HOUSTON Jun 25, 2015 (Thomson StreetEvents) -- Edited Transcript of Dynegy Inc corporate analyst meeting</ Thursday, June 25, 2015 at 12:00:00pm GMT TEXT version of Transcript ================================================================================ Corporate Participants ================================================================================ * Bob Flexon Dynegy Inc. - President & CEO * Carolyn Burke Dynegy Inc. - EVP, Business Operations & Systems * Julius Cox Dynegy Inc. - CAO * Jeff Coyle Dynegy Inc. - VP Operations Support * Sheree Petrone Dynegy Inc. - EVP, Retail * Hank Jones Dynegy Inc. - Chief Commercial Officer * Clint Freeland Dynegy Inc. - CFO * Andy Smith Dynegy Inc. - Managing Director, IR ================================================================================ Conference Call Participants ================================================================================ * Julien Dumoulin-Smith - Analyst * Mark Fisher AF Capital - Analyst * Eric Flown Goldman Sachs - Analyst * Greg Gordon Evercore ISI - Analyst * Michael Lapides Goldman Sachs - Analyst * Stacey Nemeroff Bloomberg Intelligence - Analyst * Felix Carmen Visium Asset Management - Analyst * Jeff Cramer Morgan Stanley - Analyst * Mitchell Moss Lord Abbett - Analyst * Angie Storozynski Macquarie - Analyst * William Frohnhoefer BTIG - Analyst * Evan Kramer Silver Point - Analyst ================================================================================ Presentation -------------------------------------------------------------------------------- Bob Flexon, Dynegy Inc. - President & CEO [1] -------------------------------------------------------------------------------- Good morning, everybody. Thanks to everyone for coming. And safety is such a core value at Dynegy, I don't want folks to look at this room and think this is how we typically run our business. I think we put every tripping hazard we possibly could -- a lot of congested chairs, monitors, stage, so just please be careful as you try to navigate the room here. Over the course of the day you're going to hear from the management team and I'll kick it off and then following me will be Carolyn Burke, immediately to my left, who will cover the integration, PRIDE and synergies. Julius Cox, to my right, will do the regulatory overview. I'm zigzagging here because when we had rehearsals watching Julius and Jeff Coyle get by each other on the stage, it wasn't pretty, so we had to separate. So Jeff Coyle is going to be doing the operation support after Julius. Then we're going to take a break. I'm sorry, right before the break we'll do a quick Q&A. And in the Q&A what we are going to attempt to do is focus it on the topics that were covered primarily by Carolyn, Julius and Jeff. And then after the break we'll come back with Sheree covering retail, Hank on commercial, Clint on financial. I'll do a wrap-up and then we'll have a Q&A session that will cover any topics that you like to go through. So with that will get into the presentation. Our first Investor Day meeting was held on January 13 of 2013 and Dynegy at the time was a very different Company. We think today that our generation portfolio since that time has increased by 16,000 megawatts. PJM is now our largest market rather than MISO and our combined cycle fleet has more than doubled in size and we now have the largest -- we are now the largest merchant combined cycle fleet in PJM and ISO-New England. EBITDA in 2013 was $227 million and back then we identified a path at our meeting on how we could reach $500 million in EBITDA. The levers at the time that we saw that we needed to achieve that level was executing around PRIDE, the expected impact that we felt was forthcoming around retirements and the impact that would have on energy prices and capacity prices, reaching a settlement in California for the [tolling] agreement that had previously been canceled and probably most leveraging was how can we effectively allocate capital through the balance sheet capacity that we had that was a result of our restructuring. So now in 2015 after we've executed in these areas, EBITDA is expected to be more than 300% higher than what it was in 2013. That more than doubles the $500 million target that we had put out there on an annualized basis. And during that same time period, our share count has only increased by 28% or 40% on a fully diluted basis. At our 2013 meeting, we also identified we needed to develop and start a retail business. We were starting from Ground Zero on retail. Today our retail business serves over 22 million megawatt hours of load per year and it provides a very cost-effective hedging for a portion of our wholesale fleet while adding incremental earnings and EBITDA. So Dynegy today is no longer dependent on just two assets. Our portfolio today offers several advantages versus what we had in 2013. We've increased the combined cycle portfolio from 4900 megawatts to over 9900 megawatts. Our capacity revenues in 2016 will represent approximately 32% of our gross margin versus 12% in 2014. And we have a lower cost generation fleet as a result of unequaled access to low-cost fuel and then the efficiencies that we've developed through our PRIDE program. So while much has changed since January of 2013, our investment thesis at Dynegy remains the same. We're an attractive value-oriented investment opportunity with a very compelling risk return profile. The portfolio has multiple avenues for upside from having high-quality assets in markets where supply is contracting, market reforms are now taking place and improved capacity values and higher energy prices are now being realized. And PRIDE keeps us focused on improving the value of our fleet. Access to lower-cost fuels due to our advantaged locational position of the gas fleet to the Marcellus and Utica reserves and the lower delivered coal costs that we have for our coal fleet provides a layer of protection from downside risk that enables our portfolio to generate very positive cash flows in virtually any natural gas price environment. The expected free cash flow generation from the portfolio over the next three years is expected to be about $2 billion and allows us to meet our obligations while having access to substantial discretionary capital that can be allocated to what we view as the best risk-adjusted return opportunities. This includes returning capital to shareholders. In 2013, the anticipated market catalyst that we saw forthcoming was the structural changes taking place to generation supply leading to tightening reserve margins. We are now in that cycle where coal-based generation and to a lesser extent nuclear assets are being replaced by natural gas fire generation and renewable generation, so 2015 really brings a very substantial change in generation mix. 2015 will have the most coal retirement ever and that's primarily in the markets in which Dynegy participates. It will be the most gas burn for power generation that's driven across all markets and this will be the year that will have the most renewable build ever and that's primarily concentrated in the Southwest and the West which is away from Dynegy's core portfolio. So these changes have created a more volatile and a less stable power market and we anticipated this as we approached 2015. We deployed our balance sheet capacity to reshape our portfolio by expanding into markets where these fundamental changes were occurring. We increased our gas-fired generation assets in markets that have well defined capacity markets leading to a more balanced revenue mix from the portfolio. So while 2015 will likely be the watershed year of change, there's a second wave of retirements that we see coming. With the declining reserve margins, ISO-New England and PJM have both recognized the need for what we refer to as quality megawatts. These are megawatts that can be relied upon for reliability to meet the most challenging events and conditions. These performance incentive reforms in these two markets reward the overachievers and it penalizes the underachievers. So older assets, or assets that do not have certainty of fuel supply, or long ramping time, intermittent assets and demand response will be facing increasing pressure to meet the same standards as traditional fossil fire generation and nuclear generation or be forced to exit the market. They'll either need to exit the market due to lack of compensation or to avoid the risk of the penalties. So this is going to put additional pressure on reserve margins benefiting generators like Dynegy that have a portfolio that can meet the stricter standards. We can capitalize on this through better plan availability that Jeff will be covering later this morning and through lower-cost expansions and uprates, which both Hank and I will be discussing. So as I touched on earlier, our portfolio today has far greater an unequaled relative presence in PJM and ISO-New England, arguably the most attractive markets for an IPP that's giving the market fundamentals and reforms that are underway. Our expansion into these markets in advance of the market reforms is very well-timed. In addition as Hank will cover, MISO capacity remains tight and potentially may lead to capacity prices clearing at administrative caps similar to what ISO-New England experienced. As compared to January of 2013, the demand for Dynegy capacity in MISO has significantly increased as has the prices the counterparties are willing to pay. If the overall system in MISO experiences a shortfall during the annual capacity auction, the administrative cap for MISO is about $250 per megawatt day. As I highlighted on the prior slide, Dynegy has a differential exposure versus its two closest peers to higher capacity revenues via our relative position in PGM and ISO-New England while having no ERCOT exposure and minimal California exposure. And with approximately one-third of our gross margin in 2016 coming from capacity revenues this allows us to carry a more open energy position, which is consistent with our view that power price volatility should lead to higher energy revenues. So when we originally launched PRIDE in 2011, we had a goal that was twofold. First, develop the internal skill sets to continuously innovate and improve the efficiency of the Company and drive higher cash flows, which is different from cost-cutting programs that others pursue. The second goal was to design and build a very scalable platform that could quickly absorb and serve as a platform for an expanding portfolio. By the end of 2015, the cumulative compilation of PRIDE to EBITDA will reach $218 million. With minimal investment required, PRIDE projects have very compelling and very outsized returns and the doubling of our portfolio just two months ago offers areas of opportunities that we'll be announcing new targets for later this year. Carolyn will show how leveraging our scale has led to significant reductions in our overhead costs per megawatt hour generated. The integration of the Duke and ECP acquisitions is substantially complete. In just a couple of months, we absorbed two portfolios simultaneously doubling the size of the Company while continuously identifying synergies and capturing additional savings through PRIDE. We had near flawless execution that we demonstrated our ability to quickly integrate and realize the benefit from these two transformative acquisitions. Carolyn will provide a more in-depth review of the integration status, the benefits achieved and the statistics that illustrate our accomplishments by our integration teams. The glory part of M&A, which is the deal, isn't particularly unique from one company to another. Anyone can pretty much buy assets. What separates companies in an M&A process is the speed of the integration process and what happens after the deals close. At Dynegy we follow a very structured approach to find synergy and PRIDE opportunities. We established a project in change management office to drive speed, to drive consistency and efficiency of the integration and we utilize dedicated, trained internal resources to perform our PRIDE projects and to perform the integration rather than handing the keys over to consultants. PRIDE and our synergy projects are continuously tracked; they're audited and the responsibilities are assigned to the highest levels in the Company, so the very individuals that are here with me today. Reliability is a key focal point of our PRIDE efforts offering substantial upside through increased plan availability. Our units have been benchmarked against similar units and we target top decile operating performance when compared to peer units. The Zimmer coal plant that we acquired from Duke has the most potential gains that we can make through improved reliability. Our portfolio has locational advantages for fuel sourcing. The gas fleet with its access to Marcellus and Utica gas procures a substantial portion of its natural gas requirements at locations that have a negative basis to Henry Hub which results in higher spark spreads. The coal portfolio also benefits from access to lower-cost fuel utilizing PRB and Illinois basin coal as well as the favorable coal transportation contracts that we're able to negotiate with the rail companies as a result of our scale. The Environmental Compliance rules recently, or about to be connected, that are the most impactful to the Company's assets and environmental spend are the 316(b) Rule which deals with water intake, effluent limitation guidelines, which addresses wastewater streams and coal combustion residuals rule for the treatment of handling of coal ash and ash impoundments. Jeff will provide the detailed discussion on the impact of these rules and our compliance plans. The expenditures associated with these rules will occur over many years and into the next decade. Over the next three years, the expenditures are not significant and overall very manageable given the Company's outlook for free cash flow generation. The portfolio's access to lower-cost fuels, greater exposure to capacity markets, cost and reliability benefits driven through PRIDE and manageable CapEx spend results in positive free cash flow generation in a wide range of commodity environments. In the current commodity environment, our combined cycle units in PJM and ISO-New England run as baseload units with high-capacity factors similar to our baseload coal unit. Within PJM as gas prices climb from current levels, any reduction in the capacity factors of our combined cycle units will be offset by higher margins from our coal fleet. And to the extent there are natural gas price declines, the spark spreads of the gas units in PJM would likely expand offsetting lost margin from the coal units. The PJM portfolio as constructed imbeds a natural hedge providing protection in a falling commodity environment. The MISO coal fleet as in prior years continues to be the major beneficiary of rising natural gas prices. As we assess our future capital allocation alternatives and plans, we do so with confidence of maintaining a strong balance sheet and liquidity position that is within our targeted metrics with ample liquidity to meet our daily operating needs. Clint will address our balance sheet management later in the presentation. So as we evaluate capital allocation alternatives there are a series of low cost and high return expansions in uprates in our core markets. Dynegy is GE's largest LTSA customer and we've developed a very effective partnering relationship with GE that has created several of these uprate opportunities in our combined cycle fleet. And within MISO, we are just days away from bringing 235 megawatts of combustion turbines online at a cost of less than $5 per KW. This is comprised of five mothballed peaking units that were part of the IPH acquisition and they will be able to sell not only into the MISO market but also to two other adjacent markets. In PJM, New York-ISO, and ISO-New England, several of our existing combined cycle units are set for uprates adding an additional 450 megawatts at a fraction of new build costs and in significantly less time. In some instances, the capital that's associated with these uprates is deferred beyond the completion of the uprate. We recently acquired the development rights to Burke Hollow. It's a 750 megawatt fully permitted site that's on the same plot of land as our Ontelaunee plant. No decision has been made at this time to initiate construction. Our immediate objective was to obtain the option as we assess the opportunity. Having an existing 550 megawatt unit on the same site brings economies of scale that no other competitor would have thus presenting a very attractive investment opportunity for the Company to consider. Much of the Company's success since 2013 can be attributed to the prudent allocation of capital and over the next three years we estimate that as much as $2 billion of cash will be available for allocation. Safety, environmental and reliability investments remain a first order of allocation. Our PRIDE investment opportunities have very compelling IRRs and short payback periods and require limited capital investment. The vast majority of the unallocated cash will be used for share repurchases or discretionary investments to the extent that the discretionary investments have a return profile that exceeds that of share repurchases on a risk-adjusted basis. Debt levels will continuously be managed to the targeted metrics that Clint will be covering and once we get through the summer season and the upcoming capacity auctions in PJM, we'll be better positioned to formally announce and initiate the first phase of our capital allocation plans. While Dynegy's equity price has dramatically outperformed its two closest peers since the 2013 investor meeting, the outlook remains equally bullish. So when taking into consideration the markets that each of the companies have exposure to combined with the quality and the quantity of the assets in these markets that Dynegy's valuation by comparison is inexpensive. The free cash flow yield which potentially reaches the midteens provides a solid footing for further share price appreciation over the forecast period. And Dynegy has become much more than a natural gas play and to illustrate this on January 17, 2013, the [Valve 13] natural gas strip was $3.67 per million BTU. Today the settled [Valve] 15 natural gas strip is $2.86 per million BTU, which is 22% lower. Our equity performance over this same timeframe increased approximately 66% where the share price of our other two closest peer companies Calpine and NRG have essentially achieved no price appreciation. Our portfolio additions in attractive markets with locational advantage, generation asset retirements, capacity market reforms, our self-improvement efforts through PRIDE and synergy capture are not dependent on natural gas to drive value. Earnings in free cash flow growth is being realized from a series of different catalysts many of which have now been triggered. And without new generation in the intermediate term to offset the retirements that are now occurring within our core markets, the fundamentals for the Company are very promising. Our coal generation fleet continues to provide substantial upside in a rising natural gas market where our gas fleet with its locational advantages provides substantial cash flows in the current natural gas environment. So as we go into the various presentations today, the theme of a transforming marketplace coupled with the regulatory environment will be highlighted several times. Our portfolio has been shaped and positioned to be a beneficiary of these changes. PRIDE continues on and later this year we will launch the next chapter of PRIDE with new targets and with upwards of $2 billion of cash expected to be available for allocation over the next three years, we look to build on our track record of creating shareholder value by prudently allocating capital to the best risk-adjusted return opportunities. Now I will hand it over to Carolyn who will talk about the integration of synergies and PRIDE. -------------------------------------------------------------------------------- Carolyn Burke, Dynegy Inc. - EVP, Business Operations & Systems [2] -------------------------------------------------------------------------------- Good morning, everybody. My name is Carolyn Burke. I am currently the Executive Vice President for Business Operations and Systems. Most recently though I ran the integration for the EquiPower and Duke assets and that along with PRIDE and the synergies is what I will be speaking to you about today. Now I know you'd like me to all just jump straight to the synergy numbers but please let me take you through our approach to the integrations. It is because of the approach that we employed with the integration that we feel so confident in our ability to capture the synergies that we're announcing today. The primary reason many M&A deals do not deliver longer-term value is because they fail to integrate the hard assets, the systems and the plants with the soft assets, the people and the process in a timely manner. They fail to leverage the timing, momentum and excitement around a transaction, i.e., they just take too darn long. And when it takes too long, it adds cost, it adds complexity and it adds uncertainty to an organization. A couple of points on this slide that were particularly leveraging to us. Speed over elegance. We always planned for a December 1 Duke and a January 1 EquiPower go live date. While aggressive, we were ready on those dates and the fact that we had more time simply meant that we were more ready. We accelerated certain system conversions and shortened the transition service agreement with Duke from six months to three months. This not only decreased the amount of cost by 50% to less than $3 million, but it accelerated the change in management that you need to achieve the synergies. And it let us focus on exactly that, achieving synergies. Dedicated IMO teams; our first priority was maintaining our core business. We did not want the integration to distract us from running our legacy plans and commercializing the assets with the same level of excellence that we did before the integration. As such, we set up dedicated teams to focus on the integration and backfilled where necessary. IT strategy; we actually defined our IT strategy during the due diligence period, i.e., before we even announced the acquisition in August. A key philosophy for us at Dynegy is one team and one goal and as an integration team, we added one system. We live by this religiously. We will not maintain more than two systems for any significant period of time. It's costly, it prevents the changed management that you need and it does not allow for a scalable platform for future growth. As of July 1, we will go down to just two duplicative systems and they will both be eliminated by year end. Slide 23 describe some of the activities and the goals of the integration team. We had one primary goal, no disruption to the business. And on day one, our traders traded, our plants operated, the accountants started closing the books on Q1, and communications between the ISOs, the plants and our commercial floor flowed smoothly. Yet behind the scenes, we had converted over 118 system applications, with just five applications not fully converted. And again on July 1, we'll be down to two. On the employee front, we had on-boarded and trained nearly 1000 employees onto our platform and onto our systems and today we have a retention rate of 99.4% and we intend to maintain that. On the commercial side, we moved over 3000 trades and 150 wholesale contracts yet day one was like any other day and the last three months have been just like that. Given this sort of seamless cut over, transition costs tend to be low and in this case again, less than $3 million. This discipline has also served us very well with our PRIDE program, which has reaped significant benefits to the bottom line. On slide 24, we show the trends in O&M and G&A costs in 2010, the original baseline year for our PRIDE program through an average of our planning horizon, 2016 to 2018. From 2010 through 2013, we focused on streamlining our G&A costs through a variety of PRIDE initiatives. We reduced our real estate footprint; we decreased our burden costs and we maintained a flat organizational structure. We've carried each one of these initiatives through each acquisition and our overall G&A per megawatt hours has been reduced by 70%. That same vigilance on cost effectiveness is applied to our O&M costs. Here too despite the swings in outage costs, the trend is favorable over the 2010 to the forecasted planning period. Similar to G&A spend, the initial O&M reductions were focused on reducing non-value added spend through a variety of PRIDE programs. We consolidated regional offices, we reduced plant insurance premiums and property taxes, we renegotiated certain water contracts and we looked at our outage spend very carefully. In 2014, we began to see the favorable impact of the increased scale with the IPH acquisition and in addition to that, the successful renewal of our coal co union contract. In 2016 and beyond with the ECP and the Duke acquisitions, our portfolio and cost structure is benefiting from a less cost intensive gas fleet balancing out our coal fleet and maintaining a relatively flat O&M cost structure. It is important to note that you do not see a 70% decrease in O&M like you do in the G&A. Rather we leverage our PRIDE savings to offset other investments and other increases in our plants to maintain the reliability and safety and that's why you see a much more moderate 10% reduction over the same time period. So now I can move on to synergies. We are very pleased to announce that we have increased our EBITDA synergies today to $130 million. At the time of the announcement, we had identified $40 million in EBITDA improvements and had assumed the elimination of all Duke corporate G&A. The $90 million increase is driven primarily by the improved rail pricing at three of our coal plants as well as the associated gross margin from those plants thanks to the improved dispatch due to lower fuel costs. Additionally, we have included approximately $20 million in gross margin from various uprates at our newly acquired PJM and New England-ISO CCGT plant and another $10 million in gross margin due to the improved reliability at the acquired fleet. Given the ongoing PRIDE program, we wanted to clarify how we're managing synergies versus PRIDE. First, we're tracking synergies very similar to PRIDE, fixed cash costs, gross margin improvements and one-time improvements in the balance sheet. Synergies are improvements that will be realized during the time period of 2015 through 2018 and have been identified as of today, June 25. Now we will of course continue to look for improvements in the newly combined businesses but any project that's identified after today will be labeled PRIDE. And we will report progress on both our synergy targets and our PRIDE targets at the next earnings call. We will also announce PRIDE targets at the third-quarter earnings call for 2016. There are a number of projects that we have identified through the synergy program that have not yet been fully vetted or quantified at this point. Refined coal is a perfect example. We will begin testing refined coal at the Ohio plants over the coming months. In 2014, refined coal brought $14 million of improved EBITDA to the IPH fleet and an additional $4 million to the coal co fleet, again in 2014. In 2015, we're actually forecasting an incremental $10 million of improvement to the coal co plant. If testing proves out at the Ohio plants, we would announce that improvement through the PRIDE program. Other projects under study include changing the fuel mix at our Ohio plants and reviewing the barge transportation rates. Finally with the exception of the LTSAs, we have yet to complete our review of the combined fleets' purchasing power but we do know this, our annual non-labor O&M and CapEx spend is nearly $650 million. If we target just 3% of that in savings, which is significantly below the benchmark for most M&A transactions, we would be looking at another $20 million of improvement. So more to come at the third quarter earnings call on that. Slide 26 provides a breakdown of the breadth and depth of the synergies. And again, I will just highlight a few things here. In the by source category, the fuel and fuel transport includes the coal contracts and the improved dispatch that I spoke to earlier but it also includes improved gas contracts and pipeline optimization projects. These savings are largely due to our increased purchasing power and taking advantage of the proximity of our plant sites. Procurement synergies are savings from renegotiating better rates at our plant insurance providers and our LTSA provider. With the LTSA renegotiations, Marty Daley and his team have done an absolutely fantastic job in securing major savings for our newly acquired CCGT fleet. There's a $9 million benefit in maintenance CapEx and O&M. There's another $10 million in improved gross margin from the increased dispatch thanks to the lower cost structure and there's approximately $25 million in reduced future outage spend. Additionally, collateral outstanding to our LTSA provider was reduced by $120 million, previously announced as part of our balance sheet target. Finally, by leveraging the combined fleet in the LTSA renegotiation, we are on track with 260 megawatts of uprate projects at our newly acquired New England-ISO and PJM gas plants. Hank will speak to those later in the presentation. But please note any uprates associated with our legacy Dynegy plant will be part of the PRIDE program. They are not part of the synergy program. The by status category, what does this mean? The 75% of our synergies are secured. That means all actions have been taken and there is little to no risk that we will be able to achieve these synergies. We've signed new contracts, we've implemented any changes in our operating procedures and we've received any necessary external or internal approvals. The remaining 25% of the synergies we consider identified and in process. We have quantified the synergy and we've initiated steps to achieve it but the synergy itself is dependent on forward pricing and the final favorable impact will not be known until sometime in the future; for instance, the value of the uprates in the PJM performance capacity market. Cost to achieve these synergies are reasonable. In 2015, approximately half of the $31 million is related to severance and the other half is related to uprate CapEx. The balance in 2016 forward is all driven by uprate CapEx. The majority of our synergies requires little to no investment. So in closing, I just want to reiterate that we have executed on a very complex transaction, closing two transactions back-to-back with no disruption to the business. We have leveraged our platform with the additional scale and we have confidence that it can manage the forecasted growth in both our retail and our wholesale businesses. We are on target for $130 million in EBITDA and $375 million in balance sheet synergies, significantly beating our earlier expectations and we will continue to carry on the work in our synergy program well into 2016 and beyond with our PRIDE program. With that I'm going to turn it over to Mr. Julius Cox and he'll cover regulatory policy. -------------------------------------------------------------------------------- Julius Cox, Dynegy Inc. - CAO [3] -------------------------------------------------------------------------------- Thank you, Carolyn. Good morning. I'm Julius Cox, Dynegy's Chief Administrative Officer. Our approach to regulatory remains consistent. We want to focus our efforts on helping to make appropriate environmental policies and advocating for constructive market design. We accomplish this at the federal, state and local levels through advocacy, outreach, education and by forming partnerships with our peers and other key stakeholders. As this slide shows, there are a number of examples of how our regulatory efforts have had a positive impact on our business. We've been active in both Illinois and Ohio in terms of advocating against out-of-market subsidies. In Illinois, we took on the responsibility to educate consumers and policymakers through our PR campaign and by putting boots on the ground at the state capital. In April, Bob and our regulatory team met with state legislators. We wanted to provide a dissenting view to Exelon's request for out-of-market subsidies, which we believe would have a destructive impact on the market. We've also proposed broader solutions for the state of Illinois, which I will cover a bit later. In Ohio, we provided a drastically different and a much more bullish view of their competitive market. We believe these efforts help to create an extremely high approval bar for AEP and FE to overcome in their request for out-of-market PPAs. In MISO, we're continuing to bring attention to the need for market reform. Our team has continued to educate stakeholders on a number of key issues including the fact that electricity rates charged by regulated utilities include capacity costs of nearly $300 per megawatt day. We've also worked to educate MISO and state officials with respect to the fact that while Zone 4 separated in the most recent MISO auction, the results are very much consistent with competitive markets, including those in PJM. Here's another way to think about how an effective regulatory function should set its priorities. We protect the interest of our business and investors by making an impact on markets and policy matters that drive costs and revenues. Previously we've talked about our efforts and the potential impact at Dynegy with respect to pending regulations, market design changes and supply/demand fundamentals. As this slide shows, a number of things that were previously unknown are now known. For example, we're now in the compliance stage for both MATS and CCR and market design changes in PJM and ISO-New England have now occurred. We want to ensure that competitive markets are preserved and that environmental policies don't place an inappropriate burden on our business. Let's talk about MATS for a moment. The only story with MATS is that there really is no story. As the chart on the right illustrates, the amount of megawatts that are set to retire this year nearly equal the total number of megawatts retired in the previous three years combined. Additionally, plants located in PJM that are set to retire have not participated in any recent forward capacity auctions. Now the most recent information we have about MATS is that the Supreme Court ruling could be issued as early as this morning. But our belief is that these plants have retired or soon will retire and we don't believe that the Supreme Court ruling will have a significant impact on this. The real story with respect to plant retirements is that beyond MATS, as Hank will talk about a little bit later, is the second wave of retirements that will be driven by things like the risk of not performing in PJM under CP. For Dynegy, our reliable and well-run fleet is set to capture the opportunities MATS has created with respect to tightening energy and capacity markets. We've included ELG here since the rule is not yet finalized. This serves as another illustration of where our repertory efforts are focused in helping to develop appropriate policies. We're actively engaged in helping to shape the final ELG rule by providing comments to the US EPA and our advocacy efforts through our trade associations. With ELG expected to be finalized in September, we will soon move to the compliance stage. In a moment Jeff will provide an update on our spend profile and as he will show, we believe the assumptions we've made remain consistent with prior expectations. As currently proposed, the Clean Power Plan contains a number of points that we believe to be unworkable. For example, improving coal plant heat rates by 6% is not technically feasible. Additionally, the plan would likely result in several unintended consequences with respect to state emission limits. As this illustration tries to show, neighboring states like New Jersey and Pennsylvania have vastly different emission rates. Even when you have plants on other side of the state line, they are separated by less than 10 miles. Now that would actually benefit our Ontelaunee and Liberty plants that reside in Pennsylvania because they would be in a position to export power into PJM. But the result of the current proposed emission limits will likely result in shifting generation and jobs from one state to another without having much of an impact on lowering CO2 emissions. With our reshaped portfolio -- while the inconsistencies in the plan fail to be addressed, we are positioning Dynegy to manage any risk. With our reshaped portfolio, a much larger percentage of our fleet is in areas like Pennsylvania and New England where we believe the emission limits can be more reasonably met. Additionally, our strategy for beneficial reuse of CCR serves as a program to offset CO2 emissions. And we continue to work within key states to identify appropriate compliance pathways. As Bob covered in his earlier remarks, with 90% of our generation in PJM, ISO-New England, New York and MISO, Dynegy is the IPP best positioned in the highest value markets. For regulatory, this heat map serves as a roadmap for how and where we should focus our time and resources. The map helps to highlight gaps that we should be working to address in the markets where we operate. Along those lines the next few slides talk about market design in the two markets we have our largest concentration of megawatts, that's PJM and MISO. As many anticipated a few weeks ago, FERC accepted Capacity Performance in PJM. Given our deep presence in PJM, it comes as no surprise that we were strong proponents of CP. To this end along with one of our peers, we jointly filed comments in support of CP. We also met with FERC's staff to discuss the proposal prior to its initial filing. Now there has been some concern about the impact the balancing factor would have on Capacity payments under CP. But even with a balancing factor of 85%, the default offer cap is still likely to be more than $270 per megawatt day. With our diverse and reliable portfolio in PJM, we're in a better position than any other IPP to capture the upside CP provides for reliable performance. Here's where the leverage of our PJM portfolio is realized under CP. As you can see in this example, under a forced outage scenario that lasts 8 hours, an owner with a single plant faces a penalty of nearly $16 million. That penalty then gets shared as a bonus by plants that are over performing. Under the same scenario if you have a portfolio of plants even with a plant that is underperforming, plants that are overperforming are in position to receive a bonus. In this example, the overperforming plants share in the bonus which helps to offset the penalty incurred by Plant A. Now there are countless scenarios under CP but the point here is that having more plants allows you to mitigate risk and provides more opportunities to be rewarded. It's also important to consider CP as a potential barrier to entry. Financing new build in PJM may be more difficult given the downside risk of not performing under CP. And with our fleet of 60 units across PJM, we have a diverse and reliable portfolio that will mitigate risk and allow us to capture additional opportunities for upside. Let's shift gears and talk about MISO. As you are likely aware, the MISO default offer cap link to PJMs RTO capacity price. For MISO, this is meant to represent the lost opportunity cost of not exporting capacity to PJM. As you can see on this slide, the starting point for MISO's 2016/2017 planning year reference point is the RTO clearing price in PJM's base residual auction. Now taking the current RTO clearing price for 2016/2017 and using last year's transmission cost of $19 per megawatt day, you get a reference price of about $80 and a default offer cap of about $100 per megawatt day. But a few points to be made here. First, either the incremental or the transition auction in PJM may clear above the BRA. And under the tariff, the MISO Market Monitor has the latitude to reassess the reference price under a variety of circumstances. Secondly, [as a net] increase we will request to make facility-based offers in excess of the cap and our commercial and regulatory teams are working to evaluate the exemption request process. Finally, as Hank will address in more detail, if reserved margins at MISO for the 2016, 2017 planning year continue to decrease and the system is short, the actual clearing price of next year's auction could result in CONE, or nearly $250 per megawatt day. We've been increasingly [commenting] to the market dynamics in MISO. Illinois is the lone wolf in terms of market participants. It is surrounded by vertically integrated utilities in the other 14 MISO states. And as I mentioned earlier, regulated utilities in MISO earn on average more than $300 per megawatt day for capacity that's baked into their rates. These utilities do not rely on the auction as an economic mechanism. Instead, utilities use the auction to balance load and demand, so they bid everything in at zero to ensure all megawatts clear the auction. In Zone 4 as this chart illustrates, we estimate our weighted average capacity price of less than $60 per megawatt day. But the real story here is this, if you take the clearing price of $150 per megawatt day and southern Illinois, as well as the $136 per megawatt day in northern Illinois PJM and contrast that against the $300 per megawatt day that vertically integrated utilities are receiving for capacity, that's a signal that competitive markets are actually resulting in lower prices for consumers. But it also highlights the inconsistency in the MISO market construct and we believe that this uneven playing field has to be addressed. Finally, despite the potential for reserve margin shortfalls, MISO's capacity market does not send us effective signals to incent new build. Given these factors in the longer term, the status quo market construct in Illinois needs to be improved. If Illinois wants to ensure that it has a [new] generation at reasonable and just rates for both consumers and suppliers, we believe there are number of options that should be considered. Illinois is caught in the middle between a regulated utility model and a competitive market model. The current hybrid market construct faces a number of challenges. Last week Bob spoke at MISO's annual meeting continuing to highlight these very same points and we will also outline options that should be considered. One such option would be for Illinois to move back to a fully regulated model. Obviously this is not our preferred option as we continue to believe that competitive markets are more efficient and deliver the lowest cost to consumers. But you can't ignore the challenges of the hybrid model and the increasing volatility it exposes consumers to. Ideally Illinois will move to a completely competitive market model and this could be accomplished in a couple different ways including by moving southern Illinois into PJM. This would allow all of MISO to be on a vertically integrated model while also putting the entire state of Illinois under the same market construct. Another Illinois only solution would be to create a Zone 4 capacity construct and while there are a number of things to consider with pursuing this path, it would serve to recognize the unique and competitive nature of Zone 4 as compared to others. Under either scenario we believe that preserving competitive markets reward the most effective suppliers and results in lower prices for consumers. And while we remain bullish about tightening capacity markets in Illinois, the status quo is not sustainable in the long run. If change doesn't occur, the result will likely be increased risk of further retirements which will only serve to create even more volatility for consumers. In closing, for Dynegy our regulatory rule is to advocate for constructive market design that supports competition. We protect the business by engaging key stakeholders in developing policies that result in appropriate environmental regulations. We focus our efforts on the markets where we operate like PJM and ISO-New England which provide for upside with their market design and in markets like MISO where we will continue to encourage taking the necessary steps to address any gaps. With that I will turn it over to Jeff Coyle to cover operations support. -------------------------------------------------------------------------------- Jeff Coyle, Dynegy Inc. - VP Operations Support [4] -------------------------------------------------------------------------------- Thank you, Julius. Good morning, everyone. I'm Jeff Coyle, Vice President of Operations Support. My team provides services to the generating fleets in the areas of safety, environmental compliance, marketing of CCRs, and reliability and today I would like to give you our status and our plans in these areas. Let me start with safety, which is our highest value at Dynegy. Dynegy has been on a track of improving performance in this area with an exception in last year when we went from top quartile performance down to average performance in our industry. This was unacceptable to us and we've invested significant effort to understand and to address the situation. Our safety incidents continue to be mostly sprains and strains and most occur when employees are performing routine tasks, ones they do regularly and repeatedly. We conclude that we do a pretty good job on the complex involved tasks that we do but sometimes we let our guard down on the day-to-day activities. In response, we focused on complacency awareness and injury prevention for our personnel in our plants. We've also addressed -- placed additional emphasis on summer preparation and winter preparation for safety in our plants. And as a result, we had no weather-related incidents in the past year and for the first time in our recollection, no injuries from slips on ice and snow. Another important initiative for us is obtaining voluntary or OSHA voluntary protection program status for our facilities. We presently have six sites with this certification, an additional six sites that have either made their application or in the process of application. We think this is important because it requires plans to have and to demonstrate an excellent program for safety and health that involves both management and employees. Only a small percentage of power plants have this accreditation and they typically obtain a lost workday incident rate less than 50% of industry averages. Today we're not yet achieving our goal of top decile safety performance but we do believe that we will get there with a consistent program of continuous improvement and proactive efforts. Let's turn to reliability. Reliability is also another key initiative for us. Our gas plants have performed very well in the area of reliability with historic equivalent availability performance in the upper 80s and lower 90s and end market availability in the mid to upper 90s. The units recently acquired from Duke and ECP also have a similar performance history. For this fleet, we're targeting equivalent availability to be above 90% and end market availability to be 98% for both of these fleets, or all of these fleets through the end of the decade and we'll continue to invest in the units to achieve this objective. Moving to coal, in 2014, coal segment performed a detailed benchmarking of their units against industry and determined that while some of the units also performed very well against their peers, there were some opportunities on specific units. As a general rule, 90% equivalent availability for coal-fired boilers constitutes top decile performance against their peers of similar size and type. As a fleet, the coal co units have performed in the mid-80s. IPH units have performed typically in the low 80s and legacy Duke fleet in the low 70s. Last year we looked and identified several high payback projects that we could advance into the year. IPH was in their first year as part of Dynegy became much of that opportunity. From our initial work on this fleet, we saw equivalent availability improve by 3.4% over prior year results and that translated to an improvement of more than $6 million for the remainder of the year. As we move into 2015, it's easy to see the boiler tube leaks on our coal-fired boilers remain our greatest opportunity area with losses here three times that of the next largest contributing factor. We calculate our opportunity costs for our legacy Dynegy and IPH fleets in 2014 was in the range of $44 million and of course this would move higher with the new plant additions that we've recently made. We are responding to this opportunity by working with the plants to perform a section-by-section review of each boiler to quantify the number, location and cause of the leaks that we've had. We will use this technical information along with our commercial and asset management teams to assure that we have our resources properly prioritized and have the work reflected in our budgets and our outage schedules. Additionally, our teams are exploring other timely repairs and operational changes to extend the life of equipment that will allow us to delay or negate near-term capital expenditures and the associated outages that go with them. Overall, we are targeting to get our coal-fired fleet to 90% equivalent availability by the end of this decade. Last year we also rolled out a fleet initiative for gas and coal to improve preventative maintenance activities. We started with our highest priority areas, which included safety, environmental compliance and critical equipment to assure we have right activities taking place in a timely manner. And when we talk about the critical equipment, those are the pieces that if there were a failure would constitute immediate production loss, either a forced outage or forced type of derate. We completed our first work in 2014 and in 2015 and years beyond, we just continue to drill down further into our other systems and make our preventative maintenance systems more robust. Now maybe this all sounds a little basic and in some ways it is but it does take the coordinated efforts of many to get this right. Moving to environmental compliance, certainly in years past our focus has been heavily weighted toward compliance with a myriad of federal and state air in emissions regulations. We've invested in plant equipment and made operational changes and we're in compliance with the existing major rules. This compliance extends to the plants that we recently acquired from Duke and ECP. Now our focus starts to turn to the three recent and pending rules: 316(b), ELG and CCR. The rules themselves, 316(b), also known as the water intake rule, is designed to protect aquatic organisms at plants that draw cooling water from lakes and rivers considered waters of the US. This rule was signed last April and requires compliance within two years after each plant's water discharge permit, known as the NPDS permit, is renewed. Effluent Limitation Guidelines, what we call the ELG rule, sets more stringent guidelines on power plant water discharges. This rule has not been signed yet though we expect signature to occur on or before September 30 of this year. And the Coal Combustion Residuals rule, what we call CCR, was signed last December and published in the Federal Register this past April. This rule regulates landfills and surface impoundments that contain combustion residuals and also defines the beneficial reuse criteria for these products. Let's dive a little deeper into each of the rules. 316(b); our view of this rule remains essentially the same as last year but there are some positive aspects that I'd like to point out. First, the majority of our fleet is already compliant. Our gas plants including our new acquisitions, utilize cooling towers and many take their makeup from municipal water sources which makes them exempt from the rule. For our gas plants that do draw from waters of the US, we'll need to perform some low-cost studies over the next few years but the draw rate and velocity of that water is so low that we don't anticipate any issues that will require mitigation. Additionally, our Moss Landing gas plant will be compliant with 316(b) as it will already comply with the more stringent California Once-Through Cooling rule. In total our view is that nine of our 35 plants will require some level of capital expenditure. These are the coal-fired plants without cooling towers located on lakes and rivers considered waters of the US. Last year at Investor Day, we estimated the cost of $50 million over a five-year period for this work. This year we're reflecting $60 million over a seven-year period with most of that spend occurring after 2019. The main change in our number is the addition of work at our Steward and Kincaid stations which were recently added to the portfolio. ELG; our view of this rule also remains essentially unchanged from last year. We believe the rule will issue with language similar to previous guidance provided by EPA. As a result of this, we also expect our compliance strategies to remain the same although we will have some additional work at our newly acquired plants. This rule applies to all plants but we do not anticipate mitigation will be necessary at any of the gas facilities. On the coal side, you'll see on the slide where we anticipate capital expenditures will be required. Most of the costs will be associated a conversion of bottom ash conveyor systems from wet to dry operation on units that are greater than 400 megawatts in size. We'll also have some costs for treatment of scrubber wastewater on the wet scrubber systems located on the Ohio facilities. In addition, we have a number of smaller capital projects expected to be $2 million or less per site that are shown as red crosshatch on the chart. Last year we were estimating $125 million over a five-year period for this work. This year we're estimating $290 million over an eight-year compliance period with most of that spend occurring between the years 2018 and 2023. Again the main difference is the work required at the acquired coal plants. The numbers in our budget exist today as engineering estimates and they are based on conservative assumptions. Once the rule is finalized, we'll begin to perform the detailed engineering and we'll refine our costs accordingly. CCR; the clock for this rule began running on April 17 when it was published in the Federal Register. The final language in the rule allows us to demonstrate compliance of our impoundments for groundwater, location and structural safety requirements. Any site that meets the requirements can continue to remain open and receive material. The slide on the screen shows the major milestones that are in front of us. 2015 starts off very busy as we initiate the key monitoring, record-keeping and reporting requirements. Our preparations are already well underway and we're on track to complete all of this required work. We're also now proceeding with analysis of structural integrity, groundwater and location restrictions that must be completed in years 2016 through 2018 respectively and we're also on schedule with this work. So what does this mean for Dynegy? We have 46 CCR sites spread across our different coal plants. Three of these are closed or otherwise maintained facilities and are exempt from the CCR rule. They require no additional action or spend. Eight are landfills, typically newer facilities with liners. They'll need to go through the testing that was discussed on the prior slide but we believe they are low risk and will likely remain in service until they are fully utilized and are closed according to their original schedule. 13 are inactive facilities. And we have some flexibility here around their closure. We will have a decision point in October where we can either elect to close some of these within three years to limit our exposure to future monitoring and maintenance requirements, or we can just take them through CCR analysis. And then finally, we have the 22 active surface impoundments that are receiving CCR products today. These plus any of the 13 inactive facilities will go through the CCR analysis. Again, any site that passes its testing can remain open and continue to receive material. If a site does not pass this testing, we have another decision point and can choose to either mitigate or proceed to close. At this time, we have not reflected any dollars in our budget to mitigate the issues. Without the analysis in hand, we simply can't reasonably estimate these costs. However, we may find that some mitigations are prudent and will allow the impoundments to stay open and defer the asset retirement obligations for closure to a later time. You can see we have a lot of work ahead of us and that's why we're are getting an early start on our testing. If we determine impoundments need to close, we have time to mitigate or make alternative arrangements for the CCRs without the detrimentally impacting plant operations. This next slide summarizes the key assumptions and points from the environmental section. Overall we're estimating approximately $108 million of spend between years 2016 and 2018 and approximately $600 million in spend between years 2019 and 2023. These numbers contain our capital spend plus our asset retirement obligations for closures of the landfills and surface impoundments. We think this contains conservative assumptions and we may be able to reduce these project costs as we perform the detailed engineering. We also believe the number of our impoundments will demonstrate compliance with the CCR rule and will be able to remain in service. And this of course will allow the associated ARO dollars to be shifted to a later time. Coal combustion byproducts; before the acquisitions, our legacy Dynegy and IPH fleets produced about 1.5 million tons of coal combustion residuals each year and we were recycling about 30% of that total. Last year we announced our plan to beneficially reuse 100% of our CCR production by year 2020. This benefits us in multiple ways but especially by reducing the future cost for landfill construction and maintenance. Our new acquisitions complement this strategy very well. Even though today's combined fleet produces 3.5 million tons of CCR annually, the group is now recycling 56% of that total production. That's mostly fly ash and gypsum today. In comparison you can see that the industry average is in the low to mid 40s. By realizing our goal and beneficially reusing that additional 44% on top of the 56% used already, we can avoid approximately $30 million per year in future landfill construction, operation and eventual closure costs. This year we expect to move at least 61% of our production and that represents 175,000 ton increase over last year and we'll keep stepping up from there as we develop additional avenues in the market. To do this we have recently developed a CCR marketing team and have charged them with improving our CCR utilization. We've also tasked this team with the development of new product opportunities. Last year I alluded to a potential product opportunity during my presentation and I'm happy to report back to you today that we've just signed an agreement with a third party to build a fly ash processing plant at our Duck Creek Station. We'll sell our ash to this vendor and they'll mill it to improve flow, strength and set time properties that are desired by the concrete industry. We believe this will help create a larger market demand and more movement of product into the marketplace. Construction is slated to begin later this year and be in service by the second quarter of next year. Within three years, the vendor has committed to take 80% of the fly ash generated by Duck Creek Station. This will be a first of a kind system in the Midwest and based on our experiences from this system, we may also move ash from some of our other nearby plants through this facility. Another expected benefit to this work is the carbon offset. We anticipate this milled product can replace up to 60% of Portland cement and concrete and since the cement manufacturing process itself creates significant CO2, use of milled fly ash can reduce overall CO2 emissions. In summary, our team is actively responding to the requirements of the new and pending CCR and water rules. We're developing plans for all of our plant sites and we are on track with our planning and execution of the work. We don't envision any of these rules will negatively impact the operation at any site. The expected spend is manageable and limited to the near-term. And finally, our CCR marketing team benefits Dynegy by requiring fewer future landfills to be constructed, maintained and eventually closed. With that, I will turn the podium back over to Bob. -------------------------------------------------------------------------------- Bob Flexon, Dynegy Inc. - President & CEO [5] -------------------------------------------------------------------------------- Thank you, Jeff. So what will do is we will spend about 15 minutes or so on Q&A that will follow it with a break. I would also say that available for questions, we have Catherine Callaway, our General Counsel; Mario Alonso, who heads up strategy and M&A who we're not going to let answer any questions; Dan Thompson, runs our coal operation and to my right we've got Dean Ellis who works with Julius on regulatory and Marty Daley, who does the gas operations. So with that, I open it to the audience here for questions on the first half of the presentations. ================================================================================ Questions and Answers -------------------------------------------------------------------------------- Julien Dumoulin-Smith, - Analyst [1] -------------------------------------------------------------------------------- Good morning. Julien (inaudible) at [UBS]. So first to touch on the capacity market development, I'd be curious, what are your expectations on the transition option. (inaudible) So I'd be curious what you expect for your portfolio, (inaudible) cleared, uncleared, etc.? And then on MISO if you could elaborate, what has enabled you to bid above the market level, if you could talk a little bit to the strategy (inaudible)? -------------------------------------------------------------------------------- Bob Flexon, Dynegy Inc. - President & CEO [2] -------------------------------------------------------------------------------- Sure. On the capacity performance piece for PJM, Hank will get into more of that in his discussion. I think the high level response that I'd give you on that is that we're doing an asset-by-asset review and where these things clear and the like will always depend on how people approach the auction and bidding behavior. For us we have to bid all of our units into the CP -- the auction in 2018/2019, I guess for the transitional, it's voluntary whether you do or whether you don't. We plan to certainly bid in the majority. There's certain units that have access to fuel issues, particularly around the peaking units. And in any bids that we make for the capacity auction in 2018/2019 would be certainly risk adjusted. We'd have to look at it from a standpoint of there are certain units that if they are going to clear, it is going to require either a level of investment or a risk premium in case it actually does clear. So a portion of our assets will be like that and if everybody takes a similar approach, then you would expect that you'd get some significant uplift in the market. If others are in there just as basically price takers and think we will play the odds and hopefully there's a shortage event and I don't get hit by it, then you would have a very different result in the auction. But if you have a shortage event that lasts eight hours and you fail to perform, that's roughly an $85 per megawatt day penalty. So call it 16 hours, you're at 170. So the risk penalties are very significant so our view is that we're going to take it very seriously on a risk adjusted approach on how we bid in assets and whether others do that or not, we'll see. For the transition auction again, a majority of our assets will be bit into it. Hank will talk maybe a little bit more about that when we come back to that later on in the final Q&A session to follow up on that. On MISO, as Julius highlighted that for next year the MISO limitation around the adjacent market tariff is $59 plus the transport to get the energy in there, which if you do the math it's roughly $78 or so a megawatt day, would be the reference price. You can go for unit specific exemptions, things like take Newton scrubber as an example that has a large CapEx spend coming its way, so you can build that into an exception request into the Market Monitor. And whether or not they approve it, it's up to them but we would look at each unit specifically as to its CapEx requirements, it's cash flow and we would make justification to the Market Monitor and they would have to decide I think within a certain period of time prior to the auction whether or not we get the exemption to bid above or not. Hank, is there anything you would add to that or Dean or Julius --? -------------------------------------------------------------------------------- Julien Dumoulin-Smith, - Analyst [3] -------------------------------------------------------------------------------- Maybe a quick comment to go with that. How much of your capacity (inaudible) tricky but could potentially clear the auction (inaudible)? -------------------------------------------------------------------------------- Bob Flexon, Dynegy Inc. - President & CEO [4] -------------------------------------------------------------------------------- Are you talking MISO? -------------------------------------------------------------------------------- Julien Dumoulin-Smith, - Analyst [5] -------------------------------------------------------------------------------- MISO, exactly. -------------------------------------------------------------------------------- Bob Flexon, Dynegy Inc. - President & CEO [6] -------------------------------------------------------------------------------- How much can potentially clear? -------------------------------------------------------------------------------- Julien Dumoulin-Smith, - Analyst [7] -------------------------------------------------------------------------------- Yes, exactly. In terms of what commitments again versus retail obligations, etc., how much --? -------------------------------------------------------------------------------- Bob Flexon, Dynegy Inc. - President & CEO [8] -------------------------------------------------------------------------------- So I guess the length that we have right now for the capacity is about 80% or so for next year. Is it 60%, 80%? -------------------------------------------------------------------------------- Unidentified Company Representative [9] -------------------------------------------------------------------------------- Yes, it's 60% to 80%. -------------------------------------------------------------------------------- Bob Flexon, Dynegy Inc. - President & CEO [10] -------------------------------------------------------------------------------- If you think about IPH, IPH will have about 60% of its capacity spoken for via retail. And then the DMG fleet will be -- the legacy Dynegy coal plants would be largely open. There are some bilaterals that have been done. IPH has some wholesale contracts but I think between the two fleets you are probably around 60% -- 50%, 60% (inaudible) an auction. You look at this year we failed to clear about 3000 megawatts in the auction out of 6400 megawatts. I'd assume it would be somewhere in the same neighborhood as that. -------------------------------------------------------------------------------- Mark Fisher, AF Capital - Analyst [11] -------------------------------------------------------------------------------- [Mark Fisher] with [AF] Capital. On the compliance side, the timeline that you are doing, does that dictate or is it similar at all to prior compliance deadlines where there are long lead times? In other words, is this something that your competitors are going to have to start thinking about for upcoming auctions? -------------------------------------------------------------------------------- Bob Flexon, Dynegy Inc. - President & CEO [12] -------------------------------------------------------------------------------- Are you talking on the -- not the environmental compliance --? -------------------------------------------------------------------------------- Mark Fisher, AF Capital - Analyst [13] -------------------------------------------------------------------------------- Yes, the three (multiple speakers) -- -------------------------------------------------------------------------------- Bob Flexon, Dynegy Inc. - President & CEO [14] -------------------------------------------------------------------------------- Oh, the environmental compliance. Yes, these are all dictated by statutory dates. -------------------------------------------------------------------------------- Mark Fisher, AF Capital - Analyst [15] -------------------------------------------------------------------------------- In terms of spending though, are these similar lead-times that you've seen before? -------------------------------------------------------------------------------- Bob Flexon, Dynegy Inc. - President & CEO [16] -------------------------------------------------------------------------------- Absolutely. -------------------------------------------------------------------------------- Eric Flown, Goldman Sachs - Analyst [17] -------------------------------------------------------------------------------- Eric [Flown] from Goldman Sachs Asset Management. A question on the slide 38. Can you help us bridge your guys' expectations for the MISO reserve margin versus what came out two weeks ago as they are showing that that is probably not going to happen until 2020? -------------------------------------------------------------------------------- Bob Flexon, Dynegy Inc. - President & CEO [18] -------------------------------------------------------------------------------- I'll let Hank provide a little bit of additional color on this and again he goes into it in his section but the high level is, MISO adjusted three things to take a deficit to a small surplus. They did the pencil whipping where you take your reserve margin and you lower it a little bit, so that gives you a little bit. You take your demand growth and you lower it a little bit so that lowers demand and then they have capacity additions of about 3800 megawatts or so and of that 3800 megawatts, half of it is the new nuclear unit being built in Detroit in two year's time. They haven't broken ground on it yet so I'm going to put that in the somewhat skeptical category. So you look at those three things, MISO is teetering on balance of whether or not they're going to have enough resources or not, and again there is no price signal to build and the way that MISO works and Julius certainly was covering this in that the market design where you've got 14 regulated states and you've got one that's a competitive state; the other regulated states they want to do their own resource planning. And there really is nobody bringing the total picture together and the capacity auction within MISO has no economic incentive to actually spend the price signal other event in central and southern Illinois, so there's really essentially no new build underway. They've got a fairly large queue, 63 gigs, I believe, of which I guess 18 or 19 have already been pulled out. But as far as the interconnection agreements, which is kind of where the ones that are real, that's the 3800. So we just view that MISO is just teetering on the edge here and they're relying on a lot of units that older peaking and the like, so we view that there's a real risk that the capacity is not going to be there on the highest demand days. And even when I was at the MISO Annual Stakeholder meeting last week with the Market Monitors doing state-of-the-market report, he was expressing his frustration with MISO that you're not doing anything to fix this capacity market. There's no new price signals and if you look at the highest demand days that they foresee after giving credit to demand response and everything else, their reserve margin is going to this summer about 7%, 8%. So you think about forced outages and the like -- it's a precarious balance that MISO has created and it's only going to get tighter because really there's nothing being built over the next several years there. -------------------------------------------------------------------------------- Greg Gordon, Evercore ISI - Analyst [19] -------------------------------------------------------------------------------- Greg Gordon with Evercore ISI. On MISO and then back to PGM first, Julius, can you comment on the statements made by the Illinois -- I think it was the Illinois Attorney General (inaudible) being unhappy with the auction and what the next steps might be in that if there will there be a new process or not if there is (inaudible)? -------------------------------------------------------------------------------- Bob Flexon, Dynegy Inc. - President & CEO [20] -------------------------------------------------------------------------------- I'll jump in in front of Julius. The auction results and this slide illustrates it particularly well on page 38, that you've got a market where every other surrounding state is incented to put their generation in at zero except for central and southern Illinois and this is where I think Exelon, Dynegy, the legislature in Illinois and MISO need to come together and fix the market for central and southern Illinois. Otherwise as days go on, generation in central and southern Illinois is such competitive disadvantage to those surrounding states it needs to be fixed. Otherwise central and southern Illinois are going to lose their tax base. They're going to lose a lot of jobs. You're going to see plants shutting down. The Attorney General reaction to the auction where you suddenly see it going from whatever it was $16 a megawatt day to $150 and then they look at these surrounding zones and they see $3 a megawatt day and they think oh my God, something must be dramatically wrong; and it is. It's because these other 14 states are getting $308 per megawatt day. That's where the complaint should be. But people don't necessarily understand the market. It's a bit esoteric in the way it all comes together and so they want to make sure that -- in deference to the Attorney General, she wants to make sure things were done the right way. We have experience working with Lisa Madigan; she wants to make sure that the proper procedures and protocols have all been followed, so they filed a complaint with FERC and we are going to respond to that complaint I guess in the next week or so. -------------------------------------------------------------------------------- Carolyn Burke, Dynegy Inc. - EVP, Business Operations & Systems [21] -------------------------------------------------------------------------------- July 2. -------------------------------------------------------------------------------- Bob Flexon, Dynegy Inc. - President & CEO [22] -------------------------------------------------------------------------------- July 2. But recall that both MISO and the independent Market Monitor, they're all over the whole bid process, the options, and they both have declared that everything was done completely within the tariff. So I don't see any risk or any issue from FERC or anything that deals with this particular auction. What it does serve is the catalyst -- let's make sure we have a full discussion around the market design in central and southern Illinois and I think there's a lot of parties interested in doing that now. And at the MISO meeting last week, John Bair, who is the President of MISO, made the comment we've got the attention, we know we need to fix this -- let's go at it. They have proposals that they've made to Illinois that deal with treating Zone 4 differently than the other zones where it's kind of a PJM look-alike and it's probably the fastest thing you can do because actually moving to PJM would be much more involved and contentious to get it there. So the fundamental issue is just you've got central and southern Illinois in the wrong market and we've got to do something to either synthetically improve that or actually move it. -------------------------------------------------------------------------------- Greg Gordon, Evercore ISI - Analyst [23] -------------------------------------------------------------------------------- Thanks. Back to PJM, maybe just a question or clarification, (inaudible) -------------------------------------------------------------------------------- Jeff Coyle, Dynegy Inc. - VP Operations Support [24] -------------------------------------------------------------------------------- I don't know if I understand the question. What type of unit? -------------------------------------------------------------------------------- Greg Gordon, Evercore ISI - Analyst [25] -------------------------------------------------------------------------------- So just within the (inaudible) zone (inaudible) auction, the capacity price was [119], it was [59] (inaudible), but PJM has said that they are only going to clear one price. And so at 49.999% CP you need a [mac] unit to clear, one would presumably have to be at least a modest premium to 119. Can you comment on whether or not that's plausible? -------------------------------------------------------------------------------- Jeff Coyle, Dynegy Inc. - VP Operations Support [26] -------------------------------------------------------------------------------- So the PGM rules are evolving as we speak. It's a very fluid situation and understanding from the meeting yesterday is consistent with yours that there's going to be one price. They'll be no zonal separation. And forecasting capacity prices was complicated enough before all this and now that -- but the volume part was pretty simple at least in our shop, we assumed all of our (inaudible) clear. In the new environment you're not only trying to forecast pricing in a much more complex scenario where you can -- where you can (inaudible) individual strategies to take on risk, you also have the added component of the volume question. So there's a wide range of outcomes in the transitional auctions. We are going to know the answers to these things within five or six weeks and again I think the general view is that there is potential uplift and possibly meaningful uplift for the RTO section and the zones properties may or may not experience any uplift. -------------------------------------------------------------------------------- Bob Flexon, Dynegy Inc. - President & CEO [27] -------------------------------------------------------------------------------- Greg, I don't see why it wouldn't be feasible. There's a fairly large risk premium you need to build in. There's been changes in generation mix. PJM West has had a lot of retirements. So again, it's all going to come down to bidding behavior but I don't see why it couldn't still continue to clear a strong (inaudible). -------------------------------------------------------------------------------- Michael Lapides, Goldman Sachs - Analyst [28] -------------------------------------------------------------------------------- Michael Lapides of Goldman Sachs on equity research. (multiple speakers) Real quickly changing topic or changing region a little bit, first of all, New England. Where do you think we are in the cycle in New England given capacity prices cleared somewhere $9, $10, $11 a KW a month? Where do you think we are -- trough, peak, middle of the cycle type deal? That's the first question. Second question, can you address your outlook and more importantly your strategic plans for the California fleet? -------------------------------------------------------------------------------- Bob Flexon, Dynegy Inc. - President & CEO [29] -------------------------------------------------------------------------------- Hank will go into ISO-New England. I'll just give a real quick answer on it. I think ISO-New England in the -- we are there in the cycle I put us somewhere between desperate and crisis. There's virtually no new generation being built. It's very hard to permit. If Northern Pass comes to fruition, it's going to be trapped in a new northern zone and the reason zones are created is to incent generation where it's needed and it's needed in South East Mass. And with Brayton Point retiring, with Vermont and Yankee now out, ISO-New England I think very concerned about reliability in meeting the capacity needs in the southern portion, southeast portion of the state. It is not looking any better. There hasn't been much -- been cleared. I know in our meetings with ISO-New England they're concerned about liability and I think really the bellwether what tells you that is still they are doing the out of market type mechanisms to try to drive reliability by making payments for having excess fuel on-site and the like to run units. They're relying on 25% of their generation fleet is old peaking units. So it's a very precarious situation in New England. I don't see it letting up any time soon because there aren't any necessarily big solutions coming. When we see Brayton Point and when we think about operational expansion, the kind of Brayton Point location as a Tier 2 for us, we've got some ideas for new generation and the like but that's a ways away. There just doesn't seem to be a lot of generation coming in. The other problem they have obviously, is getting pipeline capacity to actually get gas in during the winter because obviously that's utilized for the home heating season. So I don't see the noise in New England letting up anytime soon. What was the other half of your question? Oh, California. California, the main unknown for right now around Moss Landing continues to be the PG rate case and that process is ongoing and if it actually goes to a full hearing that will take us into the fourth quarter, stretch into December. Hopefully at some point in time we will have a settlement that we can negotiate with them. Right now they've been obviously very pre-occupied with bigger settlements that they're working on. But that's kind of a real pivot point for us where that settlement goes off because -- or where the final rate case terms out -- but that ultimately drives a significant value of Moss Landing in one direction or the other. And the thing that we continue to put forth to the Governor and to the California Water Resource Board is the Moss Landing provides such a good answer to the state of California to address their drought. You can see by ramping up Moss Landing just one or two, not even thinking about six and seven, you can save 2 billion gallons of water a year if you cycle down some of the combined cycle units that use [uni water] and we've got conversations done with the Agricultural Associations and trade groups out there and we're going to continue to push on it. I don't know why California wouldn't jump on the opportunity to save 2 billion gallons of fresh water overnight. And it is something we're going to try to push that through the political machines and bureaucracy that exists in these places but it's an incredible opportunity for California to make a serious dent into some of water issues that they have out there. And again, we are compliant with 316(b) out there. We would even accelerate some of the final negotiated agreements that we've reached for the Water Resource Board to extend the permit out there, so hopefully that get some traction out there and that would certainly drive some value with Moss Landing as well. -------------------------------------------------------------------------------- Stacey Nemeroff, Bloomberg Intelligence - Analyst [30] -------------------------------------------------------------------------------- Stacey Nemeroff, Bloomberg Intelligence. I have a question about potential further development or plant acquisitions and three specific types of opportunities. One, are you focused more exclusively on brownfield investments? Also you were speaking a lot about opportunity in the New England market and Eversource. They've indicated they are divesting their New Hampshire portfolio, so wondering how you view that? And then also are you potentially open to increasing your clean energy exposure? Other competitors both IPPs and hyper generators are pursuing that or have indicated their openness to that. -------------------------------------------------------------------------------- Bob Flexon, Dynegy Inc. - President & CEO [31] -------------------------------------------------------------------------------- So our focus first on expansion, which I provided some early looks and Hank will talk more about it, has been expanding existing generation capacity. Our alliance with GE has proven very beneficial and Marty gets certainly the lion's share of credit on that and what he's been able to work through with GE. He's uprate the speed to market, very low cost on average, $200, $250 a KW versus new capacity would which cost $1200, $1300 a KW. Time to market is quite quick. So that's where our immediate focus is at. It's kind of our Tier 1 desire. In terms of renewables and I liked the word that you use, I think the way that we think about it is clean technology. We're looking at it a couple ways that on the renewable front, the only way that we would participate in something like that is if there happened to be within one of our markets some renewables maybe coming off contract, if for some reason when it came time to enter in some type of auction that makes more sense for us versus someone else. And it is somewhat hard for me to see where that lies. I don't see any big jump into renewables. Maybe at one of our sites in Illinois that has excess land where you could do some type of PV application that would support Sheree's business in retail, maybe you could do that as part of growing the retail business because there it makes sense. But jumping into a commodity renewable market or solar, that's not what we do. I think you see from our cost structure the things that Carolyn covered, we place a premium on being lean, agile, low-cost and not a lot of overhead. And when you decide to jump into a new business that you really have no core competency or no differential market advantage, you're going to build a layer of hidden costs. That's just not anything that I want to within Dynegy or the Board has an appetite to do because it's just not who we are. So we want to bring an advantage. So when you think about clean technology, there are developing technologies out there that we are very interested in. On SO2 emissions and things of the like that are new technology that can lower your operating costs. So if we can find and develop with outsiders some new technologies around emission reduction -- we're getting into now the kind of the new buzzword is retro-commissioning, we're doing a retro-commissioning project at one of our plants where you look at energy leakage, look at ways to run the plant more efficiently, things like that. Jeff Coyle talked about the arrangement that we just had with an outside firm that has new milling technology for coal ash, so we can market more of our coal ash, so things around clean technology I think is more of our sweet spot than just a general generic jumping into renewables and be a me-too player and see a lot of cash leakage that I don't have any desire to see at this point. So we want to stay in our sweet spot, things that really help our portfolio. And regarding Eversource, in general around M&A we try to understand what's in the marketplace and what makes sense for our portfolio (inaudible) and I don't necessarily have a view on those assets at this point in time only to say that we look at M&A in the context of our deployable balance sheet capacity and disposable or discretionary cash. And at this point given our portfolio construct, particularly as it relates to New England and PJM where we are the largest generator in terms of combined cycle capacity relative to our market cap exposure to these two markets, I'm not in a real hurry to try to dilute that at all. I see that deploying a lot of our cash -- and again call it on average $1.5 billion or so over the next three years of deployable cash, that's one-third of our market cap, which could have significant value accretion for our shareholders. So all of those things we have to take into consideration. I think it's our job to make sure that we evaluate all of the opportunities fully and come out and say what's the best risk-adjusted return profile for this Company and decide at that point. So fairly long-winded (inaudible). With that we'll take a 15-minute break and then we will come back and do the second half. (Break in progress). ================================================================================ Presentation -------------------------------------------------------------------------------- Bob Flexon, Dynegy Inc. - President & CEO [1] -------------------------------------------------------------------------------- All right, we are going to start off with the second half of the presentation. I would like to introduce Sheree Petrone who is our EVP of Retail. -------------------------------------------------------------------------------- Sheree Petrone, Dynegy Inc. - EVP, Retail [2] -------------------------------------------------------------------------------- Thanks, everyone, good morning. So last year the first successful year for retail, I am happy to report. And this year we are continuing to execute the strategy that we have laid out for retail at the inception, which is to create value for our customers and our shareholders. If you look at the -- so we have three priorities for retail. And first, we are a marketer of our generation fleet. So, we work to fulfill the hedge objectives set by the commercial team with forward sales that lock in value and reduce risk. Second with the recent acquisition of Duke Energy retail, we continue to build a fully integrated operation that generates profit on a standalone basis. And third, our marketing effort is focused on understanding customer priorities. This informs our decisions on the products and services we should offer and also Dynegy's long-term strategy overall as a generator located in the communities we serve. Now for a little more detail on each of these, first starting with risk reduction. We have played a key role in supporting the commercial strategy to sell our MISO capacity through retail customer contracts. We have sold over 1,800 megawatts of capacity in Southern Illinois for planning year 2015-2016 which is about 28% of our available capacity. And this reduces the amount of capacity that alternatively we would have been a pricing through the MISO auction. In conjunction, retail energy sales are forecast to exceed 11,000 gigawatt hours in 2015 which equates to 70% of the expected generation of IPH. As a generator we have a cost advantage when making offers to customers, first through the collateral efficiency that we create by linking retail load with generation. And our estimate is about $0.25 per megawatt hour for this benefit. And in addition, internal hedging transactions eliminate the wholesale premiums that are paid by generators and load serving entities that transact independently in the market. This we estimate at a value of about $0.50 per megawatt hour. So, in total this results in about $20 million to $25 million in savings annually during the planning period. Now for a little bit more about the markets. The retail business operates in both MISO and PJM and in Southern Illinois we sell power under the brand recognized by our communities, Homefield Energy. We serve just under 500,000 residential customers with fixed-price contracts and these are consumers that live in communities that procure power through municipal aggregation programs. In addition we serve about 11,000 commercial customers that consume about half -- 55% of the power we sell. As you can see, we are the largest supplier in the MISO Southern Illinois with 29% of the market and we have an average customer renewal rate in excess of 60%. And we feel that this is really a unique point in time as our competitors are reevaluating their interest in retail and they are either exiting, scaling back or consolidating, which gives us a great opportunity to grow. In PJM we operate in Northern Illinois and Ohio and, as you can see, we are a relatively small player. We are now branding our expansion efforts there as Dynegy Energy Services. Currently we serve just over 400,000 residential customers mostly through muni agg, municipal aggregation. And in Ohio we do make some direct sales to mass-market customers through the use of digital campaigning. Our C&I customers, numbering 19,000, consume about 70% of the power we sell. We see PJM as an opportunity for expansion now that we have a larger generation footprint in Illinois, Ohio and Pennsylvania. So a little bit more about the growth on the next slide. Our growth strategy continues to focus on large volume transactions and they are the ones that are less costly to acquire and serve. So for C&I customers that means leveraging our expertise in the wholesale markets to provide energy offers that match a customer's risk profile. For residential customers we work with a network of energy consultants to create cost competitive offers in response to large RFPs. And in addition, we are in the process of integrating our operations since we have added the Ohio business. This we see as an opportunity to improve our operation, drive efficiencies, move to a standard platform and build common process across all of the markets. And these efficiencies will allow us to maintain a low cost operating model to serve our customers. As far as growing market share and our goals, so in Southern Illinois we have a three-year goal of reaching a 40% market share as we have plenty of generation length available. And again, we have seen signs over the last 12 months of retraction from some of our competitors. And some of these are the smaller market participants or those that don't have sufficient generation to back load. And as I mentioned earlier, retailers backed by generation have a cost advantage over the suppliers that are paying wholesale premiums in the market for load following energy products, especially post polar vortex. In PJM we set an attainable three-year goal for sales in Illinois and Ohio. Now with a much larger generation fleet and Dynegy's new entrance and commitment to the retail market in Ohio, we are well-positioned to be much more competitive and win market share while other suppliers are reevaluating their retail business opportunity. Now, this slide reflects a conservative growth rate for a Ohio since it is a new market for us and we are rolling out a new brand. But we do see opportunity for growth there. So how does that impact the financials? With a focus simply on expansion in our existing markets we are confident that volume growth is achievable given the change in the competitive landscape and we can drive an increase in annual earnings. And this projection is very reasonable in that it assumes prices will return to a more weather normal levels as our current contracts come up for renewal, and that sales growth will occur quickly -- more quickly in the large C&I segments where margins are typically lower or through large volume transactions like procurements for aggregate loads. We can be very competitive with the generation backed offers and it is really such an efficient way to hedge our long position. Beyond our existing territories we are evaluating new markets for expansion, based on the number of criteria though to determine if there is really a fit. So first it's whether we have generation significant enough to actually need a retail channel and that the generation infrastructure is in place to manage risk associated with load following retail products. In addition, there are other elements of the market that are important such as whether it is a pro competitive state and if utilities there facilitate supplier choice with programs like purchase of receivables. And we also need to be confident that our offers would be competitive when compared to other supplier offers. And also the residential market is certainly interesting to us where municipal aggregation opt out models are implemented. So to summarize, the retail business continues to be an attractive channel to market for our generation. The changes we see in the competitive landscape make growth and an expansion in PJM well-timed. And finally, we are confident that the retail will contribute stable earnings throughout the planning horizon. So now the long awaited Hank with the commercial presentation. -------------------------------------------------------------------------------- Hank Jones, Dynegy Inc. - Chief Commercial Officer [3] -------------------------------------------------------------------------------- Thank you, Sheree for that introduction. My name is Hank Jones; I am the Chief Commercial Officer for Dynegy. Thank you all for being here today. So as Bob mentioned in his opening comments, the power industry is facing profound structural changes that will have a lasting impact on reserve margins and system dynamics for years to come. 48 gigawatts of dispatchable generation has been retired or is scheduled to retire in New England, PJM and MISO between 2010 and 2016. In addition to the impact of this first wave of retirements, the system is experiencing a growing dependency on intermittent renewables and unreliable Demand response resources, all of which is expected to lead to firming capacity prices and higher and more volatile energy prices. Poor asset performance during the first quarter of 2014 was a wake-up call for those responsible for system reliability. As an example during peak demand periods in January 2014, 20% of the generation capacity in PJM didn't perform. Tight reserve margins coupled with poor reliability during high demand periods served as a catalyst for significant market design changes in New England and PJM. Performance incentives and capacity performance were put in place to drive reliability investment or the replacement of underperforming assets. As a result of (technical difficulty) market design changes, older and less reliable assets are at a significant risk of retirement, with 10% to 15% of the capacity in PJM and 25% of the capacity in New England identified as at risk. Given the challenges facing new builds and the speed with which older, less reliable assets will retire under CP and PI, new build will struggle to keep pace. For these reasons we expect tight reserve margins and the associated higher capacity and energy prices to persist for years to come. Historical natural gas flows have changed dramatically over the past few years and have had a meaningful impact on power markets. A shortage of takeaway capacity from the Marcellus Shale has resulted in depressed natural gas prices in the region. As low regional natural gas prices place downward pressure on power prices and contribute to the retirement decisions of uneconomic assets, they also result in expanding spark spreads for well-positioned CCGTs. As additional infrastructure is built to deliver this gas to other markets, natural gas prices are projected to rise in the region. Natural gas demand in the United States is expected to rise by 7 to 8 Bcf per day over the next four to five years providing additional support for natural gas prices. Dynegy has unrivaled access to inexpensive Marcellus gas at our combined cycle units in Ohio, Pennsylvania and New York which result in robust spark spreads and provides a significant competitive advantage in PJM and New York. As an example, this week we paid $1.30 to $1.70 per MMBtu for gas delivered to our CCGTs in Ohio and Pennsylvania while selling on-peak power at $40 to $55 per megawatt hour. Our southern New England fleet has firm natural gas transportation agreements in place for 25% of their peak demand and will be some of the first assets in New England to benefit from pending pipeline capacity expansions. While low natural gas prices have put pressure on coal-fired generation economics, we are a low cost producer in MISO and PJM and are well-positioned to weather the impact of low regional natural gas prices. Through aggressive rail contract negotiations, coal sourcing, coal blending and the implementation of refined coal at our facilities in PJM and MISO, we have achieved a low delivered cost of coal providing us with a $6 per megawatt hour fuel cost advantage in our PJM Ohio fleet versus eastern coals and a fuel cost advantage of up to $3 per megawatt hour versus our peers in MISO. In turning to slide 66, as you can see from the bar chart on the left, a disproportionately large amount of retirements in PJM and MISO occur in 2015 with more to come next spring as a result of mass compliance deadlines. These retirements will have removed 15% of the capacity in ISO-New England, PJM and MISO since 2010. Retirements are occurring not just in these three markets, but also in SPP and SERC for their tightening regional supply balances. The system's reliance on non-dispatchable capacity is growing at the same time that dispatchable assets are retiring. Wind and solar generation will comprise between 6% and 10% of the generation mix in New England, PJM and MISO by 2020. Random swings in output and the non-dispatchable nature of wind and solar resources make them a poor substitute for dependable coal, gas-fired and nuclear generation. There is no guarantee that intermittent resources will produce during peak demand events as the chart on the right illustrates. The vertical access on the left and the blue line depict the peak load in PJM for the period from January 6 through January 9 of 2014. The vertical axis on the right and the red line represent wind energy output in PJM during the same period. As you can see, when temperatures dropped and demand was peaking wind output dropped dramatically. Dispatchable resources were called upon to satisfy system reliability. This phenomenon will become more apparent and more impactful on energy prices as the system tightens up in a post MATS environment. Since 2010 Demand response as a supply resource has grown substantially. DR and PJM has proven to be unreliable when called upon. 70% of the Demand response resources provided no reduction in load during PJM Demand response events in 2014. These resources receive capacity payments in spite of their failure to perform during shortage events. Their inclusion in the capacity auction effectively depressed capacity market clearing prices by 25% to 30% over the past several years. Due to market design changes DR will play a limited role as a supply resource through auction. Moving to slide 69. In New England, in addition to the tight reserve margins projected in planning year 2018-2019, an additional 5 gigawatts of primarily oil fired steam units are at risk due to their inability to perform to PI standards. New builds are slow to arrive in New England due to challenging permitting processes and the need for infrastructure build out. We expect capacity prices in New England to remain firm and we have submitted transmission service requests for an incremental 100 megawatts of low-cost up rates at our existing facilities that we expect to qualify as new capacity and be eligible for the seven-year lock to capitalize on tight market conditions in FCA 10. Imports alone will not solve new England's reserve market problem. Northern Pass is tentatively targeted for delivery in 2019 but still faces further state regulatory approval before moving ahead. ISO-New England has proposed several capacity zones to stimulate investment where additional generation resources are required and to discourage investment where it is not required. The addition of Northern Pass in the proposed Northern Zone would likely cause the zone to separate and clear at a low price. This zonal construct would trap Northern Pass and Casco Bay but would protect Dynegy's assets in southern New England. The full effect of match retirements is reflected in our projection of reserve margin shortfalls in over -- of over 3 gigawatts in MISO's North and Central zones for planning your 2016-2017 which is next year's auction. Given the vertical demand curve employed by MISO, a capacity shortfall in the system may result in a system-wide clearing price at CONE which is estimated to be at $250 per megawatt day. We do not envision a quick fix to MISO's reserve margin shortfall and it is unrealistic to expect enough new build to enter the system to solve the shortfall until planning year 2018-2019 at the earliest. As the MISO capacity market tightens up we have significant volume to place in the market. We continue to pursue transmission paths to export MISO capacity to PTM for future planning years. We are exporting approximately 850 megawatts to PJM in planning your 2016-2017 and expect to complete a transmission path for an additional 240 megawatts of exports from Joppa to PJM in planning year 2017-2018. All of these MISO export volumes will qualify for capacity performance from PJM. Although the next significant retail sales opportunities are not expected until this fall, we have sold incremental retail volume in Zone 4 over the past few weeks that incorporates updated market views on capacity pricing. We are also in active discussions with munis, co-ops and utilities throughout MISO regarding additional long-term structured transactions. We recently closed an eight-year transaction at a weighted average capacity sales price of $3.82 per KW month or approximately $125 per megawatt day. This is evidence of a promising trend with load serving entities in MISO continuing to secure capacity for the long-term. A significant portion of the first wave of PJM retirements is located in Ohio, West Virginia and Western Pennsylvania and will precede the new build response. 8 gigawatts of deactivations occurred in PJM since May 1 of this year alone. New builds are more heavily weighted towards the east and will come into service over the next two to four years. The evolving regional balances are constructive for Dynegy in that over 80% of our PJM capacity is located in the West. We see tightening supply dynamics resulting from the first wave of retirements increasing the around-the-clock energy price in the AD Hub by $2 to $3 per megawatt hour. We expect the first wave of generation retirements to raise energy prices not only in PJM but also in New England and MISO as well. As the full impact of asset retirements take hole, price scarcity premiums may be substantial and will become evident during high demand periods and system shortage events possibly as early as this summer, but certainly by the summer of 2016. Our hedging strategy is driven by a balance between our market view and appropriate risk management practices to secure cash flow targets. 2016 hedge levels across the coal segment and IPH are at 30% to 40% and protect a portion of our coal fleet from the potential impact of lower natural gas prices in the region. Our coal segment now includes not only our DMG MISO assets, but also the recently acquired coal assets in PJM and New England. The gas segment is substantially less hedged during this period to allow for appreciation in spark spreads as power markets tighten and gas prices remain under pressure. Our forward hedging percentages will increase as the prompt year approaches with IPH hedging activity driven by the retail sales cycle and the coal and gas segments hedged opportunistically. Our position in 2017 is largely open and reflects our bias that the structural changes we have discussed will lead to higher energy prices and increased volatility that is yet to be recognized in forward markets. As you can see from the bar charts depicting the various components of the supply stack in each of our three primary markets, intermittent resources and DR make up a substantial portion of the reserve margin and their share of the asset base is growing. In 2020 without DR, PJM, MISO and New England are actually short versus reserve margin targets. In the CP and PI world not all megawatts are equal. A generator or supply resource collecting capacity payments will be held accountable for performance. The new market design at PJM and New England will likely drive a second wave of retirements as non-reliable assets either can't survive the penalty regime or price themselves out of the market during the auction. The chart on the left illustrates the 2014 forced outage rate by plant type in PJM. Each diamond on the chart represents a generating unit; the red circle represents the capacity weighted average forced outage rate for each plant type. Combustion turbines and steam units account for 60% of the installed capacity in PJM and experienced a weighted average forced outage rate of 18% and 15% respectively in 2014. As you can see, there are a number of combustion turbines and steam units with substantially worse forced outage rates than the class average. Without investment to increase the reliability of these assets a significant number of these at risk units will not survive in a CP environment because they will no longer be able to collect a risk-free capacity payment from PJM. Many of these retirement decisions will be made prior to new build filling the gap which may prolong a period of tight reserve margins across the system. As reserve margins tighten zonal balances within PJM become more critical. We have identified 10% to 15% of the capacity in the ComEd and AEP zones as at risk due to age and performance characteristics. Without reliability investments or new build these zones may separate from the RTO in upcoming auctions. New England is faced with a similar dynamic and an additional 5 gigawatts are at risk for retirement with the majority of these assets located in southern New England. This projected second wave of retirements and asset replacements will be driven by an onerous penalty structure for nonperformance. Penalties during shortage events in PJM are estimated to be $3,900 per megawatt hour and rising from $2,000 to $5,000 over time in New England. At $3,900 per megawatt hour, with 16 hours of nonperformance in PJM during shortage events, the penalty payment is equivalent to $170 per megawatt day, which is close to the market consensus estimates for the CP clearing price in planning year 2018-2019. This means that the entire CP payment can be lost in 16 hours of nonperformance during shortage events. In this type of environment the stakes are high and reliability, critical mass and a diverse portfolio are critical to success. Dynegy owns approximately 11 gigawatts of installed capacity in PJM and will import another 850 to 1,100 megawatts from MISO via firm transmission paths. As the largest merchant owner of CCGTs in PJM, Dynegy is well positioned to benefit in a capacity performance market with a diverse and reliable fleet consisting of over 60 generating units. Dynegy's fleet performance is on par with the PJM average in 2014. Excluding Zimmer, which was previously limited to interruptible natural gas supply for start-up fuel, the EFORd of Dynegy's coal units in PJM in 2014 was 13% versus the system average of 12% and 1% at our CCGTs versus the system average of 4%. Reliability initiatives such as winterizing exposed equipment, commissioning dual fuel start-up capability at Zimmer, developing alternative natural gas pipeline supplies, and pursuing firm gas transportation and delivery options are underway to enhance our reliability and to position the fleet for the capacity performance market. Citing, permitting and financing challenges do not allow for a quick new build response. New entry faces significant hurdles and response time is lagging the first wave of retirements. We expect new build to lag the timing of the second wave of retirements as well. As an example of this lag time, in spite of the opportunity to lock in $9.55 per KW month for seven years, only 1,000 megawatts of new capacity cleared the planning year 2018-2019 New England capacity auction. Historically PJM has only added 2 to 4 gigawatts of new capacity each year and only 20% of announced new build actually ever gets built. It will be difficult to measurably accelerate this rate going forward. While spark spreads in PJM are at historical highs it is difficult to lock in these rates beyond 2016. Additionally, the hefty collateral amounts required of developers to guarantee potential CP penalties and the fact that CP payments are at risk further increases the cost of development projects and serves as another hurdle for new entry. Due to market design issues, the only new entry expected in MISO is within regulated utilities outside of Zone 4 and there are only 2 gigawatts of new build with interconnect agreements in place targeted for completion by 2019. We are implementing expansions and up-rates to our existing facilities with economics and speed to market that are far superior to new build opportunities. We've identified over 645 megawatts of up-rates and expansions at our existing sites most of which come in service by the fall of 2016. These up-rates range in cost from $5 per KW to activate combustion turbines in Southern Illinois to $200 to $400 per KW for up-rates in the Northeast. This compares to recently quoted new build CCGT cost of $1,100 to $1,200 per KW in Eastern PJM. 260 megawatts of our up-rates are targeted in PJM with 210 megawatts expected to be in service by the fall of 2016. These up-rates will increase the efficiency and the output of the plants and will qualify for capacity performance. We have submitted transmission service requests for 100 megawatts of up-rates at our facilities in New England. We are confident that the 70 megawatts of up-rates at Lakewood and Milford will not require significant transmission upgrades, will qualify as new capacity in FCA 10 and will be eligible for the seven-year lockup for new capacity. The expansion opportunity at Independence is expected to bring an additional 50 megawatts of energy producing capability to the plant and will allow us to capitalize further on the strong spark spreads we regularly achieve at Independence. At Joppa we are in the process of returning 235 megawatts of gas fired peakers to service at a cost of approximately $5 per KW. These megawatts can be delivered to MISO, TBA or KU via our EEI transmission system. Additionally, we purchased Burke's Hollow as a potential development site adjacent to our Ontelaunee plant and will explore the possibility of taking advantage of the synergies of co-locating a new CCGT next to Ontelaunee. Summary, Dynegy is well-positioned with critical mass and a reliable and diverse generation fleet in markets where tight reserve margins are expected to persist and quality of assets matters. We have a substantially open forward hedge position which reflects our view that the structural changes facing the industry will result in meaningful increases in power prices. Inexpensive Marcellus gas has changed power market dynamics and we are well positioned for the opportunities and the challenges it creates. We have unrivaled access to Marcellus gas for a large portion of our fleet and we are a low cost producer of coal-fired energy in PJM and MISO. While there are substantial barriers to new build, we are capitalizing on changing market conditions by adding up to 645 megawatts of expansions and up-rates to our existing fleet at an average cost of $200 per KW in a fraction of the time it takes to bring on a greenfield project. In summary, there are profound structural changes occurring across the power market and their impact is expected to persist in the form of tightening reserve margins and increased capacity and energy prices for years to come. Dynegy is extremely well-positioned to benefit from these market conditions now and into the next decade. Thank you, and I will turn it over to Clint for our financial overview. -------------------------------------------------------------------------------- Clint Freeland, Dynegy Inc. - CFO [4] -------------------------------------------------------------------------------- Thank you, Hank, and good morning, everybody. My name is Clint Freeland, I am the Chief Financial Officer at Dynegy. Over the past several years the financial strategy of the Company has been focused on driving efficiency in the cost structure and the balance sheet of Dynegy, in building and diversifying our sources of liquidity and generally positioning the Company to execute and growth initiatives should they arise. Over that time frame we have made significant progress really on all fronts and today have a balance sheet that is strong and improving, a liquidity profile that is sufficient for all current and future needs, a cost structure that is efficient and stable over time. And a balanced portfolio of assets that generate significant gross margin across multiple markets. Now given many of the market dynamics that you just heard about, we expect Dynegy to generate significant EBITDA and free cash flow over the next several years. And as a result, to have a significant amount of excess capital to allocate in the years to come. Now while the Company has changed quite a bit over the past couple of years our approach to capital allocation has not. As we have said on a number of occasions, the first call on capital at Dynegy is for our plants to ensure that the appropriate amount of investment is made in safety, reliability and environmental compliance. We also prioritize our balance sheet and liquidity to be sure that the financial foundations of the Company remain strong. Now from a balance sheet management standpoint, our longer-term goal or medium-term goal is to migrate to BB credit metrics over time and we think that we are well-positioned to do that. And as we move forward we may look to refine our leverage profile from time to time, but in general we are happy with where our balance sheet is and with where our liquidity is. And what that means is that going forward the vast majority of the free cash flow generated by the Company should be available for intrinsic and extrinsic investments or returning to capital to shareholders. And as we look to make those decisions we intend to use share buybacks, or the economics associated with share buybacks, as the benchmark against which other uses or other investment opportunities are measured. Now as you can see our focus on capital efficiency and allocation has resulted in a virtual doubling of Dynegy's return on invested capital over the past couple years from 5.5% in 2013 to roughly 10.8% this year while at the same time driving down the cost of capital by roughly 250 basis points. The main contributors to the improvement in ROIC are primarily our PRIDE program as well as the two most recent acquisitions that, when compared against the amount of capital deployed, generate an ROIC of roughly 16%. Now as I mentioned earlier, our medium-term goal is to migrate to BB credit metrics over time, and again I think we are well-positioned to do that. As I will get into in more detail in a moment, we expect to generate a significant amount of cash over the next several years sufficient to drive the Company's net debt to adjusted EBITDA ratio down from 4.9 times today to somewhere in the mid 3 to mid 4 range. Now, while I wouldn't expect to use a lot of our cash to delever the balance sheet to those levels, it does demonstrate the Company's ability to manage its balance sheet to its target metrics. Looking at the FFO to debt trajectory over the next several years, we may get to BB credit metrics over time naturally through increased earnings. That is something that we are going to need to keep our eye on, but be sure that we are always moving in the right direction from a balance sheet management standpoint. Now that was the DI balance sheet, but we also keep a close eye on the IPH balance sheet. And from everything that we have seen so far, the financial outlook for IPH has materially improved. There are a number of reasons for that, including the forward sale of capacity into MISO and PJM, positive contributions from our retail business, and a significant improvement in the cost structure of the subsidiary driven mainly by original transaction synergies, our PRIDE program, our new rail agreements as well as lower corporate cost allocations. Now many of these items are in place today but will benefit IPH in coming years. So one of the things that we have done to try to capture this and to demonstrate this is to put together a forecast for IPH that only looks at those items that are in place today. And that, together with the forward curve, is the scenario that we call our current status case. And as you can see under that very conservative case, the net debt to EBITDA for IPH over the next several years falls from about 8.8 times today to roughly 5.5 times on average over that three-year window. And from an FFO to debt standpoint, the FFO to debt improves from roughly 2.2% today to roughly 9.5% on average. Now to the extent that our retail business is able to renew its book of business and roll that forward, to the extent that we are able to sell more capacity out of IPH, or to the extent that actual power prices materialize above the current forwards, all of those could be meaningfully accretive to the financial profile of IPH. Now 2018 and 2019 are critical years for IPH with a $300 million debt refinancing as well as a meaningful investment in backend controls at Newton. So we are keeping a very close eye on IPH's ability to meet these obligations, but so far, based on what we see today, we are encouraged. Now historically we have spoken about needing to have roughly $600 million to $800 million in cash liquidity to run the business. And I thought it would be helpful to kind of break that down into kind of the largest components. From a working capital standpoint the combined Company -- the combined Company's working capital needs are relatively steady throughout the year, but can spike during the winter as fuel and power prices increase and become very volatile. So to demonstrate this we put together a pro forma rolling four quarter look for the combined Company. And as you can see, just this past winter as prices spiked working capital spiked for the combined Company. From peak to trough that is roughly $150 million to $200 million. And again, this is something that we need to prepare for and manage to. Now historically one of the most significant uses of the Company's liquidity has been providing collateral to our natural gas suppliers. And with the addition of so many natural gas plants in the most recent transactions that need is only increasing. So to estimate what the collateral need for the combined Company going forward is, we put together a simulation for the combined fleet that mimic the polar vortex to see how much collateral would we need to post in that situation. And the result of that analysis showed that we needed roughly $650 million in collateral to post to our natural gas suppliers. Now we would meet that in several different ways. First, we would max out the amount of first lien capacity that we have available for natural gas purchases. Second, we would max out the amount of letters of credit that we would issue to our suppliers. And looking through our various supply agreements that comes out to about $250 million. And then we would need to post cash for the balance which would be roughly $200 million. Now posting cash collateral to our natural gas suppliers isn't the only place where we post cash. We also post collateral against some of our hedge positions on various exchanges that we use to manage our seasonal hedge position. Historically that amount for the legacy DI fleet was roughly $50 million to $100 million and we estimate that on a go-forward basis for the combined Company that is roughly $100 million to $150 million. And then finally, one of the areas that I don't think it gets a lot of attention is the lumpiness of our interest expense. Looking at our $5.1 billion acquisition financing, interest expense payments are due every May 1 and November 1 of each year. And on our legacy DI debt interest payments are due every June 1 and December 1 of each year. And what that means is that every year there are two 30-day windows during shoulder periods when $215 million in cash needs to go out of the Company to service our debt. So in total this gives you a sense of the building blocks of how we get to the $600 million to $800 million in cash. Now I would say that over time I think there may be opportunities to bring this down to manage this to a lower level and we certainly will do that. But even with all that said, given our current liquidity position of roughly $1.5 billion, $600 million of which is in cash, I think our current liquidity position is sufficient for all of our current and future needs. Now for Dynegy there are four main areas of cash cost: G&A, O&M, CapEx and interest expense. And as you can see from the slide, all of these are roughly stable over time. And what that means is that as the Company generates gross margin, and increasing levels of gross margin, that that should fall directly to EBITDA free cash flow and capital available for allocation. Now as a result of the most recent transactions Dynegy's gross margin is much more diversified and I would argue higher quality with roughly one-third of our gross margin going forward coming from market capacity revenues versus only 12% just last year. And roughly two-thirds of our gross margin going forward is coming from a diversified energy margin led by our PJM fleet. Now there are a number of factors that influence our gross margin, one of the most significant of which is the price of natural gas. Now in the past we have provided a sensitivity analysis showing that for every $1 change in the delivered price of natural gas that our EBITDA sensitivity was roughly $360 million. Now that was based on an analysis that looked at how forward power prices and forward spark spreads responded to changes in the price of natural gas in the forward markets. And that was specific to the timeframe 2011 to 2014. We have since refreshed that analysis and rolled that timeframe forward to 2013 to midyear 2015. And what we have seen is that some of the correlations between the gas and power in that new timeframe have been weakening. And as a result our sensitivity to a $1 change in the delivered price of natural gas has fallen to roughly $290 million. Now in looking even further into the new timeframe between 2013 and 2015 there is a very important dynamic that is taking place that we are seeing that investors need to keep their eye on. When you look at the sensitivity from year to year during that updated timeframe, the sensitivity of our MISO fleet really doesn't change. When you look at our New England fleet the sensitivity really doesn't change. But within that timeframe what we are seeing is a meaningful change in the sensitivity of our PJM fleet -- we tried to call that out at the bottom left-hand part of the slide here. Just several years ago a $1 change in the delivered price of natural gas for the PJM fleet would have translated into roughly $140 million to $160 million change in adjusted EBITDA, where in 2015, looking at 2016 forward, that sensitivity is only $10 million. So obviously a significant change. Now this is something worth keeping your eye on. Because to the extent that this dynamic continues, and it certainly can change and go the other way, but to the extent that this continues it will bring down the overall sensitivity of the Company in natural gas over time as we roll the analysis forward. So now, while these are all of the relationships that are implied by the forward markets over the long-term, there are factors that can cause these relationships to break down in the short-term, such as weather, leading to results that are different than what the sensitivity would suggest. And that is exactly what we have seen over the last 9 to 12 months. We originally initiated our 2015 guidance in August of 2014 and since that time the price of natural gas is come down significantly. But it hasn't had a meaningful impact on our forecasted results for this year. And the reason why is that market heat rates this year have been significantly higher than what has been implied in the forward markets historically. So when using our sensitivities it is really important to really use them in two steps. First is to look at, in response to changes in gas, what our sensitivities would imply because that is based on history and what has been implied in the forward markets over time. But the second step is important as well -- look at what the current market is doing to see if those historic relationships are holding. If they are not an adjustment needs to be made to take into account that there is a difference between how historic forward markets are moving versus today's current markets. Now as the Company generates EBITDA and free cash flow on a go-forward basis, one of the largest assets of the Company will come into play, its $3.5 billion net operating loss carry forward. Based on current calculations, to the extent that the consolidated adjusted EBITDA at Dynegy over the next five years is on average over $1.1 billion we will be a positive taxable income generator, that we would then be able to use our NOL to shield and protect us from being a significant federal income tax payer. Now as we move forward taking into account all of the dynamics that you have heard this morning, we have updated our forecast for the 2016 to 2018 timeframe to provide investors with a better sense of the earnings power of the combined Company. We have done that by really running two separate forecasts, the first is our base case which uses market power prices and market spark spreads, as well as certain assumptions around unsold capacity and the PJM transitional auctions. And the second is our incremental case which uses our internal view of power prices and spark spreads from 2016 to 2018. Now based on these two scenarios we would expect for the Company to generate in total between 2016 and 2018 consolidated adjusted EBITDA of $3.9 billion to $4.9 billion. So as you can see, we believe there is meaningful earnings growth potential with the assets that we already have and with the stable cost structure that we have in place for that to translate into significant free cash flow and capital available for allocation. Now of the $3.9 billion to $4.9 billion in aggregate consolidated adjusted EBITDA, $600 million to $700 million of that is at IPH. And IPH will use that to pay its own interest expense, it is environmental and maintenance CapEx going forward. Now given the ring fence nature of that subsidiary, any free cash flow generated during the period will remain at IPH and not be available at DI for allocation. Of the remaining EBITDA generated by the coal and gas segments roughly $2.2 billion will be needed to pay our interest expense as well as fund our maintenance and environmental CapEx and investments leaving roughly $1.1 billion to $2 billion in excess capital available for allocation. Now of this amount about $75 million will be needed to make mandatory principal repayments on our term loan, as well as pay dividends on our mandatory preferred stock. And we're also evaluating, as you've heard this morning, incremental investments in both reliability and up-rates. But those will need to be economically justified as part of our capital allocation program. But even with those investments being made, we still expect a significant amount of capital to be available for allocation over the next several years. So in summary, the financial foundation of the Company is strong and with the balance sheet, liquidity and cost structure of the Company where it needs to be, we see Dynegy as being well-positioned to be a significant generator and allocator of capital in the future. And with that I will turn it back over to Bob. -------------------------------------------------------------------------------- Bob Flexon, Dynegy Inc. - President & CEO [5] -------------------------------------------------------------------------------- Thank you, Clint. Today -- we have covered a lot of ground today and I have tried to capture the themes on a conclusion slide -- I won't go through them all because I know it is quite busy. But I wanted to put generally the general takeaways that I think everybody should have from today's session. I would also like to add that our investment thesis that I outlined at the very beginning remains constant, it is the same investor thesis that we had when we first had our investor meeting back in January of 2013. And that is the retirement of base load generation that is happening across the market, that is happening that is driven by economics along with the continuing flow of state and federal regulations that continue to impact generation assets. I think the new change that we have now going forward is how capacity performance or performance incentives is again going to change the mix of generation assets with an obligation for quality megawatts and the implications of not meeting your delivery requirements during a declared shortage event. I would say now today that Dynegy's portfolio as reconstructed over the past couple of years is best positioned in these markets to meet these obligations. And that combined with the cash flow generation profile that we see for these assets. I would say today that our Dynegy is positioned better than it has ever been in the past, and that combined with our disciplined capital allocation approach to the business I would say the outlook for the Company, for its stakeholders and for its shareholders has never been brighter. I would also like to add before we go to the Q&A that part of the objective that we have coming to a meeting like this is for our shareholders to see the full management team. And the team that has worked hard at pulling this information altogether. We also have three members of our Board of Directors here, we have Paul Barbas, Hilary Ackerman and Jeff Stein -- was here. Oh there he is, he's hiding. So the takeaway that I want you to have from meeting the management team and several of the board members is that we have got a deep bench, we've got a lot of talent in the Company throughout at all levels. The teamwork is excellent and it's those combination of factors that gives us the agility in the market to do things like announcing two acquisitions on the same day, integrating them into the portfolio during the same time period, having it fully integrated within two months, capturing the synergies that we said we would capture. It really is just a testament to the employees that we have and it starts Board of Directors all the way through the organization, we really have built a great Company with a lot of great talented individuals and that is certainly important for us to demonstrate to our shareholders as well. And that is part of our objective today as well as trying to be as transparent as we possibly can on the business for all of you. So at this point though I would like to open up for the final Q&A session. I guess we have about 30 minutes or so, Andy, to go through that. I should also add that this is Andy's last Investor Relations activity. He is switching jobs with Rodney McMahan who is over there very stressed (laughter). Andy is a lot happier than Rodney. ================================================================================ Questions and Answers -------------------------------------------------------------------------------- Felix Carmen, Visium Asset Management - Analyst [1] -------------------------------------------------------------------------------- Felix Carmen, Visium Asset Management. Can you share with us some of the assumptions that you are including in the $1.3 billion run rate, the adjusted EBITDA? Maybe talk about what you are assuming for the incremental auctions in the 2018-2019 planning year. -------------------------------------------------------------------------------- Bob Flexon, Dynegy Inc. - President & CEO [2] -------------------------------------------------------------------------------- Okay, and so the question is what are some of the assumptions built into the forecasted EBITDA over the timeframe and what are the assumptions built around the transitional and the capacity performance options within PJM. Clint, do you want to --? -------------------------------------------------------------------------------- Clint Freeland, Dynegy Inc. - CFO [3] -------------------------------------------------------------------------------- Yes, I will start off with and (inaudible) any additional (inaudible). Yes, so for the base case, as I mentioned, we use market curves for power prices and spark spreads as of mid-May. For the unsold capacity we made certain assumptions around the transitional auctions, kind of working with the commercial team. We tried to be relatively conservative on the outcome of those auctions. Obviously we don't want to be too specific given that there is an auction coming up in (inaudible). But I think we were -- there are a wide range of outcomes that are possible and we try to be kind of on the conservative end of our expectations for the transitional auctions. For the MISO capacity, in general I would say that the prices are expected in that base case are generally consistent with the most recent auction. However, we do make certain assumptions on how much of that capacity actually clears. Again, I don't know if we can be more specific than that. We do assume that the retail book does roll forward at historic levels and then it is just a matter of -- then we also already have volume sold into MISO, volume sold into PJM. And just how much of that amount that is left is sold at prices that roughly are equal to more recent [clearing in] MISO. -------------------------------------------------------------------------------- Bob Flexon, Dynegy Inc. - President & CEO [4] -------------------------------------------------------------------------------- And then maybe just one thing I would add that Sheree is experiencing in her business, our win rate on the Homefield Energy side has declined a bit since what it was in the past and that is because we have a firm view on the value of our capacity in MISO. And as part of our retail bidding processes, we take that view on value, which is similar to recent auction clears, that that is the value of the capacity in MISO and that is built into the forecast as well. -------------------------------------------------------------------------------- Unidentified Audience Member [5] -------------------------------------------------------------------------------- And just one follow-up question maybe to kind of help gauge our expectation. Do you have maybe perhaps a sensitivity for maybe every $10 deviation from the current PJM [clearance] price of 120? What would that translate into EBITDA? -------------------------------------------------------------------------------- Hank Jones, Dynegy Inc. - Chief Commercial Officer [6] -------------------------------------------------------------------------------- I think -- and check me on this, but I think the sensitivity is that for every -- assuming that the entire fleet clears that for every $10 change it is $40 million in EBITDA? -------------------------------------------------------------------------------- Clint Freeland, Dynegy Inc. - CFO [7] -------------------------------------------------------------------------------- Yes, and a key assumption there is that if every megawatt were to clear a $10 uplift is (multiple speakers). -------------------------------------------------------------------------------- Unidentified Audience Member [8] -------------------------------------------------------------------------------- All right, so a quick question, I will try to be clear. So with regards to the IPH portfolio, is that included -- I know in the SCF breakdown -- is that included in the $3.9 billion to $4.9 billion, the IPH? -------------------------------------------------------------------------------- Clint Freeland, Dynegy Inc. - CFO [9] -------------------------------------------------------------------------------- Yes. -------------------------------------------------------------------------------- Unidentified Audience Member [10] -------------------------------------------------------------------------------- It is indeed, okay, great. And then secondly more strategically, you've obviously got a couple deals off the ground. And I don't mean to be too early about this, but how are you thinking strategically about deals going forward? And specifically in that regard, there is sort of a hole when it comes to Texas and your positioning around the country. How do you think about that? -------------------------------------------------------------------------------- Bob Flexon, Dynegy Inc. - President & CEO [11] -------------------------------------------------------------------------------- I think our view on M&A processes as we go forward is much like we have (inaudible) in the past, and that is to make sure we are really aware of what is happening in the market there. Are portfolios coming to market? How they fit with us we would evaluate. We don't necessarily think we have any particular market restrictions. It is more around what is the best investment opportunity for the Company when you look at all of the alternatives. What is different today versus a couple of years ago is we have critical scale, we have critical mass in the markets where we want to be. Certainly I am glad we didn't invest in ERCOT a couple of years ago. We went -- obviously PJM and ISO-New England. ERCOT has gotten certainly over the past few years a lot less bullish than what it previously thought it was going to be. But it is up to us continually to look, evaluate, and determine what is the best use of our capital. The urgency around mitigating the risk that we have with just one or two assets that we're really driving the cash flow is behind us. The risk of carrying a subscale portfolio is behind us. And I think you see the value of leverage that -- leveraging the scale that we have. So it is really just opportunistic and what is the best use of our capital. And there aren't as many opportunities as there were in the past. Again, we continue to evaluate and see -- I don't want to get specific to any Company or any particular asset. But I wouldn't close the door on anything. Again, we just have to go through the evaluation and what is the best thing to do for the Company, for the shareholders, and what's the best risk adjusted return that we can pursue. -------------------------------------------------------------------------------- Unidentified Audience Member [12] -------------------------------------------------------------------------------- Great. And then perhaps another strategic question. Obviously a lot of legislative efforts Ohio, Illinois -- focusing on Illinois first. Can you comment a little bit about your expectations on MISO capacity as it relates to what comes out of that process? Specifically I suppose Clinton is a big wildcard as it would relate to capacity price expectations. How does that drive your thinking and then what are your expectations at present in Illinois given where we are in that? -------------------------------------------------------------------------------- Bob Flexon, Dynegy Inc. - President & CEO [13] -------------------------------------------------------------------------------- So the question is around MISO capacity. We have gone through the auction, review is under way and the like. So what is our expectation for MISO capacity going forward? Certainly there is a number of dynamics at work. There is just the base fundamental of just how much capacity is within MISO wide system. Our theory around MISO has always been more around the entire MISO, classic MISO footprint than specifically to Zone 4. We just have continually viewed that as we approached 2015, 2016, 2017 and 2018 that there could be a capacity shortfall due to retirements. And within MISO a lot of the one year MATS extensions were granted. And MISO has another wave of retirements under MATS that will (inaudible) the next or have an impact on the next capacity auction next March. So there is further tightening there. And whether or not there would be enough resources, to be determined. As we talked about earlier this morning, they have done some cosmetic things to change that around reserve margins, forecasted demand. But the fundamental issue in MISO was nothing being built, stuff is being retired. So I expect continuing tightness. Whether it gets to an administrative cap over the next year or two is to be seen, it is very, very close to that. Right now we do have the [attention] that Zone 4 is not designed properly. As I mentioned earlier, John Bear at MISO has talked to Illinois about some specific potential redesign of Zone 4 to make it have a lot of characteristics that we are looking for, a three-year forward look, a sloping demand curve and the like -- make that specific to Zone 4 to get a better construct in place. How long it takes to get that into place will take some time, but we also have Illinois legislature certainly very much focused on this. What happens to Clinton is the question mark (inaudible). As Clinton retired do they need it for liability, how does that impact the auction process or again some open questions. So, to be seen, but I think the trend is just tighter and we are getting closer and closer to not having enough reserve requirements within MISO. -------------------------------------------------------------------------------- Unidentified Audience Member [14] -------------------------------------------------------------------------------- And then last little detail, mark-to-market on the portfolio versus the guidance? The date sent was May 13 versus today. Any sense on what that delta would be, maybe that is a Clint question. -------------------------------------------------------------------------------- Clint Freeland, Dynegy Inc. - CFO [15] -------------------------------------------------------------------------------- Yes and I don't have specific numbers, but certainly you have seen the curb curve weaken since the middle of May. But again, I think a lot of it has to do with kind of weather expectations and certainly that can turn. So we tried not to kind of constantly mark that to market, but I think certainly since that date we have seen some (inaudible). -------------------------------------------------------------------------------- Bob Flexon, Dynegy Inc. - President & CEO [16] -------------------------------------------------------------------------------- We generate 120 million megawatt hours a year, right, so, moves a dollar and that dollar -- that could happen tomorrow. So this does have some volatility to it (inaudible) turning around a little bit. -------------------------------------------------------------------------------- Unidentified Audience Member [17] -------------------------------------------------------------------------------- I wanted to ask you about slide 77. The reserve margins there for Western PJM look a little lower than I recall PJM's forecast. Is that because of some local transmission constraints or is there some other calculation that you are putting into it? I am sorry if I am a little slow there, but it wasn't completely clear to me on that. And if it is some adjustments that you guys had made --. -------------------------------------------------------------------------------- Unidentified Company Representative [18] -------------------------------------------------------------------------------- (Inaudible - microphone inaccessible). -------------------------------------------------------------------------------- Bob Flexon, Dynegy Inc. - President & CEO [19] -------------------------------------------------------------------------------- So was that 70? -------------------------------------------------------------------------------- Unidentified Company Representative [20] -------------------------------------------------------------------------------- (Inaudible - microphone inaccessible). -------------------------------------------------------------------------------- Unidentified Audience Member [21] -------------------------------------------------------------------------------- That's it, that's the one. So when I look at that, the Western PJM was 10%. Now just wondering is that because of some local transmission constraint or were there some adjustments that you guys are making? And if you were to apply that adjustment, if that is what it is, to 2015-2016 what would that be just so that we have some idea about what is going on there? That is the first question. And then the second question I have is associated with what you guys expect in terms of new entrants. You mentioned a few things, there are some new barriers to entry, etc. But what are your expectations for the next BRA, roughly speaking, in August or whatever for new entrants to come in given the new capacity performance stuff that we have here going on? If you guys could opine on that, that would be great. -------------------------------------------------------------------------------- Bob Flexon, Dynegy Inc. - President & CEO [22] -------------------------------------------------------------------------------- Yes, so, the first question that I think you asked was around Western PJM, what is the assumption, what is the assumption that's being built in there in terms of the 10% capacity at risk with that? -------------------------------------------------------------------------------- Unidentified Audience Member [23] -------------------------------------------------------------------------------- So the reserve margin looks like it is starting at 10% for 2015-2016 -- 2016-2017, right? And that is a little bit lower than what I generally think of what PJM has got forecasted, right. So maybe you are taking out the (inaudible), I am not sure what is going on. But if you -- if it is an adjustment as opposed to maybe some transmission constraint what would the impact -- what would be (inaudible) now, in other words what is the reserve margin? -------------------------------------------------------------------------------- Bob Flexon, Dynegy Inc. - President & CEO [24] -------------------------------------------------------------------------------- Sure, so the starting point for 2016-2017 of 10% at Western PJM, what is behind that (inaudible)? -------------------------------------------------------------------------------- Hank Jones, Dynegy Inc. - Chief Commercial Officer [25] -------------------------------------------------------------------------------- So, this is our internal analysis based on a potentially different geography than specific PJM zones. And I can't speak to how this would reflect in a 2015-2016 reserve margin case. The point of the graph is to suggest that there is substantial capacity at risk in the AEP zone and the ComEd zone as a result of performance characteristics and age of the units. And if new build did not occur over time there is a substantial shortfall. So I guess to your second question about our expectations on new build, there clearly are limitations in terms of the speed with which new capacity comes into the system. We are not -- it is logical that new builds should come into the system. That is how -- that is why this market is set up this way is to inspire investment. And we do expect new build to come, we just don't think it happens in one big slug. It consistently (technical difficulty) 2 to 4 gigawatts a year across the whole system and that's a huge percentage of the volume that's -- or of the projects that are listed don't ever get built. But we do expect volume to come in. I think it's going to be hard to push it much faster than 2 to 4 gigawatts a year. -------------------------------------------------------------------------------- Unidentified Audience Member [26] -------------------------------------------------------------------------------- Okay, but just going back to the 10%, not to harp on this, but so when you say that the 10% is based on some specific area, are you guys backing out Demand response or anything or are you just basically -- I mean because it just seems like a low number? And I guess -- I understand conceptually you are saying, hey, this could be a drop-off. But when you mention like a minus 10% reserve margin, I mean is that -- I mean -- is it apples-to-apples with what PJM currently has forecasted or is it -- is this something more here. Do you follow what I am saying? -------------------------------------------------------------------------------- Hank Jones, Dynegy Inc. - Chief Commercial Officer [27] -------------------------------------------------------------------------------- Yes, it is not apples-to-apples to what PJM forecasts. This is not a -- doesn't have a complicated algorithm for imports and exports out of the system. This is reflecting -- one of the comments that I made was that 8 gigawatts was deactivated since May 1 simply in Ohio, West Virginia and Western PA; most of that volume sits right there. So this is a reflection at a high level of all that capacity leaving the system. -------------------------------------------------------------------------------- Unidentified Audience Member [28] -------------------------------------------------------------------------------- Oh, hi, it is Douglas, (inaudible) Capital. On page 36, maybe you could help me with that a bit. It is about the PJM capacity performance. And the capacity payments, that is all very alluring. But the penalties seem very severe. I mean eight hours, that is $0.10 a share based on the amount you show. How do you even model that? I mean, it is a bad deal for bad operators, but it could be a bad deal for good operators too. I mean is there a force majeure. What are the mitigating factors? Because you could give away a lot of money here. -------------------------------------------------------------------------------- Bob Flexon, Dynegy Inc. - President & CEO [29] -------------------------------------------------------------------------------- Yes, I will let either Hank or Julius (inaudible) talked about the force majeure component of it. But the point that we are really trying to highlight from the slide as well around -- and for the folks on the webcast on page 36, talking about the penalty structure of CP. If you are a single operator or if you are someone that wants to build a new unit within PJM, this is not necessarily a good thing. From a financing standpoint on building a new unit I would think you've got to put more equity at risk because your capacity payment now has become very variable and potentially very punitive. And if you are a single operator or you have a relatively small fleet with the penalty being at 1.5 times CONE I believe you can end up with negative capacity payments in any given year. The advantage of our fleet is that we have 60 units, so you have risk diversification. And there are times, particularly in a very high demand period, whether that could be in the summer where you have fee rates due to the temperature of cooling water or whether that is in the winter when you have other issues with -- particularly sometimes when it is snow that creates clogging in combined cycle intakes and the like where you get [D rates] or outages or the like. That happens in spots of the fleet, it doesn't happen to the entire fleet. It is definitely a positive for us being that we have 60 units. But if you are sitting there with just a couple of units, as we said, if the capacity market clears at $170 a megawatt day you can lose that in one day. And then you are going to go in the negative if it happens again. PJM is forecasting approximately 30 hours -- shortage hours a year. And you can lose $170 a megawatt day in half of the time. So it is an interesting structure that is going to put pressure on units. And if you are a generator that has mostly peaking units in that market as well, this is not the market for you. I mean if you have got a ramp time of 12 hours or something like that or you have got an LDC between you and your gas supply, that is your problem, and it is not going to be a force majeure event. So if the plant is not there when called upon. Whether it is your fault that fuel is missing, I presume also transmission outages, it is still you are wearing -- you are virtually wearing every risk. Is there anything that is a force majeure event? -------------------------------------------------------------------------------- Unidentified Company Representative [30] -------------------------------------------------------------------------------- Yes PJM has definitely tightened up the rules (inaudible) portfolio, graphically diverse, fuel diverse and (inaudible) reliability and also build that risk into our offers. -------------------------------------------------------------------------------- Unidentified Audience Member [31] -------------------------------------------------------------------------------- But you are confident you can like model this I guess is it really the (multiple speakers)? -------------------------------------------------------------------------------- Bob Flexon, Dynegy Inc. - President & CEO [32] -------------------------------------------------------------------------------- We are confident what we can model is -- and while we are looking at every single asset that we have, every single unit and modeling what is the risk of them. We know there are certain coal units that are less reliable than others so they will be bid in differently. We know that there is -- we have got a couple of peaking assets that we would bid in differently. And we know we have certain combined cycle units that have unfettered access to (inaudible) so they would be bid in differently. And each unit has 10 different bidding levels that you can participate. But we have asset managers in each of the markets working with Dan and Marty making sure we understand the capabilities of each asset, where the vulnerabilities are and developing a bid strategy around it. And I say right now that is a work in progress, we don't have the answers yet. To your point, we are doing some very detailed modeling and analysis and scenario planning around that. -------------------------------------------------------------------------------- Hank Jones, Dynegy Inc. - Chief Commercial Officer [33] -------------------------------------------------------------------------------- Can I make a comment, Bob? Can I make a quick comment? So just to be clear, the optimization of this wouldn't necessarily be that all your volumes cleared CP. In fact, that would not be the optimal scenario. Your pricing and risk and at a level which you are able to invest based on the premiums you receive. But there is a tradeoff between volumes we will offer in pairs, a base auction price and a CP auction price. So I think there is -- want to make sure there is no misconception about that, that all the volume more than likely will not clear CP. -------------------------------------------------------------------------------- Unidentified Audience Member [34] -------------------------------------------------------------------------------- (Inaudible) from Deutsche Bank. Back to slide 77. (Inaudible) 1979 -- what percentage of the PJM capacity do you see at risk? -------------------------------------------------------------------------------- Bob Flexon, Dynegy Inc. - President & CEO [35] -------------------------------------------------------------------------------- Did you say 77 or 79? -------------------------------------------------------------------------------- Unidentified Audience Member [36] -------------------------------------------------------------------------------- Our 77, your 79. -------------------------------------------------------------------------------- Bob Flexon, Dynegy Inc. - President & CEO [37] -------------------------------------------------------------------------------- Oh, I didn't realize they were different numbers. Oh, that is helpful (laughter). -------------------------------------------------------------------------------- Unidentified Audience Member [38] -------------------------------------------------------------------------------- So, the question was what percentage of PJM live capacity is at risk and also maybe related is how much is more targeted towards base capacity? And that pool is only limited to 20%, so a lot more than that around (inaudible) presumably (inaudible). -------------------------------------------------------------------------------- Hank Jones, Dynegy Inc. - Chief Commercial Officer [39] -------------------------------------------------------------------------------- Sure, so the question was on slide 79, how much of the capacity in PJM is at risk for retirement. And I think that was the question. Our assessment is that that number is 10% to 15%. It is based on what we know about the operational characteristics of some of the assets and the age of the assets. And the view is that in the past they were collecting capacity rent with no obligation to perform. So no harm no foul if they didn't make it. And I our view is that those assets will either appropriately price risk and be priced out of CP and possibly default to the base. Or they may in some cases unwittingly or unfortunately clear at CP at a level that does not adequately compensate them for the risk. I mean part of our assumption here is that under either scenario that the decision to cease operations at these facilities will occur before a new build response ever makes it. Because you are either out of the auction and not collecting enough rent or you are getting a knockout blow in the performance three years from now. And that is when you make the decisions to exit and it is presumably before new build is able to come in behind. -------------------------------------------------------------------------------- Unidentified Audience Member [40] -------------------------------------------------------------------------------- Just want to drill down specifically on your Ohio assets. I understand the advantage of where your plants are relative to very variable pipes. But if we fast forward with all the new pipeline built, pipeline reversal, if suddenly we are in an environment where everyone has access to sub $2 gas, what is the risk? What do you think about pricing in that environment? And if you could frame your answer in terms of how much coal generation is actually being supplied into the market today? How much gas capacity is there in the very local markets that could potentially leapfrog any coal generation that is still being done today? -------------------------------------------------------------------------------- Bob Flexon, Dynegy Inc. - President & CEO [41] -------------------------------------------------------------------------------- I will start and then let Hank tag on. But we expect over time as pipelines are built out, that differential advantage should narrow and the negative (inaudible) should flatten out as pipeline capacity is built. Hank, I don't know if you have any specifics on the capacity. -------------------------------------------------------------------------------- Hank Jones, Dynegy Inc. - Chief Commercial Officer [42] -------------------------------------------------------------------------------- Sure, just to tag on to Bob's comment about the (inaudible) of the forward markets for Dominion South in calendar 2016 is just over a negative $1 versus Henry Hub and 2018 it's showing minus $0.70. So it is still viewed as a significant discount to gas at the Henry Hub in Louisiana, but the logical expectation is that gas will be relieved and move out of the system. There is a lot of factors that would tell us that $2 gas generically is an extreme case in the future given how much incremental consumption there is expected to exports to Mexico, exports to LNG, increased petrochem demand and all the gas-fired assets that are going to replace the coal assets. There is a huge uptick in gas demand over the next five years. So I think that provides some support for that floor, presumably at a -- if there was a sustained low cost price it would put a lot of pressure on coal units. But I would say that today we're already experiencing lower than $2 gas up there. We had gas delivered to our facility over the five days of this week at $1.30 to $1.70 per MMBtu. At the same time we are selling on-peak power at $45 plus or minus $5. So there is a huge spark spread. And what that tells me is that the system can't survive without coal being on the margin certain hours. There just isn't enough gas-fired generation to satisfy the system. So the coal units, the cost of those units keeps the power price up. As gas prices drop our spark spreads expand. I would expect that situation to be even more pronounced in the future as the system -- as retirements come into the system. So I think there is an extended -- we are already dealing with under $2 gas; I think there is an extended period of time here where the structural change overwhelms the gas price issue. There is not going to be enough generation during peak times to keep us out of scarcity pricing events, is our view. -------------------------------------------------------------------------------- Bob Flexon, Dynegy Inc. - President & CEO [43] -------------------------------------------------------------------------------- As you said earlier, Hank, we had 8 gigawatts retire in the past month in Western PJM of coal. -------------------------------------------------------------------------------- Jeff Cramer, Morgan Stanley - Analyst [44] -------------------------------------------------------------------------------- Thanks, Jeff Cramer with Morgan Stanley. Just shifting gears a little bit, just touching on IPH, obviously a pretty positive outlook here today. Just curious what in your mind it would take to pull that into the broader Dynegy structure more formally, maybe recognize some of the benefits and what those benefits are. And then, Clint, on the capital occasion it sounds like share repurchases are going to be a big focus. But you also mentioned balance sheet improvements. Can you just kind of discuss what that might entail? -------------------------------------------------------------------------------- Bob Flexon, Dynegy Inc. - President & CEO [45] -------------------------------------------------------------------------------- Well, on the IPH structure ring fence, we have no near-term plans to do anything different with IPH. We have got to get through a few hurdles along the way. We have got the Newton scrubber that needs to be built. The CapEx pull on that is in the -- towards the end of 2017 into 2018 and 2019, we have got the first tranche of debt to refi in 2018. And then we have got to take a look at the environmental CapEx, which I think in Jeff's area he showed separately when you think about 316 B and ELG and CCR that IPH is roughly -- I think it was $230 million -- $250 million of CapEx in the later years. But we will be exceedingly cautious about doing anything that could risk the Dynegy balance sheet. So we would have to see the capacity expectations that we have come through, the energy price volatility or higher prices come through. And a clear path to refinancing the debt in 2018 and meeting our other obligations. So we have got a ways go before that proves itself out. Certainly the outlook today has never been better for IPH and we want to see that continue to go certainly in that direction as we enter these next couple of years. But there is no near-term plan necessarily to change the structure. Regarding the other question around the debt management, Clint, over to you. -------------------------------------------------------------------------------- Clint Freeland, Dynegy Inc. - CFO [46] -------------------------------------------------------------------------------- Yes, I would say that we don't have any specific plans to use any of the excess cash to pay down debt. My only comment around that we may look to refine our leverage over time really is more going to be a function of kind of our future view on earnings and whether or not we are kind of growing into the right statistics. There are a couple of different ways that you can kind of achieve that BB credit metric goal. And if we are growing into the right statistics then I am not sure that there is really anything to do as far as debt pay down. To the extent that that moderates some you may want to pay down a little bit of debt over time. Again, I think we don't have any specific plans to do that, it is something that we are monitoring. But I think that is something that we will have to consider again when we think about prioritization of our capital allocation program, we want to be sure that our balance sheet and our liquidity is in the right place. And we will take a look at that over time to get the specific plans. -------------------------------------------------------------------------------- Mitchell Moss, Lord Abbett - Analyst [47] -------------------------------------------------------------------------------- Mitchell Moss with Lord Abbett. Just a follow-up on the last question. So regarding IPH, does that mean that any excess cash generated we should expect it will stay in the IPH bucket going forward? -------------------------------------------------------------------------------- Bob Flexon, Dynegy Inc. - President & CEO [48] -------------------------------------------------------------------------------- Yes. So the question is with IPH any excess cash flow would stay there. And for the time being that should be the assumption you work under. There is dividend blocks that the debt has already that prevented that we haven't met the threshold to clear those. But I think in the capital allocation chart that Clint showed toward the end of this presentation the assumption around all of that is that all the cash generated IPH -- stayed with IPH to meet its obligations with really no support from the parent. We still continue at the parent level, we see charges for the services that the corporate and operational support group provide. Historically that's been has been about $60 million a year now. With the expanded portfolio I think that drops to about $40 million a year. So that cash continually flows just on a monthly basis to the parent. And that will continue. -------------------------------------------------------------------------------- Mitchell Moss, Lord Abbett - Analyst [49] -------------------------------------------------------------------------------- And just when you think about the Ontelaunee expansion, brownfield expansion, what type of uplift or better power prices or margins are you looking for to make that investment, to make that expansion? -------------------------------------------------------------------------------- Bob Flexon, Dynegy Inc. - President & CEO [50] -------------------------------------------------------------------------------- Well, on the expansion on the Ontelaunee site, having -- I don't know if you are familiar with the site. It's in (inaudible) for right outside of Reading. And it is a piece of property that is vacant next to our plant, I mean it is contiguous, there is no separation by roads or anything that has been developed by (inaudible), has full permits, everything it needs to start construction. We haven't necessarily evaluated at this point in time is it a go or no go to build. The one thing that we felt strongly about is that that site that we share with all of our infrastructure, if anybody should have that property to develop it should be us and recognizing the synergies. We haven't done the math around specifically what would the price have to be. I think more realistically we would have to take kind of a view on the market. I think basically new build economics are roughly -- on a capacity performance level it's roughly $170-ish. Is that fair, Mike, or a little --? -------------------------------------------------------------------------------- Unidentified Company Representative [51] -------------------------------------------------------------------------------- For us. -------------------------------------------------------------------------------- Bob Flexon, Dynegy Inc. - President & CEO [52] -------------------------------------------------------------------------------- Yes, for us roughly $170 a megawatt debt. We still have to refine what capital cost would be. I think you have seen recent discussions in the market, I guess PSEG talked about their -- I think they quoted $1,200-$1,300 per KW construction. I would expect being that we have infrastructure to share that our costs would be below that. But we have to go through all that math to find out where is a sweet spot on that and is that a better alternative to just buying basically the same capacity by buying back our shares. And that is what that is going to have to compete against because that's a fairly intense capital outlay. We would probably end of financing it -- a large portion of it at the corporate level, we would still have to decide whether that is a good use of our free cash flow or not. And that is something that we have got more work to do. We are nowhere near concluding on that. Again, we just wanted to make sure that something is going to be built on that site that we are the ones that are in the best position to do it. -------------------------------------------------------------------------------- Mitchell Moss, Lord Abbett - Analyst [53] -------------------------------------------------------------------------------- Well, in some of those economics that you just mentioned, getting close to the new build, when I look at the incremental case, which is slide 94 or 96, is that -- is the incremental case reflecting something closer to some of those new build economics? -------------------------------------------------------------------------------- Bob Flexon, Dynegy Inc. - President & CEO [54] -------------------------------------------------------------------------------- I would say I just quoted $170, kind of a benchmark ,that we think about where we see new investments come in. I would say showing what are probably more -- our assumptions around that is it's lower than that, it is embedded in this number. -------------------------------------------------------------------------------- Clint Freeland, Dynegy Inc. - CFO [55] -------------------------------------------------------------------------------- What is embedded in the incremental case is our view of how our prices and spark spreads (inaudible). -------------------------------------------------------------------------------- Bob Flexon, Dynegy Inc. - President & CEO [56] -------------------------------------------------------------------------------- Sure, it is at the capacity performance, we have an assumption in there that is lower than the $170 that I quoted. -------------------------------------------------------------------------------- Clint Freeland, Dynegy Inc. - CFO [57] -------------------------------------------------------------------------------- That's right. -------------------------------------------------------------------------------- Bob Flexon, Dynegy Inc. - President & CEO [58] -------------------------------------------------------------------------------- (Inaudible). -------------------------------------------------------------------------------- Clint Freeland, Dynegy Inc. - CFO [59] -------------------------------------------------------------------------------- Across the fleet. -------------------------------------------------------------------------------- Bob Flexon, Dynegy Inc. - President & CEO [60] -------------------------------------------------------------------------------- Yes. -------------------------------------------------------------------------------- Greg Gordon, Evercore ISI - Analyst [61] -------------------------------------------------------------------------------- It is Greg Gordon again, hi. Okay, you just kind of answered one of my questions. Roughly speaking, what is baked into the 1-3? Because there is sort of two levels (multiple speakers) vectors of exposure on CP what is the price going to be relative to what you have as placeholder and how much --? Do you expect as we move through the incremental auctions and through the BRA that you will give us a disclosure subsequent to each auction or subsequent to all three auctions as to what percentage cleared and whether that price was meaningfully different from what you baked into the guidance so we can adjust our expectations accordingly? -------------------------------------------------------------------------------- Bob Flexon, Dynegy Inc. - President & CEO [62] -------------------------------------------------------------------------------- Yes, not to over commit at this point in time, but I would certainly hope we would be able to do that. We recognize, as Hank said, not all of the assets should clear and we will risk adjust our bids. And I would expect we would get some level of transparency on how much cleared, how much didn't, and we could talk about the (inaudible), what is embedded in there. And I do think, to the extent you to have clearing prices, I would expect it would be higher than what is in those cases. But the time it comes to clear and we reach the third-quarter call in November, we should be able to give some level of transparency and what is different than what we assumed at the (inaudible). -------------------------------------------------------------------------------- Greg Gordon, Evercore ISI - Analyst [63] -------------------------------------------------------------------------------- Awesome. And then one last question. The 2016 sensitivity that showed the $10 -- $10 million delta to $1 change in gas, is that simply just a linear calculation? And is that overly simplistic as you get to different breakpoints in gas price? For instance, this year in PJM we had a significant decline in gas without a commensurate decline in power as we hit that sort of coal floor and spark spreads have widened. So if gas were to go up let's say $0.50 you might see spark spreads decline a lot but dark spreads not go up that much. But if guys went up $1.25 you might have a much different response in the market as you get through certain breakpoints on where plants dispatch. So does this scenario analysis take into account the potential nonlinearity of that or is it simply a linear calculation? -------------------------------------------------------------------------------- Hank Jones, Dynegy Inc. - Chief Commercial Officer [64] -------------------------------------------------------------------------------- That is looking at how 2016 forwards have been trading during 2015. And so, to the extent that you do see a change in market dynamics as you were just talking about, that would change that sensitivity. And so, that is what I mentioned that this is what we are seeing, and it certainly could go the other way. But it is something to keep your eye on as to whether or not that relationship continues to hold over time. It very well may not. But that is something that we are seeing today, it is something that is affecting the sensitivity that we provided this morning. But it is something to watch, because to the extent that it does go back the other way, we certainly will be picking that up as we update our sensitivity. But I would not suggest to you, based on what we are seeing today, that that $10 million will necessarily always (inaudible). -------------------------------------------------------------------------------- Angie Storozynski, Macquarie - Analyst [65] -------------------------------------------------------------------------------- Angie Storozynski, Macquarie. So I wanted to go back to slide 96, can we have apples-to-apples comparisons versus what you guys are showing now, which includes the CP payment versus just pure play flat prices for capacity and forward observable curves? How much of this $1,300 in EBITDA has in general for those unpriced products, so EP, MISO, you name it? Can you tell us if it's like $100 million, $200 million roughly? -------------------------------------------------------------------------------- Clint Freeland, Dynegy Inc. - CFO [66] -------------------------------------------------------------------------------- Yes, roughly speaking it is a couple hundred million on average each year. -------------------------------------------------------------------------------- Bob Flexon, Dynegy Inc. - President & CEO [67] -------------------------------------------------------------------------------- Included in that is the (multiple speakers) MISO capacity. -------------------------------------------------------------------------------- Clint Freeland, Dynegy Inc. - CFO [68] -------------------------------------------------------------------------------- MISO capacity, the PJM (inaudible) transitional auction, yes. -------------------------------------------------------------------------------- William Frohnhoefer, BTIG - Analyst [69] -------------------------------------------------------------------------------- Okay. Okay. Secondly, for non-growth CapEx, so inclusive of all of the environmental CapEx, what is roughly the run rate in 2016 and beyond? -------------------------------------------------------------------------------- Bob Flexon, Dynegy Inc. - President & CEO [70] -------------------------------------------------------------------------------- The run rate of CapEx, roughly $250 million. -------------------------------------------------------------------------------- Clint Freeland, Dynegy Inc. - CFO [71] -------------------------------------------------------------------------------- On a maintenance CapEx basis it is roughly $250 million and that may from year-to-year change as outages change over liability (inaudible). -------------------------------------------------------------------------------- Angie Storozynski, Macquarie - Analyst [72] -------------------------------------------------------------------------------- But it doesn't include that environmental CapEx? -------------------------------------------------------------------------------- Clint Freeland, Dynegy Inc. - CFO [73] -------------------------------------------------------------------------------- That is right, that does --. -------------------------------------------------------------------------------- Angie Storozynski, Macquarie - Analyst [74] -------------------------------------------------------------------------------- That does not include it. Okay. -------------------------------------------------------------------------------- Bob Flexon, Dynegy Inc. - President & CEO [75] -------------------------------------------------------------------------------- And Angie, in 2016 you will see in the appendix I think there is like an extra $50 million -- $40 million to $50 million in there for reliability type investments. -------------------------------------------------------------------------------- Angie Storozynski, Macquarie - Analyst [76] -------------------------------------------------------------------------------- Okay, and lastly, this notion that you guys are keeping your energy book open because you are bullish on energy prices. But you are also bullish on capacity prices. So are you bullish on regional gas prices or are you trying to say that despite rising capacity payments and penalties associated with those capacity payments you do not expect a contraction in heat rates? -------------------------------------------------------------------------------- Bob Flexon, Dynegy Inc. - President & CEO [77] -------------------------------------------------------------------------------- Angie, I will take the first shot at that and let Hank tag on after that. But our assumption, and I think what Hank tried to illustrate in his presentation, is that we are not betting on gas doing anything different than what it has been doing. But we have been building our portfolio around and assuming is that the supply-side continues to tighten and the type of assets that are leaving versus the types that are coming in, the generation that's coming in, are very different. And I think Hank illustrated during the polar vortex the response from wind. I think he also illustrated the response that Demand response -- how they have answered the bell with a 70% failure rate. So what we see is there is going to be just points in time when the system is stressed, it's going to be tested like it hasn't been tested for a long time. 8 gigs just left in May out of Western PJM. MISO in a high temperature environment has a reserve margin of 7% to 8% and that is counting on 5 gigs of Demand response showing up which MISO has no control on whatsoever. So our fundamental thesis behind keeping the energy price portion open is that the supply-side is very different than what it has been and it is going to be stressed, it is going to cause volatility. And during those periods of volatility will be the time to layer on additional hedges, not when weather is soft and gas is kind of trading with the malaise of the weather and the sentiment that we are going to have a cool summer or a warm winter. But when the system gets stressed is when you will see us adding on positions. Hank, anything to add to that? -------------------------------------------------------------------------------- Hank Jones, Dynegy Inc. - Chief Commercial Officer [78] -------------------------------------------------------------------------------- No, thank you. -------------------------------------------------------------------------------- Unidentified Audience Member [79] -------------------------------------------------------------------------------- One last one, I swear. -------------------------------------------------------------------------------- Bob Flexon, Dynegy Inc. - President & CEO [80] -------------------------------------------------------------------------------- How many questions does Julien get? Rule number two (laughter). -------------------------------------------------------------------------------- Julien Dumoulin-Smith, - Analyst [81] -------------------------------------------------------------------------------- Quick clarification on the last one really, what is the profile of that [1.3]? You talk about an average over the next three years. Is it fairly flattish over the next three years, the 1.3, or is there Contango built in there? Especially given the synergy targets you talked about, locking in capacity, hedges rolling off, lots of different moving pieces. Net-net, what do you see? -------------------------------------------------------------------------------- Bob Flexon, Dynegy Inc. - President & CEO [82] -------------------------------------------------------------------------------- I would say that there is some level of Contango but it is not meaningful. It is not a dramatic change from 2016 to 2018 in the base case. There is a Contango to it, but it is not really significant. -------------------------------------------------------------------------------- Julien Dumoulin-Smith, - Analyst [83] -------------------------------------------------------------------------------- Perhaps said differently, you have got $200 million -- or a couple hundred million every year in potential locked in -- or potential to be locked in capacity that we just spoke about a second ago. -------------------------------------------------------------------------------- Bob Flexon, Dynegy Inc. - President & CEO [84] -------------------------------------------------------------------------------- So I guess I was talking to the overall number -- not necessarily to the specific capacity component of that. I mean remember that over the next -- over that timeframe Brayton point is going out. You have got our California contract that is expiring at the end of 2016. You have got a number of factors that are kind of coming out, but then there are other adjustments also coming in. So again, I would say overall that the trajectory, that there is a slight Contango to the numbers through time, but it is not a significant one. -------------------------------------------------------------------------------- Julien Dumoulin-Smith, - Analyst [85] -------------------------------------------------------------------------------- Right. So like less than $100 million or something like that? -------------------------------------------------------------------------------- Bob Flexon, Dynegy Inc. - President & CEO [86] -------------------------------------------------------------------------------- I would say that is kind of a reasonable --. -------------------------------------------------------------------------------- Julien Dumoulin-Smith, - Analyst [87] -------------------------------------------------------------------------------- Okay, great, thank you. -------------------------------------------------------------------------------- Unidentified Audience Member [88] -------------------------------------------------------------------------------- Okay, thanks. I had a question about the retail business, maybe it is for Sheree and maybe Julius on the regulatory side. Obviously it is a much smaller business than the commercial business. But it obviously has a strategic advantage, as you mentioned, with the load volume, the ability to capture higher margins and the natural hedging. So I am just curious about some of the risk and opportunities in that business. On the regulatory side, for example, are there any regulatory risks in terms of potentially reducing competition? At the same time, I would see regulators might view it positively that you could potentially offer lower prices or create an environment of lower prices for consumers. And then just -- obviously (inaudible) a smaller side of the business. Bob mentioned the potential to put the PB on some available space on the Illinois site. I am just curious, is that part of your strategy of bundling services, is that kind of how you see that? -------------------------------------------------------------------------------- Bob Flexon, Dynegy Inc. - President & CEO [89] -------------------------------------------------------------------------------- Sheree, did you catch all of it? -------------------------------------------------------------------------------- Sheree Petrone, Dynegy Inc. - EVP, Retail [90] -------------------------------------------------------------------------------- Yes. So (inaudible) your first question was about regulation and whether or not there is any risk of reregulation or something like that in the retail markets. I guess I would say that retail markets are successful because wholesale markets are and vice versa. So they go hand-in-hand. So to the extent that we have a lot of work that we are doing in the wholesale environment to protect the market, that is very helpful to maintaining a structure for the retail side. And we talk to the regulators quite often as well and in the markets where we compete the regulators and the states are very interested in regulation. They see the value of competition to provide good price for customers. And then the second question, as far as whether or not we get into clean energy products or such for retail customers, we sell a lot of RECs or renewable energy credits to our retail customers that are voluntary purchases. There are certain communities that are extremely interested in having green energy. So that is why we are looking on the strategic side about what sorts of things could we do as a generator in that space. And we are not -- we are probably not taking an approach that a lot of our competition does to really get into the customer side, sort of value added products and services related to that are getting into rooftop solar or those sorts of things. But we are trying to look at ways where our generation and the things that we can do to enhance our generation suite could add value to our products that we offer to customers. So, we are thinking about it. We're just not quite sure how it fits with the generator because we are not interested in some of those other types of things that retailers with a lot of value added services do. -------------------------------------------------------------------------------- Unidentified Audience Member [91] -------------------------------------------------------------------------------- Thank you. -------------------------------------------------------------------------------- Bob Flexon, Dynegy Inc. - President & CEO [92] -------------------------------------------------------------------------------- Thanks, Sheree. I mean retail or anything like that would have to compete against capital just like everything else. Just because we like Sheree doesn't mean she has to get any special favors. Andy, how are we on time? -------------------------------------------------------------------------------- Andy Smith, Dynegy Inc. - Managing Director, IR [93] -------------------------------------------------------------------------------- (inaudible) we have got time for one, maybe two more questions. -------------------------------------------------------------------------------- Bob Flexon, Dynegy Inc. - President & CEO [94] -------------------------------------------------------------------------------- Okay. Anymore? A question up front. -------------------------------------------------------------------------------- Evan Kramer, Silver Point - Analyst [95] -------------------------------------------------------------------------------- Evan Kramer, Silver Point. You see from 2014 to your 2016 to 2018 estimated average that the O&M per megawatt hours actually stepping up despite the fact see synergies coming in and the price savings coming in. Is there still meaningful difference in the O&M per megawatt hour on the Duke and EPC side of the house versus the legacy Dynegy and IPH portfolio? -------------------------------------------------------------------------------- Bob Flexon, Dynegy Inc. - President & CEO [96] -------------------------------------------------------------------------------- I would say not so much on the ECP side of the house, maybe that is obviously heavy gas weighted and tends to have less. On the Duke or the coal portfolio within the Duke assets is where more of the opportunity but certainly (inaudible). I don't know if there is any --. -------------------------------------------------------------------------------- Evan Kramer, Silver Point - Analyst [97] -------------------------------------------------------------------------------- Could you speak to any specific numbers or -- at this time? -------------------------------------------------------------------------------- Bob Flexon, Dynegy Inc. - President & CEO [98] -------------------------------------------------------------------------------- In terms of the cost per megawatt on [those deals]? Is there anything particular? -------------------------------------------------------------------------------- Sheree Petrone, Dynegy Inc. - EVP, Retail [99] -------------------------------------------------------------------------------- No, I mean I do know we are looking specifically at Zimmer and --. -------------------------------------------------------------------------------- Unidentified Company Representative [100] -------------------------------------------------------------------------------- The liability issues at Zimmer in particular probably raise that level up a little bit. -------------------------------------------------------------------------------- Bob Flexon, Dynegy Inc. - President & CEO [101] -------------------------------------------------------------------------------- Yes and that is probably the biggest -- maybe the biggest impact of all is just when you look at the denominator, the liability hours should be much higher. Because you take a couple of the units and have forced outages, right? We talked about Zimmer having some of the most opportunity of the forced outage rate of 25%. -------------------------------------------------------------------------------- Unidentified Company Representative [102] -------------------------------------------------------------------------------- North of 20%. -------------------------------------------------------------------------------- Bob Flexon, Dynegy Inc. - President & CEO [103] -------------------------------------------------------------------------------- So that plant should not be having a planned availability factor of 70% which is where it is today. It should be up where the rest of the fleet is up closer to 90%. So I would say that the Duke portfolio historically has relied more on contractors than what we do, and that might have some cost impact. I think the other element and probably the bigger half of it is the amount of megawatt hours you are getting out of the units. -------------------------------------------------------------------------------- Bob Flexon, Dynegy Inc. - President & CEO [104] -------------------------------------------------------------------------------- One final question? Maybe not. Again, I would like to thank everybody for hanging in there with us and going through 100 plus PowerPoint slides. We appreciate your support and attention. Thank you.
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