts in the first half of the year and increased forced outages late in 2013. More than offsetting the Coal segment decline was a $180 million year-over-year improvement from our Gas segment. This improvement was primarily due to the absence of legacy commercial positions that negatively affected 2012 results, as well as improved capacity pricing. Finally, we are introducing 2014 guidance, targeting an adjusted EBITDA range of $300 million to $350 million and a free cash flow range of $10 million to $60 million. Our fleet performance is shown on Slide 6. The eastern gas fleet experienced lower on- and off-peak spark spreads during 2013. As a result, capacity factors for the majority of our combined cycle units were down year-over-year. Ontelaunee was impacted by planned outages, and Kendall was impacted by a planned outage and then extended outage. We continue to expect the low capacity factors experienced by our Casco Bay facility to improve with the expanding access to natural gas supply as Deep Panuke increases production. End market availability, or IMA, for our Gas segment at 97% improved year-over-year while IMA at the Coal segment fell due to the unplanned outages. During 2014, we're undertaking a series of initiatives to improve IMA for the Coal fleet as well as the IPH fleet. In addition, we are implementing the IMA performance metric at IPH that we will report on quarterly. Slide 7 highlights the targeted and achieved synergies resulting from the integration of the IPH assets acquired from Ameren and the corresponding source of the savings. The initial $60 million synergy target announced the day of the acquisition, as well as the upwardly revised $75 million target, now stands at $95 million. Furthermore, virtually all of the actions required to realize the synergies in 2014 are in place. Our cost to implement $95 million in synergies was only $13 million. From this time forward, future synergies and improvements at IPH will be part of our PRIDE Reloaded efforts that I will describe shortly in more detail. Slide 8 highlights the final results of our PRIDE 2011 to 2013 program. Created in 2011, PRIDE is our way of generating significant value by lowering the ongoing cost structure of the company, implementing margin-expanding opportunities and creating a more efficient balance sheet. We do this through a structured problem-solving approach focused on continuous improvement. Over this time period, PRIDE initiatives contributed $90 million of fixed cash cost savings, $56 million in margin improvements and over $700 million in balance sheet improvement. Our success in integrating the IPH portfolio to capture $95 million in synergies is attributable to the skills of methodology programs like PRIDE developed and utilized. With the completion of PRIDE, we have launched PRIDE Reloaded, which is introduced on Slide 9. PRIDE Reloaded marks the next step in our continuous improvement philosophy. As shown on the left chart, we are targeting $135 million of EBITDA improvements by 2016. For example, 12 specific initiatives, including gas supply improvements, lowered delivered coal costs, increased dispatch resulting from lower start costs and expenses and improved IMA, represents 90% of the EBITDA lift in 2014. The chart on the right shows our balance sheet efficiency target of $165 million by 2016. Across the organization, we continue to look for opportunities to optimize our cash flow through efficiencies to further enhance our financial flexibility. Slide 10 provides an overview of Homefield Energy, IPH's retail business in Illinois. Illinois is a retail choice state divided into 2 markets: ComEd, which is PJM; and Ameren Illinois, which is MISO. Homefield Energy has a 30% market share in the Ameren Illinois territory. Homefield Energy's primary customers are commercial and industrial accounts, as well as residential customers, which are served through Municipal Aggregation. This portfolio of retail customers is primarily located around our wholesale generation fleet, which provides an efficient aftermarket because it matches our generation with offsetting retail load. While our retail load is back to physical generation, we do carry volumetric risk into the day ahead in realtime markets. However, potential swings in demand that occur due to weather events are taken into account when we set the price charged to customers, and therefore, those swings are expected to balance out over time. Hank will now cover our commercial activity.

Slide 12 provides an update on our hedging activity for our power generation and fuel supply. We continue to utilize busbar sales and FTRs to mitigate basis risk and to maximize the effectiveness of our hedges in the Coal segment. As previously discussed, when we hedged INDY Hub, we pair INDY Hub hedges with either FTRs or busbar swaps to create matched hedges. This strategy insulates us from changes in basis that otherwise could render our hedges ineffective. As part of our strategy, we also keep a portion of the fleet open to market prices. For our open positions, we realize the LMP for the fleet and are not exposed to basis risk. We took advantage of firming energy prices in late 2013 and early this year to increase our hedge level for the Coal segment in 2014 to 51% of our expected generation volume. Most of the energy price uplift we have observed in the natural gas market and the MISO energy market is concentrated in the front end of the curve with relatively good price uplift occurring in the forward markets for Q4 of 2014 and beyond. We do not believe the forward power markets reflect the value of energy in MISO in the longer term, and we have only slightly increased our 2015 hedge percentage to 10% of projected 2015 Coal segment production. Hedges for our Gas segment in 2014 also increased since late last year as we took advantage of expanding spark spreads at Independence and Moss Landing. Hedge volumes increased slightly for the Gas segment in 2015 to 15% from 5%. Hedge levels at IPH are 78% of expected generation volume in 2014 and 47% in 2015. Retail and wholesale contracts account for approximately 45% and 16% of the total projected IPH production in 2014 and '15, respectively, and the remainder of the IPH hedge volumes are attributable to financial hedges. We have purchased and fixed the price on approximately 95% of our projected 2014 coal volume requirements for the Coal segment and IPH. For 2015, we have procured approximately 7.5 million tons for the Coal segment and 6 million tons for IPH. This represents 68% and 44% of our projected annual volume requirements, respectively, with 14% and 22% of that volume priced. Our rail transport contract price is fixed for both the Coal segment and IPH for the next several years. Slide 13 shows the Coal segment's gen-weighted on-peak LMP for 2012 and 2013, as well as the realized year-to-date and projected balance of year LMP for 2014. The gen-weighted price assigns a weighting to the relevant LMP on a plant-by-plant basis based on nameplate capacity. As can be seen on the chart on the left, realized LMPs have been rising year-on-year for the Coal segment since 2012. We expect energy prices to continue to improve as net plant retirements reduce generation capacity in 2015 and 2016 in MISO and the region becomes more dependent on natural gas power generation. In addition, we expect the substantial draw on natural gas inventory this winter will result in continued energy price volatility through the balance of the year. Moving to the right side of the slide, we expect the MISO capacity market to tighten as plants retire due to MATS compliance requirements. Federal MATS legislation requires compliance by April 2015. However, states may grant a 1-year extension to the federal deadline. The timeline for investing environmental retrofits is extremely tight. If a unit decided today to invest in environmental controls to be MATS compliant, that unit would be hard-pressed to secure the permits, designs, contractors and equipment necessary to have controls in place for April 2016. We believe the timeline for new-build capacity is even tighter within a yet-to-be-announced new-build capacity, likely requiring 3 to 5 years to come online. The vertical demand curve construct of the MISO capacity market does not provide a signal to invest in retrofits or new generation until it's too late. The most recent capacity auction included $1.05 per megawatt day, which is significantly below a level that would provide any meaningful support to new generation investment. As a result of these dynamics, we expect the MISO market to tighten and reserve margins to fall well below MISO's 14.8% targeted reserve margin by 2016. Finally, as we discussed in the past, we have significant upside leverage to improving capacity prices at a $2 per KW-month uplift in capacity price, increases EBITDA by about $130 million on an uncontracted fleet. Slide 14 shows January 2014 natural gas and power prices related to Independence and Ontelaunee. Our Independence plant is ideally situated to capitalize on inexpensive natural gas from the Marcellus Shale. The plant is located upstream of significant natural gas supply delivery constraints while operating in a power market where higher-priced natural gas downstream of these constraints is setting power prices. And Independence continues to benefit from widening spark spreads as a result. As can be seen on the chart, the average fuel cost at Dominion South, which is broadly indicative of Marcellus Shale prices, was $4.47 per MMBtu in January. Assuming a 7,000 heat rate, this equates to an average on-peak spark spread of $114 per megawatt hour for the month. The Ontelaunee plant is also benefiting from expanding spark spreads this winter. The same calculations for Ontelaunee incorporating a Tetco M3 fuel price yield an average on-peak spark spread of $27 per megawatt hour in January 2014. Slide 15 reflects daily 2013 gen-weighted basis for the Coal segment and the IPH portfolio, excluding the impact of any hedges. The basis between INDY Hub prices and LMPs is dependent upon a number of variables and is subject to meaningful fluctuations on a short-term basis. The new basis adds a percentage to the INDY Hub price rather than as a fixed dollar per megawatt hour value may be a more appropriate estimate of basis when forecasting LMP in a volatile market environment such as the one we are experiencing in 2014. The chart on the left shows the hourly 2013 gen-weighted basis versus INDY Hub for the Coal segment portfolio, and the chart on the right presents the same analysis for IPH. Both fleets experienced a wide range of daily basis outcomes in 2013, with the average basis to INDY Hub being 15% to 20% for the Coal segment and 10% to 15% for IPH. Said another way, excluding the effect of any hedges, the average realized LMP in 2013 for the Coal segment was between 80% and 85% of INDY Hub and the average realized LMP for the IPH fleet was between 85% and 90% of INDY Hub. Slide 16 shows the constrained flowgates impacting the Coal segment. The constrained flowgates on the adjacent table were identified as having the greatest impact on congestion, affecting the Coal segment from the period November 30, 2011, through November 30, 2012. Many of these constraints have been addressed or will be addressed by projects already scheduled as part of MTEP '13. The scheduled in-service dates shown are the estimated dates the identified projects will be in service. The Mt. Vernon project, which addressed a number of the identified constraints listed in the table, was completed in June 2013. Another previously identified flowgate, which was forecasted to be a constraint in 2017 as a result of the Illinois River Project, has been incorporated into the MTEP process, thereby relieving any need for Dynegy to take on this project and will be complete in 2015. The cost for projects included in MTEP '13 and any future MTEP projects will be socialized among all MISO market participants. Dynergy will not directly contribute capital to complete these projects. The constraints identified as having the most impact on congestion affecting the Dynegy fleet, that are not addressed by MTEP projects in the near term, are the Baldwin transformer upgrade and the reconductoring of both the Sparta-Tilden and Mascoutah to Turkey Hill transmission lines. The construction cost for these projects is approximately $15 million to $20 million, which Dynegy intends to fund in 2014. We expect in-service dates for components of this project as early as November 2015 with completion of the final components in 2016. I would like to now pass over to Clint for our financial review.

Thank you, Hank. The company's year-end financial summary is outlined on Slide 18. And as you can see, Dynegy finished the year meeting all of its financial targets and continued to strengthen the financial profile of the company. For the year, consolidated adjusted EBITDA totaled $227 million, which includes $12 million in adjusted EBITDA for IPH in December. Excluding the IPH segment, Dynegy generated $215 million in adjusted EBITDA, which was in line with the full year consolidated guidance range. Contributing to this result were the strong performance from the Gas segment, which finished the year with $302 million in adjusted EBITDA, $7 million higher than the top end of its segment range, primarily as a result of stronger-than-expected spark spreads, which led to higher run times and, therefore, higher gross margin. As expected, full year Coal segment results were relatively weak with segment adjusted EBITDA totaling negative $4 million, primarily as a result of hedge correlation issues in the first half of the year. Free cash flow during 2013, excluding the impact of IPH, totaled $222 million as the $168 million positive cash inflow from the second quarter refinancing, together with a $21 million reduction in working capital, more than offset $86 million in cash interest payments during the year and $96 million in CapEx. With the better-than-expected results at the Gas segment and lower-than-forecasted CapEx, free cash flow for the year exceeded the top end of the guidance range. I would note that this free cash flow result does not include the benefit of a net $42 million inflow of previously posted cash collateral since our original guidance excluded collateral movements. However, it is notable as it is, together with a $95 million net decrease in outstanding letters of credit, contributed to a $137 million reduction in DI's outstanding collateral during 2013. As a result of the company's financial performance and continued progress on balance sheet efficiency, Dynegy Inc. finished the year with $946 million in total liquidity, up from $881 million at the end of the third quarter and up from $421 million at the end of 2012. Additionally, total liquidity at IPH stood at $215 million at year-end 2013, of which $190 million is located at the Genco subsidiary. As Bob mentioned earlier, we're initiating 2014 guidance today with a consolidated adjusted EBITDA range of $300 million to $350 million and a consolidated free cash flow range of $10 million to $60 million. These consolidated results reflect our expectations for the Coal, Gas and IPH segments taken together, based on commodity prices and hedge positions as of February 10 of this year. I will go into more detail about our assumptions and expectations for 2014 in a few moments, but needless to say, we are pleased with how the company finished 2013 and are optimistic for 2014, considering what we had seen to date. As outlined on Slide 19, Dynegy's adjusted EBITDA totaled $63 million for the fourth quarter compared to negative $42 million for the fourth quarter of 2012 as results for both the Coal and Gas segments were stronger period-over-period. At the Coal segment, adjusted EBITDA improved by $27 million as the segment generated more volumes at higher dark spreads compared to 2012. Average around-the-clock LMP prices during the quarter rose by $3.79 per megawatt hour. And this, together with higher prices on hedge generation, led to a $13 million improvement in gross margin. At the same time, coal commodity costs fell by $6 million as we were able to lock in more favorable pricing during 2012 for 2013 generation after the CSAPR Rules were stayed. As Bob spoke about earlier, the Coal fleet experienced a number of unplanned outages during the fourth quarter of 2013. However, despite that, generation was actually up compared to the fourth quarter of 2012 when our Baldwin facility had an extended planned outage to tie in the last of the facilities back in control systems. Compared to last year, generation volumes were up 770,000 megawatt hours, translating into a $5 million uplift in gross margin. Adjusted EBITDA for the Gas segment totaled $67 million during the fourth quarter, a $69 million improvement over the same period in 2012 as stronger spark spreads, higher run times, better capacity prices and lower cost led to improved results. Unlike the fourth quarter of 2012, there were no major outages negatively impacting generation levels and no legacy commercial settlements impacting gross margin. Higher pricing in generation levels, particularly at Independence and Moss Landing, drove a $15-million improvement in energy margin, while capacity revenues, primarily at Ontelaunee, rose by $6 million. This, together with the $6 million decline in O&M expense and a $40 million reduction in negative commercial settlements, resulted in a significant quarter-over-quarter improvement in segment adjusted EBITDA. Our new IPH segment generated $12 million in adjusted EBITDA in December as the business benefited from strong LMP prices during the month. For the full year 2013, Dynegy's adjusted EBITDA totaled $227 million versus $57 million in 2012 as the strong performance by the Gas segment and the addition of the IPH segment more than offset weakness in the Coal segment. Adjusted EBITDA for the Gas segment totaled $302 million, a $180 million improvement over 2012 as the absence of legacy commercial settlements and a $13-million reduction in O&M expense benefited results. Adjusted EBITDA for the Coal segment fell from $20 million in 2012 to negative $4 million in 2013, primarily as a result of the breakdown in hedge correlations experienced in the first half of the year, which negatively impacted results by $24 million. Moving to Slide 20. Dynegy streamlined its capital structure in 2013 and more than doubled its available liquidity through the addition of a new $475 million parent-level revolver, the release of previously restricted cash as part of the second quarter refinancing and the continued focus on optimizing the company's working capital and collateral needs. As a result, total DI liquidity at year end reached $946 million, including $628 million in unrestricted cash. While we have made significant progress on becoming more capital efficient, we continue to find opportunities to improve, most recently, around our emissions credit inventory program. Historically, Dynegy purchased California carbon credits and RGGI credits for our northeast plants anywhere from 1 to 3 years in advance to ensure availability of those positions to support our future generation. While this is a prudent commercial strategy, it was somewhat inefficient financially as it tied up a significant amount of capital for an extended period of time without generating any incremental return. In our view, a better approach is to contractually secure these credits in advance, as we have in the past, but structure the transactions so that we pay for them when we need them. When the corresponding generation takes place and the associated gross margin is available, to pay for the compliance and hedging costs. As such, we monetized $17 million of our inventory during the fourth quarter and expect to do more in 2014. But more importantly, we anticipate using this type of approach going forward to secure new credits and, potentially, FTRs for future generation while being able to reallocate capital previously used for this purpose to other parts of the business. At year-end 2013, total liquidity within the ring-fenced IPH family totaled $215 million and total debt, which is nonrecourse to DI, stood at $825 million. While not available currently, Genco, in addition to its existing cash balances, may receive an additional payment from Ameren in 2016 related to the sale of 3 natural gas plants that Ameren previously purchased from Genco under legacy put option arrangement. If you recall, Genco received $138 million in cash from Ameren in exchange for 3 natural gas assets with the condition that if Ameren subsequently sold those assets for a higher price, the after tax net sales proceeds in excess of $138 million would be paid to Genco. The assets were, in fact, recently sold and, based on initial indications, would lead to an additional $16 million payment. However, I would note that this amount is subject to various contingencies and could be reduced in the future. Turning to Slide 21. Dynegy is initiating its 2014 guidance this morning with a range of $300 million to $350 million for consolidated adjusted EBITDA and a range of $10 million to $60 million for consolidated free cash flow. These guidance ranges are based on the number of assumptions. However, the ones that I would highlight include the following. First, forecasted results are based on commodity curves and hedge position as of February 10, 2014, and include realized results through that date. The Nymex natural gas price used in our guidance was $4.58 per MMBtu and the around-the-clock LMP price for the CoalCo fleet was assumed to be $30.27 per megawatt hour or $4.80 per megawatt hour higher than in 2013. At IPH, the average around-the-clock LMP for 2014 was assumed to be $32.50 per megawatt hour. These LMP assumptions incorporate a more dynamic estimate of basis consistent with the analysis Hank walked through earlier. For our forecast, we assume that the gen-weighted around-the-clock average Coal segment LMP was approximately 78% of the INDY Hub price and that the gen-weighted around-the-clock average IPH LMP was roughly 84% of the INDY Hub price. You'll notice that the discount to INDY Hub for both the Coal and IPH segments are higher than what Hank noted earlier. However, that's due to higher than normal bases so far this year, given the high prices and volatility that we've seen. Otherwise, the balance of your estimates are in line with the discounts mentioned earlier. For our new IPH business, segment-level adjusted EBITDA, before corporate G&A allocations, is assumed to be $75 million. After interest expense and maintenance and environmental CapEx, IPH's segment free cash flow before allocated G&A is assumed to be negative $25 million. On a consolidated basis, corporate G&A expenses are forecasted at $100 million and will be allocated roughly 57% to DI and 43% to IPH based on a number of factors, including expected levels of generation throughout the year. A portion of consolidated operating expenses, approximately $50 million, are for operations support and insurance and will be allocated similarly to G&A between DI and IPH. This O&M allocation is already incorporated into the segment-adjusted EBITDA and free cash flow assumptions for IPH. Total CapEx, which includes both maintenance and environmental spend, is forecasted at $160 million. However, I would note that this does not include any transmission investments that may be made this year as those would be treated as independent investment decisions and considered along with other capital allocation alternatives. And finally, consolidated gross margin and cost structure of the company includes the impact of synergy and PRIDE initiatives targeted for this year. While these are some of the major assumptions going into our forecast, it's important to step back and understand the key drivers behind the year-over-year change in adjusted EBITDA, the most important of which are outlined on Slide 22. As we have discussed in the past, contract revenue will decline in 2014 as the new tolling agreement in Moss Landing 6 and 7 is at a lower rate than the previous contract that expired at the end of 2013, and the long-term capacity contract at Independence is set to expire this October. Additionally, the delivered cost of coal to our CoalCo fleet is expected to decline as higher rates under the rail agreement signed in 2012 more than offset lower coal commodity costs in 2014. While these items put downward pressure on forecasted results, the addition of IPH and the impact of our 2014 PRIDE initiatives contribute meaningfully to 2014 performance. These factors, together with the significant uplift we've seen in LMP prices at our Coal plants and spark spreads at our Gas plants, result in a meaningful year-over-year improvement in forecasted results. With that, I'll turn the call back over to you, Bob.

Thank you, Clint. Our high-level objectives for 2014 are included on Slide 24 and were developed in conjunction with our annual strategic planning exercise. We've identified 3 strategic priority areas for 2014. These 3 areas are: continuous improvement, driving best-in-class performance; customer focus, which includes an outwardly driven focus on priorities that ultimately translate into improved earnings; and capital allocation, making investments and capital allocation decisions that provide the best risk-adjusted rates of return for our shareholders. At this point, Shirley, I'd like to open up the session for Q&A.

[Operator Instructions] And our first question comes from Jon Cohen with ISI Group.

I know we're not talking about 2015, but can you just give us an order of magnitude of what the roll-off at Independence and the roll-off of the Moss Landing 1 and 2 contracts is going to do year-over-year?

Jon, I'm not sure really how to couch that. I think we've spoken on it before about the fact that the Independence contract is well above market contract that's been in place for quite a while. I think one of the things to keep in mind that while that contract is rolling off, there are a number of factors that we anticipate offsetting a portion of that, maybe up to half of that. And those types of things include -- there are some gas transport agreements that'll be rolling off in '15 as well. That will provide some cost relief there. We've also seen some uplift in Rest of State capacity prices that'll also provide some level of offset. So I think it's fair to say that the contract is a very valuable contract, too. So that'll be rolling off. But approximately -- I would say roughly half of that should be offset by other factors that we see at the plant. But as far as actual dollars, I'm not sure that I can speak to that at this point.

Okay. And then just one other question on the upcoming voluntary capacity auction. I know there's been some disagreements about what the rate load forecast and reliability requirements is among the LMPs and others. Are you hopeful that this auction is going to clear higher than the prior auction? And if not, when should we expect to see an uplift in the auction price? And maybe just one other thing. I don't know if you could talk a little bit about how Zone 4 operates specifically, the level of imports into Zone 4 and what the total reliability requirement in Zone 4 is and whether or not Dynegy can be subject to any sort of market power offer mitigation issues.

Jon, for the upcoming auction, and currently we're, I would say, cautiously optimistic that'll clear better than last year. I think when you look at the MISO capacity profile for the whole territory, as well as Zone 4, you have a near-term issue where we think that Zone 4 could potentially clear at a different level than the other zones. So there's a potential opportunity that it may bind there and clear higher. Longer term, and what the analysis that MISO puts out, continues to suggest whether it's the one that was done at the beginning of January or the end of January, suggest that the amount of resources are below the marginal requirements. So we expect longer term going up to 2016 and beyond, that your reserve margins are stressing and the capacity prices across all of them should increase. But I think for the near term, Zone 4 is the possibility of the difference year-over-year is the amount of capacity imports coming into Zone 4. Where in the prior year, it was roughly 6,500 megawatts of import capability, this year, it's down to little over 3,000 megawatts of import capability. How that all plays out in the auction process is to be seen, but it certainly requires more resources within Zone 4. And to your other question around market power and anything of that nature, we do not have market power nor are there any special rules applying to us for the auction.

The next question comes from Matt Farwell with Imperial Capital.

I was just wondering if you could give us little bit more color about the Moss Landing contracts. You talked about Independence, but can you just give us an idea of what we should be expecting going forward with Moss Landing?

Well, for Moss Landing, you've got the -- it's essentially 2 contracts, one for '14 and '15 and the other for '16. The one for 2016 is still under -- still requires that PUC approval. We are anticipating that this year. And for '14 and '15, they are in place. When you look at the profile all over the 3 years, the way that I generally think about it, where those plants would've been on a merchant basis versus contracted, it was roughly a $90 million EBITDA improvement over that 3-year period. And I would say when you look at '14, '15 and '16, each year gets progressively more valuable. I think that's a level of detail I can provide at this time on that.

Okay. And then just generally speaking, the environmental controls at some of the IPH plants are not uniform. Some may not have scrubbers. Some of your legacy plants may not have scrubbers. Could you just help us understand how these plants will obtain MATS compliance, given sort of the nonuniform profile of environmental controls?

Well, I would say for both fleets in the Coal segment and IPH, they will all comply with MATS. They have the necessary equipment to comply and using different ways of actually getting there. The only thing that I would say that has some impact for MATS is the Joppa facility has undersized ESPs. And there'll be points in time in which they have to take D rates in order to do some maintenance to ensure that we continue to comply with the particulate removal component of MATS. But other than that, there is no additional mechanical investment that needs to be made to comply with MATS for either fleet.

Okay. Then I guess last question is could you comment on some of the news coming out about utilities divesting merchant power assets? Are those assets of interest to Dynegy?

Generally speaking, when -- over the past couple of years, we continue to monitor the marketplace and look for portfolios that would potentially be a good fit with ours. And one thing that we certainly have highlighted with the acquisition of the Ameren facilities is the infrastructure that Dynegy has and how you can leverage that to reduce your cost. And acquiring 4,000 megawatts like we did on the IPH portfolio and having nearly $100 million of synergies, and I would say when it's all said and done, when we improve operating rates and the like, we'll be above that level. It's quite beneficial. So we'll continue to look at markets that make sense for us and make decisions based upon whether the investment provides the right return profile. But I would generally say that PJM is an attractive marketplace for us. We said that before. And we'll continue to evaluate opportunities in the PJM marketplace.

The next question comes from Gregg Orrill with Barclays.

I think you touched on this a little bit in your opening remarks, just around the plant performance early in the year around the weather-related events and how that -- I think you came back to it in the assumptions around the IPH, Coal organizations around the tracking base test. And I'm just interested in any additional thought you had on -- that you're willing to share on the performance for those plants early in the year and what it meant for guidance?

Sure, Gregg. And this is the kind of the way that I think about it is that this really offers an opportunity for us. I mean, as far as January and February are concerned, while plants had some outages, we had a few days that we lost on the Gas segment, but the IMA for the Gas segment was roughly 97% to 99% between January and February. On the Coal segment, I'd say both fleets were averaging IMA between 87% and 90% or so. But when we think about guidance, what we've included in that guidance range is the recent historical performance of plants. And specifically to the IPH portfolio, when you think about unavailability, it's had some significant periods of unavailability. Once we get those plants to the level that they're capable of operating, and I think about where you've got operating rates of 90% or so, and we have examples of the plants for 2013 and prior to history to that, at the end, had outage factors in the 20%s and 30%. And what we factored into our guidance is the fact that we've got a ways to go to get to the reliability that we're striving to get towards. Once those plants reach that, I would say -- if our plants were to reach that this year, I would say we have upside to the guidance. What we have factored into the guidance so is the historical operating performance, because these things take time to work through. So when we think about PRIDE Reloaded, a key target for us is to get these operating rates to the level that we know that they're capable of doing, and that will be a priority area for us in 2014.

Our next question comes from Michael Lapides with Goldman Sachs.

Subbing in for Neil Mehta today, I hope you don't mind. 1 or 2 kind of high-level questions. Can you talk a little bit about California? And given there are a lot of units in California over the next 5 years due to the cooling water intake rules likely facing either the major capital requirements or retirement, how you think about the opportunities for repowering in California?

Thanks, Michael. I would say California is a difficult market. It rewards new-build, and it punishes existing facilities. As you know, Morro Bay, we shut down partly because it's a once-through cooling plant. It was not getting contracts with the facility. The way we think about the opportunity going forward is finding a way to meet what the customer is looking for. In our discussions with PGE and others out there, they're looking for preferred technologies out there that not only are renewable but kind of a next generation of renewables. So we think about putting together our portfolio in California where we've got Morro Bay and we're having discussions with a firm that has some novel technology around ocean wave generation that basically conserve its baseload and scale up pretty large without requiring a large footprint. We think about our Oakland Facility, that is right in the center of a load pocket that they need for reliability. We think of Moss 6 and 7 as having fast ramp capability. And we think also for Morro Bay or Moss Landing, there's opportunities out there with things like battery storage. So what our approach to California as we think about it is combining all of those attributes into an offering for the utilities to consider. And our view is that, that would be pretty competitive, and we're working to try to develop those opportunities around our existing portfolio. We're not looking to necessarily expand in California in any other way, but rather just utilize the inherent attributes of the existing sites.

Got it. You've talked a little bit -- and earlier on the call, somebody asked a question about M&A potential in markets you find attractive, and you reiterated your view about PJM. Just curious about some of the other competitive markets. When you look around the country about where you think you'd like to add scale and where the markets where you already have a presence and you don't view the market, either structure or the market supply and demand dynamics, as attractive. And I'm kind of thinking you've got kind of a small position in both New England and New York and no position in ERCOT. Just your views on those 3 big markets?

I think the other thing -- I mean, I think they are all beyond markets that we're interested in. But what I would add to that is that it would have to be a portfolio of assets. We're not an efficient buyer of single assets. And the reason you haven't seen us buy into Texas to this point in time and -- it's not because we haven't looked. But when you go to try to look at an individual combined cycle unit or 2 of them, that requires virtually all of our balance sheet capacity. And at the values that they're trading, the return profile for us isn't necessarily compelling. But if there's an opportunity where we can leverage our infrastructure, get synergies out of portfolio in any one of those markets, we'd certainly would absolutely consider that. But it has to be something where we bring something unique to the table, similar to what we did with Ameren when we brought a very scalable platform. And we would have to -- any investment in M&A for us really requires that benefit so we can leverage our infrastructure here, which we still believe is capable of efficiently managing a portfolio of over 20,000 megawatts.

And then final last question, and this maybe one for Clint. How are you thinking -- if other alternatives for use of capital, as you start to generate more free cash flow, meaning if M&A doesn't emerge or market pricing for asset doesn't prove attractive enough for you, how are you thinking about your credit metrics over the next year or so and the ability to deploy cash in other manners, whether it's debt reduction, whether it's -- as capital allocation to shareholders or other alternatives?

Yes, Michael. I think the way that we tend to think about it is, first, determining what our assets, cash is and how much capital we have to deploy. And then looking at it really just from a risk-adjusted return perspective and looking at alternatives, whether it's external growth initiatives or whether it's internal organic initiatives, like the transmission investments that Hank spoke about earlier or looking at potential returns to shareholders or giving capital back to lenders. I think all of those, in my mind, compete for capital. And we look at it on a risk-adjusted return basis. I would say from a balance sheet leverage standpoint, I think we're comfortable with where we stand right now. That capital structure is relatively inexpensive and long term in nature, and so I would tend to think that kind of the other alternatives for capital allocation would probably be more attractive.

And, Michael, one thing I would add to that as well is that as when you think about our guidance and our cash flow profile, Hank shared on Page 13 the LMP prices, the volatility's been in the front end of the curve. We think with natural gas supplies dropping down, possibly below a Tcf that's going into the summer, that we're going to see more volatility, generating more cash. And I would say that we're very comfortable with our debt profile. A lot of -- every investment that we think about, we're comparing it to providing some sort of return to shareholders. So that's something that's very high on our list to -- well, continue to be very much on the top of our list to monitor and evaluate against other opportunities for deploying capital.

Do you have target credit metrics, whether it's an EBITDA-to-interest or debt-to-EBITDA metric that you -- that's kind of your long-term target?

We don't have really specific targets, Michael. We obviously have financial ratios in our revolver that we're mindful of. But I think the type of credit metrics that we have and that we've had over the last year are probably consistent with where we want to stay. But I wouldn't say that we would manage to specific credit metrics.

Yes. I would say that we want to keep a stable credit profile. We're not interested in getting any downgrades or negative commentary from any of the rating agencies. So we'll maintain a consistent credit profile, which will look a lot like today.

Our next question comes from Greg Reiss with Millennium Partners.

I just wanted to get a little bit more clarity on the new PRIDE initiative. When I look at the $135 million that you guys are laying out through '16, how should I think about the $95 million of IPH synergies you've laid out?

Well, the $95 million of IPH synergies are -- every action needed to be taken has been taken, so it's separate from PRIDE Reloaded. So anything going forward in PRIDE Reloaded -- like there will be improvements, further improvements on the IPH fleet that are built into those targets going forward, but it's completely separate from the $95 million. The $95 million is focused on very near-term actions to take, eliminating the corporate level support that Ameren was providing, rightsizing the employee base, given the duplication of functions. And also with the new rail contract that was negotiated, it started on January 1, all of these things have been addressed, done, implemented. So these synergies will now just flow across over the course of the year. Anything beyond that in PRIDE Reloaded is additive, although I would say, as Clint mentioned in his guidance assumptions, that the benefits that we forecasted for this year from PRIDE Reloaded are largely included in the guidance. There are some excess for things that are -- maybe it won't reach the level of success that you originally target or some unexpected things. But for the most part, the targets for '14 are built into the guidance.

Got you. So when I look at kind of the income statement for 2013 for IPH, I guess the $95 million will be reflected in that O&M level. So it's already been reduced by that $95 million.

It will be in '14. Yes, in '14, not '13.

Got you, got you. But in the $75 million of guidance for IPH includes that $95 million?

That's right.

But understand also that, that $95 million is shared between DI and IPH. It's not 100% of that $95 million accrues to IPH.

Yes. As Clint highlighted on his guidance slide, that was at 40s...

About 43%.

43% of G&A is allocated across to IPH, as well as some shared operating expenses. So when you think about the overall $95 million from synergies, call it roughly more than -- slightly -- call it slightly more than half is down at the IPH level, but you still have 40-some percent that's sitting up at the DI level. What used to be charge to the Coal segment and to the Gas segment is now being allocated down to IPH. So not all of the benefit is sitting in the IPH bucket. It's -- some of it is at the parent level.

Next question comes from Julien Dumoulin-Smith with UBS.

So first quick question. Could you talk a little bit more on the acquisition front, just in terms of your desire for assets and mix between Coal and Gas and Coal characteristics, if you will? And what would an ideal portfolio look like in your mind, outside of it being more of a corporate portfolio rather than single asset?

So, Julien, I think about how we're structured today, what works particularly well with having the efficient combined cycle plants that -- and also the scrubbed coal plants, if you will, I mean, what we're seeing -- what we saw in 2012 and early 2013 in the low gas environment are combined cycle units ran as baseload and generated a lot of free cash flow. What we're seeing in 2014 with the volatility is the value of the Coal plants that we have. So I think as we go forward, I'd like a market that -- certainly, capacity markets are great. We'd like to have assets in a functioning capacity market, but that, also, it has the mix of assets that continue to support our thesis on natural gas recovery, which tends to be Coal plants, and then also provide you the -- not only the shaping but also the kind of the built-in hedge if gas prices, in fact, start declining, which is the combined cycle units. So for us, a fleet that has a mix of both is particularly valuable. And I would say that also applies to the extent that you have to raise capital for an acquisition that has both. That then also addresses the issue where your Coal plants don't get fully valued in your equity and your Gas plants do. That doesn't necessarily then hurt you as -- in the case where you'd be going after an all combined cycle fleet, then you could potentially be diluting your upside on your -- from your Coal fleet, and the cost of the capital is much higher as well. So I think something that looks like us is pretty close to ideal, being the scrubbed Coal plants that run and combined cycle plants that really do well in a weak gas environment.

And then secondly, this may be a little preemptive but -- and you may be discussing it in the Analyst Day, but how do you think about the future of your Coal assets, given IPH and the DI assets in Illinois and the fact that you're projecting negative cash flow? I mean, you talked about a tightening in 2016. You talked about the viability of the market structure. How about your own assets now that you've kind of looked at the portfolio, integrated it? Is there a timeline for evaluating whether assets are up to snuff or anything like that?

Well, then I would say that our Coal segment is positive cash flow now. In the IPH segment, you get the operating characteristics of the plants to where they can be, and that's cash flow positive. We targeted the IPH fleet to be free cash flow accretive in '15. We've got a decent shot of that happening in 2014, depending on plant operating rates and what happens later in the year. But we continue to see the retirements, market tightening, capacity market building in MISO. So we remain bullish on the outlook for the Coal plants in Illinois.

Got you. But is that -- perhaps if I can dig a little bit deeper. Free cash flow accretive to all assets or the portfolio in aggregate? If you appreciate the nuance.

Yes. Well, I think on a segment-level basis, before the allocation of G&A corporate overhead is what we're referring to. Looking at our Coal assets on a segment basis, it's the segment EBITDA covering the CapEx. And I think as Bob alluded to, for '14, our expectation is that the Coal segment would be able to cover its CapEx. IPH, as we noted in our assumptions around guidance, is not able to, to the tune of about $25 million. But again, depending on how the plants operate and depending on what LMP prices do throughout the year, that negative free cash flow could certainly be minimized or potentially reach breakeven, depending on factors.

Right. And that includes covering the interest payments at Genco.

That's right.

Got you. And then lastly, could you talk a little bit more on the basis subject quickly. What are you thinking for basis just in terms of a dollar-per-megawatt-hour price for this year? And then going forward, what the impact is of the transmission changes that you talked about in aggregate?

Yes. And I'll -- Julien, I'll take the first part of your question. As I mentioned in my comments, we've moved to a more -- or as both Hank and I mentioned, we've moved to a more dynamic estimate of basis and then based on more of a percentage of INDY Hub. Now translated into dollars, what that means for our forecast this year, taking into consideration what we've already seen in January and February, which has been very volatile, the total for the year is about $8.44. That's what our implied discount translates into on a dollar basis. But again, we've seen a lot of volatility much higher than that. Base is higher than that in January and February. So the way to think about it is that taking January and the first part of February into account is raising our dollar basis to, call it, $8.44. But after February 10, for the balance of the year, our dollar estimate for basis on our Coal fleet, Coal segment is roughly in line with what we actually experienced in 2013. So really, our estimate for '14 is being driven up by what we've seen in January and February in the market. So I think for IPH, same type of dynamic where, on a dollar basis, kind of what we've implied from our discounting to INDY Hub, comes out to about right under $7. But again, that's driven by what we saw in January and February. For the period after February 10, for the rest of the year, on a dollar basis, that equates into about $4.70 basis, again, kind of similar to what the fleets experienced last year but rounded up for what we've seen year-to-date.

And then going forward, if you will, for '14?

I would simply point to kind of the percentage approach that we're now taking. Kind of depending on what INDY Hub is, I would then discount that in accordance with the information that Hank went through a little bit earlier.

Then our last question comes from Angie Storozynski with Macquarie.

I wanted to go back to the year-to-date performance. Obviously, there's -- we've seen a lot of volatility in the bases. But how much of the guidance for 2004 (sic) [2014] has baked in for the year-to-date performance, especially for your Gas plants?

Well, Angie, I would say that if you look at the results for January and February, the uplift that we have seen has been largely realized. And you look at the -- again, the chart that Hank showed on LMP prices on Page 13, you see it's all in the front end at this point in time. So a lot of it is largely baked in.

I know. But I'm just trying to -- I mean, being that we're going to be using your '14 guidance to project the future earnings power of the combined company, I don't want to extrapolate from once in a 10 years' type of winter. So is this a material boost to your '14 guidance? Are we talking about $50 million up, or is this largely immaterial in the sense of the entire annual guidance?

Well, no. I mean, I'd say that January and February are strong months. I couldn't tell you the percentage off the top of my head.

Angie, the -- one other thing that I would just mention here. When we look at the expected gross margin for the combined company for the year, during the -- call it, the first 6 weeks of the year, we realized, call it, roughly 15% of what we would expect to realize for the rest of the year. So I would say that it's been a pretty good first 6 weeks, certainly an uplift over what we've experienced in the past. But I don't know if that's helpful or not.

Okay. Secondly, now that IPH is included in your numbers and a portion of the hedges are driven by retail, how should we think about the margin over at the INDY Hub prices that we should embed in those portion of hedges that is retail-driven? Meaning, is -- I mean, are we basically looking at typical margins that we observed in Illinois for C&I clients or is this -- so that -- being that some of those hedges probably were entered into the past? Are these margins substantial? Are we talking more than $1 per megawatt hour, or can you give us any sense of how should we actually project the pricing of hedges?

Angie, there's wholesale contracts that exist, as well as the retail. So for the retail ones, typically what we're seeing is anywhere ranging from $1 to $3 a megawatt hour. So it's kind of your typical Illinois-type margins. There are a couple of very long-term wholesale contracts that are in the IPH numbers as well that are basically fairly large capacity payments with the right to draw the energy. That extends in some cases through the 2030 timeframe. But for the retail piece, it's roughly a $1 to $3 margin market.

Okay. And then I know that you're working on improvements in the dispatch of both the Coal and Gas bonds. But what strikes me is that every quarter, even during those peak seasons, it seems like there are number of plants that have planned and unplanned outages. What surprises me is that I would not actually expect that planned outage for any plant to happen during the winter or the summer period. And yet, it seemed like you did guys have a number of those. And is this just as you are improving performance of your portfolio, and as such, I shouldn't actually assume that those outages will be planned for the next peak seasons, or is this just the beauty of the portfolio that some assets need to be maintained during peak usage times?

Well, Angie, I would say that we don't do any planned outages at a peak demand period. But if you have an outage that shows up, they're typically going to be the shoulder quarters. Maybe it spills into a June or maybe it spilled into -- in October, November. But for December, January, February, you're not going to have planned outages. If you've got -- those will tend to be unplanned outage. And those tend to be, if it's a Coal unit, it'll tend to be a problem with the boiler. If it's a gas unit, it tends to be something around startups. But our drive is reliability, and part of the PRIDE Reloaded is to do everything we can on driving reliability. And each plant has its unique characteristics that we're working on to improve. But there wouldn't -- there won't be any planned outages at peak times.

Okay. And my last question is about the MISO capacity market. So I do see, obviously, MISO reports indicating deficiency of capacity versus projected peak demand. But then every single load-serving entity within MISO claims that they are fully, basically, covered as far as their demand needs. So why is the discrepancy in your opinion? Where is the discrepancy?

I would say the transparency of the market is not particularly good. The surveys go through and do an assessment on demand and do an assessment on resources. And you're right, it shows a shortfall. And we're out there trying to do origination with customers, and we're having some success with that. But we'll see at the auction time as soon as -- as to what happens at this -- at the next auction. But I would just say that the market does not have a lot of clarity in it. It's not very transparent, if you will. At this point, I'd like to thank everybody for dialing in. Thanks, Shirley.

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