DYN - NASDAQ

Hello and welcome to the Dynegy Incorporated Fourth Quarter and Full Year 2015 Financial Results Teleconference. Please note that all lines will be in a listen-only mode until the question-and-answer portion of today's call. [Operator Instructions] I would now like to turn the conference over to Mr. Rodney McMahan, Managing Director for Investor Relations. Sir, you may begin.

Thank you,

Thank you, Rodney. Good morning, and welcome to our yearend earnings presentation. Today's call will also address this morning's announcement of our joint venture formation with Energy Capital Partners, or Energy Capital, and the acquisition of the ENGIE U.S. fossil portfolio. I will begin with the results but will keep my remarks brief to in order allow sufficient time to discuss the acquisition. 2015 marked a number of significant achievements for Dynegy. We successfully integrated two large acquisitions, doubling the company's generation footprint in two of the best competitive power markets in the U.S. We achieved $155 million in synergies, well in excess of our original $65 million target. We secured almost $2.4 billion in future capacity revenues for planning years 2016/2017 through 2018/2019 as a result of the introduction of the capacity performance product in PJM and completion of the ISO-New England capacity auction for 2018/2019. We have sold almost 4,000 megawatts of MISO capacity prior to the upcoming auction through multiple channels. Just yesterday, IPH secured a multi-year, 959 megawatt retail transaction, locking in approximately $152 million in capacity revenues over the next three planning years. We've completed PRIDE Accelerated one year ahead of schedule, meeting our 2014/2015 adjusted EBITDA target contribution of $135 million and exceeding our 2014/2015 balance sheet target of $165 million by $81 million. We launched the next generation of PRIDE, PRIDE Energized during the third quarter, with the objective of achieving $250 million of EBITDA improvements and $400 million of balance sheet improvements during 2016 to 2018. And finally, we initiated in the third quarter and completed in the fourth quarter a $250 million share repurchase program. Dynegy reported 2015 adjusted EBITDA of $850 million and $186 million of free cash flow, both within the guidance range. The newly acquired assets contribute almost $600 million of the uplifted results, with almost 90% derived from the natural gas fired CCGT fleet in PJM in New England. Our fleet benefited from access to ample low-cost natural gas and the strong 2015 spark spreads drove every PJM CCGT in our fleet to an annual generation record. The strong energy margin contribution at the gas segment combined with the higher market capacity revenues more than offset the expiration of the ConEd capacity contract at Independence. Results in our MISO coal fleet were mixed. Energy margins declined year-over-year as unusually mild weather drove a decline in Indy Hub prices of approximately $8.50 per megawatt hour. Realized prices benefited from hedges, but the decline in the marketplace has also resulted in more of our generation hours being uneconomic. The increase in uneconomic hours lowered 2015 generation by 16% at the MISO coal segment and 22% at IPH. Offsetting the decline in energy margins was an increase in capacity revenue as we continue to expand our MISO capacity sales through our various channels to market. We've updated our 2016 adjusted EBITDA guidance to a range of $1 billion to $1.2 billion from our previous range of $1.1 billion to $1.3 billion and updated the free cash flow range to $200 million to $400 million from our previous range of $300 million to $500 million. The change in guidance was driven by a decline in commodity markets since we introduced 2016 guidance in November. While it is still early in the year with 10 months remaining, we felt it was prudent to revise guidance even though we are currently around the $1.1 billion bottom of the original range due to two factors. The first, a significant portion of the decline in 2016 pricing impacted the first quarter, which is the most significant quarter in the year. And second, given the transaction announced today, the Company will be accessing capital markets to raise capital for the joint venture with Energy Capital later this year, and we believe it is important to provide investors an updated view of Dynegy's outlook in light of the upcoming capital markets activity. Moving on to the acquisition and the formation of our joint venture with Energy Capital, please turn to slide 2 of the transaction announcement slide deck. We will start today's presentation with a transaction overview to address the acquisition, the joint venture, and financing for the transaction. We will then cover the combined Company's presence in the best U.S. markets, expected synergies from the transaction, and the benefits of utilizing the scale of the Dynegy platform. We will then offer some concluding remarks and open the session up for Q&A. Slide 4 provides the highlights of the acquisition and JV. First of all, this transaction is at a compelling valuation and when combined with the Dynegy platform, will capture approximately $90 million of synergies, thus creating substantial value for our shareholders. This transaction provides Dynegy with an unmatched portfolio, uniquely positioned for the long-term in premium markets. The addition of the high-quality ENGIE fleet increases Dynegy's presence in two key competitive U.S. power markets and provides an entry into ERCOT with scale. The ENGIE fleet is a clean portfolio, as over 90% of the generating assets are comprised of natural gas-fired generation. This expands Dynegy's CCGT fleet, and nearly 50% of our pro forma capacity will be from combined cycle units. With capital markets virtually closed at this time, substantial care in structuring the acquisition of the JV was taken in order to limit the equity being issued by Dynegy and limit the use of Dynegy's liquidity. Leverage at the JV initially will be about five times debt to EBITDA but is expected to drop below four times by 2018 as a result of increasing capacity payments that have previously cleared the market in PJM and ISO-New England. And to reiterate my initial comment, this transaction offers a compelling value to our shareholders. This transaction is expected to close in the fourth quarter following approval from FERC, the Public Utility Commission of Texas, and expiration of the Hart-Scott-Rodino waiting periods. Turning to the transaction overview on Slide 6, the JV is acquiring the ENGIE assets at an attractive valuation of approximately 5.7 times 2018 adjusted EBITDA, or $378 per kW, well below recent comparable transaction multiples. The transaction is also accretive to both free cash flow and EBITDA per share. To execute this transaction, Dynegy is forming a joint venture with Energy Capital, and it will be a nonrecourse to Dynegy. Dynegy will own 65% of the JV and manage and operate the assets. The initial equity contribution before transaction fees and initial cash funding is $1.05 billion. Dynegy's share of $683 million is sourced by selling to Energy Capital $150 million of Dynegy Inc. equity and the remainder from internal resources, including the monetization of future PJM capacity sales and general corporate liquidity. Energy Capital's $150 million share purchase is based on a trailing 45-day volume weighted share price of $10.94 per share that will result in the issuance of 13.7 million shares of Dynegy common stock at closing. Together with shares already owned, Energy Capital's ownership in Dynegy is expected to be about 15% post-closing. As part of our agreement with Energy Capital, as long as their ownership at the Dynegy level exceeds 10%, they will be allowed to nominate one director to Dynegy Inc.'s Board. At the JV level, there is an established put/call structure that we will review in more detail later, but it provides a mechanism through which Dynegy can be the 100% owner over the longer term. Finally, we have committed financing in place to close the transaction. Our committed financing consists of secured financing as well as a bridge loan for managing capital. But as Clint will discuss later in the presentation, we will look to optimize the debt financing at the JV as we approach the close of the transaction. The bridge financing provided by Energy Capital is a critical element in the committed financing plan, given the largely unavailable state of the unsecured high-yield market. Slide 7 provides an overview of the ENGIE portfolio. ENGIE's 8,700 megawatts are comprised of approximately 1,400 megawatts in ISO-New England, or 16% of its capacity; 2,800 megawatts in PJM, or 32% of its capacity; and 4,600 megawatts in ERCOT, or 52% of its capacity. The ENGIE portfolio is also a compelling mix of fuel type and technology. Over 90% of its capacity is modern natural-gas-fired capacity, with two-thirds of its capacity comprised of combined-cycle units. Looking closer to ENGIE's market presence, its assets are well positioned in each of its markets. In New England, the fleet is comprised entirely of combined-cycle units that are located in Southeast Massachusetts, concentrated near load centers. In PJM the fleet consists of approximately 500 megawatts of combined-cycle unit capacity, with the balance primarily comprised of natural-gas-fired CTs. The CTs in the portfolio are well positioned in PJM from several perspectives. First, each of the CTs is close to a PJM load center. Second, all of the CTs have fast ramp times that are in the top quartile of PJM peaking units, which is a critical attribute on the PJM capacity performance construct. Third, three of the four CTs have dual-fuel capability, which is another critical attribute under the PJM capacity performance construct. Finally, two of the four CTs have advantageous access to low-cost natural gas, which positions them competitively in the dispatch stack relative to other peaking units. The ERCOT fleet consists of almost 85% combined-cycle unit capacity and are all relatively new assets, constructed in the 2002 to 2004 time frame. The assets also run with relatively high capacity factors of 50% to 70% and are positioned close to the Houston and Dallas load centers. Slide 8 provides a look at the expected synergies from this transaction. With the addition of the ENGIE portfolio, Dynegy's generating capacity combined with the JV increases to approximately 35,000 megawatts, and with that increased scale and scope we expect to initially achieve $90 million in synergies or $10 per kW. Of the $90 million, $60 million will be achieved on day one with the elimination of duplicate corporate support. Other synergies including negotiating reduced costs under the long-term service agreements, reducing plant insurance premiums, and securing procurement savings. Dynegy has successfully integrated three portfolios over the past few years. With this experience we have consistently founded that upon closing a transaction and owning the assets for a period of time, we are able to identify additional synergies through operating and commercial opportunities. We do not expect anything different with the ENGIE transaction. Additionally, we will expand Dynegy's PRIDE program, our continuous improvement initiative, to the acquired fleet, where we will pursue additional cost savings as well as gross margin expansion opportunities. The ENGIE fleet in Texas is well positioned to benefit from ERCOT's current transition from relying on baseload generation to moving towards low-cost, reliable plants that are able to complement the growing goal of non-dispatchable, renewable energy in Texas. The regional haze rule, low gas prices, the lack of a capacity market, and the growing impact of wind energy all contributed to putting 4 to 6 gigawatts of unscrubbed coal and 2 gigawatts of steam units in ERCOT at risk of retirement in the next 3 to 5 years. With approximately 16 gigawatts of installed wind generation and a growing solar footprint, ERCOT's growing reliance on intermittent resources puts further pressure on the non-flexible inefficient plant. ENGIE's 3,800 megawatts of CCGTs in ERCOT are well-placed to be rewarded in this environment due to their flexibility, efficiency, scale, and location near load centers in Texas. With approximately 50% of the ENGIE portfolio in ERCOT, evaluating the cost of entry into that market was a key consideration for us. Slide 10 highlights the implied purchase price for the ERCOT assets. In this analysis we assume the weighted average purchase price per kW of recent transactions in ISO-New England and PJM. Applying these values to the ENGIE footprint in those markets implies a purchase price of approximately $2.3 billion for the ISO-New England and PJM portfolios. This results in a residual implied purchase price for the ERCOT assets of approximately $1 billion. Assigning no value to the Coleto Creek coal plant and the Warden County peaker, the implied purchase price of the ERCOT portfolio is approximately $254 per kW, which represents a material discount of almost 50% to the last two CCGT merchant sales in ERCOT, executed at approximately $475 per kW. At this point, I will hand it over to Clint to walk through the financial profile of the business going forward.

Thanks Bob. The joint venture's financial profile for the next couple of years is reflected on Slide 11. And as you can see, we expect the business to generate significant EBITDA and free cash flow going forward. Based on our forecast for the business, we expect the joint venture to generate $425 million to $475 million in adjusted EBITDA during 2017, rising to $550 million to $600 million in 2018. Based on this and making certain assumptions around financing costs, we expect the joint venture to generate $25 million to $75 million in free cash flow in 2017 and $300 million to $350 million in 2018. Both adjusted EBITDA and free cash flow are expected to increase meaningfully from 2017 to 2018 for two reasons. First, capacity of revenues in PJM and New England increased by about $85 million year over year, increasing the portion of gross margin coming from capacity revenues to roughly 40% in 2018 and accounting for a majority of the increase in adjusted EBITDA between the two years. At the same time, CapEx will decline meaningfully in 2018, back to a more normalized level after being elevated in 2017 as a result of a peak outage schedule which includes almost $100 million in spend on steam turbine outages and generator outages, which are typically on a 10- to 15-year outage cycle. Based on the midpoint of these ranges, we see compelling value in the acquisition, with a 2018 EV to EBITDA multiple of 5.7 times and a 2018 free cash flow yield on the joint venture equity investment of approximately 30%. Additionally, the balance sheet de-levers quickly as a result of increasing EBITDA and excess cash flow sweeps reducing debt outstanding, resulting in a 2018 gross debt to EBITDA below four times. Formation of the joint venture with Energy Capital was a key element in successfully executing a committed financing package for the acquisition given the challenging capital market environment. Slide 12 outlines the structure and capitalization of the JV, and there are a number of things that I would highlight. First, from a governance standpoint, the joint venture will have a five-person Board of Directors, with Dynegy nominating three directors and Energy Capital nominating two. And Dynegy will be charged with managing the day-to-day operations of the business. Consistent with their proportional ownership of the business, Dynegy will contribute $683 million in equity to the joint venture, and Energy Capital will contribute $367 million. The $1.05 billion total will be used together with the committed financing to purchase the ENGIE fossil assets. Dynegy and Energy Capital will contribute a further $135 million in total to fund transaction costs and initial working capital for the entity, and Dynegy will provide the JV with a $100 million line of credit, should it be needed. Additionally, the seller agreed to provide collateral support for all hedges and contracts existing at the time of transaction closing for an agreed-upon period of time. While the joint venture will be established with Dynegy having a 65% interest and Energy Capital having a 35% interest, we have agreed to put and call provisions which are ultimately designed to give Dynegy the option to consolidate its ownership in the business to 100% while simultaneously providing Energy Capital with the investment liquidity that it needs to be a minority partner. Under these put/call provisions, Dynegy has the right to purchase Energy Capital's stake in the joint venture at any time at a price equal to the higher of two amounts. The first uses the average of the trailing 12-months and next 12-months joint venture EBITDA, multiplied by Dynegy's then-current EV to EBITDA trading multiple. The second is 2.25 times Energy Capital's initial investment in the joint venture, net of any cash dividends, plus any incremental equity contributions. Conversely, Energy Capital has the right to monetize its investment in the joint venture four years post-closing. At that time, Energy Capital has the right to notify Dynegy of its desire to exit the joint venture, at which time one of several courses of action can be taken. First, Dynegy can elect to acquire 100% of Energy Capital's interest in the joint venture at a price equal to the average of the trailing 12-months and next 12-months joint venture EBITDA, multiplied by Dynegy's then-current EV to EBITDA trading multiple. For Energy Capital's put right, there is no minimum floor price, as there is in the call option held by Dynegy. If Dynegy elects not to buy 100% of Energy Capital's interests, the second option would be that Dynegy could elect to acquire only 50% of Energy Capital's interest in the venture, using the same formula above for valuation. If Dynegy makes this election, Energy Capital will then have the ability to put their remaining interest in the joint venture to Dynegy 12 months later. In the event that Dynegy is unable or unwilling to purchase either 100% or 50% of Energy Capital's interest in the joint venture when the initial notice is given, the third option would be for Energy Capital to exercise its right to require a sale of the entire joint venture. While our strong desire at this point is to ultimately consolidate Dynegy's ownership in this entity, this put right has been designed to protect Dynegy from any owner risk debt-like obligation in the event that it does not have the financial wherewithal at the time to acquire Energy Capital's interest. Slide 13 outlines the sources of funds for the transaction purchase price. While we intend to access the capital markets to raise permanent debt financing, we have arranged committed financing at this point to ensure availability of capital at closing. As mentioned earlier in the presentation, the joint venture has secured $2.25 billion in debt financing, including a $1.85 billion nonrecourse secured debt facility from a consortium of relationship banks and a $400 million junior bridge facility from Energy Capital. On the Energy Capital bridge, there are no upfront fees and no prepayment penalties in the event the bridge is used. And if it is used, it has a four-year maturity, and interest accrues at 11%. Energy Capital financing has a payment-in-kind feature for interest payments, which the JV can use to manage cash flow if needed. If the Energy Capital bridge is drawn but has not been refinanced by the one-year closing anniversary, the note may be: one, repaid on a pro rata basis by the members; two, converted into equity of the joint venture by Energy Capital; or three, remain outstanding through the fourth anniversary of closing at a higher rate of interest. This bridge commitment is designed to allow the joint venture to maximize the amount of third-party secured debt available to it, which is helpful in this difficult capital market environment. And it also provides the joint venture with the ability to close the transaction without having to access the unsecured high-yield market if it remains challenging. It also provides risk mitigation to Dynegy in the event that the bridge cannot be refinanced and Dynegy does not have the capital to repay its share of the financing at the time. To partially fund Dynegy's equity commitment to the joint venture, Dynegy will issue 13.7 million shares of common stock to Energy Capital at an average price of $10.94 per share for aggregate proceeds of $150 million. Dynegy is also pursuing the sale of up to $200 million, or approximately 18%, of its PJM capacity revenues for planning years 2017/2018 and 2018/2019, bringing forward that revenue and allocating those dollars to this investment. Based on our current forecast, we would expect future dividends from the joint venture in 2017, 2018, and 2019 to equal or exceed the capacity revenues monetized as part of this financing. The balance of Dynegy's equity will be funded from Dynegy's general liquidity, which will not only be enhanced by free cash flow throughout 2016 prior to closing, but also by an incremental $50 million credit facility provided by one of our relationship banks. I would also note that Dynegy Inc.'s interest in the joint venture will be added to the parent Company's collateral package for the benefit of its senior lenders. In summary, the financing plan for this acquisition has been constructed to achieve a number of objectives, including: first, minimizing the issuance of Dynegy equity; second, maximizing the amount of nonrecourse secured debt with prepayment flexibility that can be accessed by the joint venture in light of current market conditions in the high yield capital markets. Third, establishing a leverage profile for the venture that is reasonable at closing and improves meaningfully over time; and, finally, managing future financial commitments of Dynegy to ensure that we have multiple options depending on opportunities and challenges at the time. With that, I will turn it back to you, Bob.

Thank you, Clint. With the ENGIE acquisition is another step in Dynegy's pursuit towards creating the premier independent power producer. The footprint of the combined company, as shown on Slide 15, the pro forma Company will own approximately 35,000 megawatts with scale in the best competitive power markets in the U.S. The combined company's capacity will be comprised of approximately 60% natural gas-fired generation and approximately 40% coal-fired generation, with significant diversity across power markets. PJM, the best competitive power market in the US with the most constructive capacity market design, comprises over 40% of the pro forma Company's capacity, with the rest of the portfolio evenly balanced between multiple competitive markets, none of which represent more than 20% of capacity. Our facilities are located close to load centers, and a number of them have access to low-cost natural gas in the Marcellus and Utica regions as well as good access to pipeline supply. The Company's expanded footprint in PJM will now consist of 78 units with the addition of 18 PJM units from the ENGIE fleet. The addition of this fast-ramping, dual-fuel peaking capacity in PJM enhances the Company's ability to benefit from PJM's capacity performance product. Our entry into ERCOT brings the benefit of additional market diversification. And while ISO-New England is very much a winter peaking system, the opposite is true for ERCOT, as it is very much a summer peaking system, providing further balance to the fleet. The acquisition of the ENGIE portfolio is also another step in the evolution of Dynegy, as shown on slide 16. Looking back to 2013, Dynegy was comprised of approximately 10,000 megawatts, with 65% of its capacity concentrated in California and Illinois. The acquisition of IPH increased the Company's exposure to MISO, which, as we have discussed previously, has a challenging capacity market construct. Southern Illinois, where our MISO coal fleet is located, is surrounded by regulated utilities that do not compete economically, as the regulated utilities are compensated under a regulated construct. The acquisition of the Duke Midwest fleet and EquiPower significantly expanded Dynegy's presence in the attractive PJM and ISO-New England markets, while reducing the Company's exposure to the challenging MISO market. As demonstrated in our 2015 earnings results, the expanded combined-cycle fleet from of the Duke and EquiPower transactions position the Company well to benefit from the low-cost natural gas supply in the Marcellus and Utica regions that has developed in recent years. The ENGIE acquisition builds upon this transformational trend by strengthening the Company's position in PJM and New England and establishing a new position in ERCOT and further reducing the relative significance of MISO in California. Turning to Slide 17, Dynegy has a successful track record of identifying and delivering on significant acquisition synergies. We exceeded our initial synergy targets in the previous transactions and integrated three portfolios into the Dynegy platform. Two key factors facilitate our ability to execute on delivering synergies. The first is our disciplined, programmed approach to integrating newly acquired assets into our portfolio, and rule number one in that approach is quite simple: one system, and it is Dynegy's. Letting legacy systems and legacy processes linger only in impedes the realization of synergies. The second, as mentioned earlier, is the benefit from post-closing ownership and the benefit of increased access to the newly acquired portfolios. Initial synergies by necessity are developed from an outside perspective looking in. Upon taking ownership of the assets, we are relentlessly focused on optimizing the assets both commercially and operationally, with an eye towards driving inefficiencies out of the system, reducing costs, capturing gross margins improvements. Corporate overhead savings are typically a key source of transaction synergies, and in our past transactions the elimination of corporate overhead represented 40% to 50% of initial synergy targets. In this transaction, it is important to note that the elimination of corporate overhead represents approximately 70% of our initial synergy target in this transaction, and nearly 100% of this will be eliminated day one. If we calculate the benefit of synergies on a dollar-per-KW basis, we achieved approximately $20 per KW in synergies with our IPH acquisition and then approximately $12 per KW in synergies with our Duke and EquiPower acquisitions. Our initial synergy target we are announcing today represents about $10 per KW. Dynegy has leveraged its platform to become the premier low-cost operator as we have built the fleet, as shown on slide 18. Looking back to 2010, before we launched our PRIDE program or executed any acquisitions, our G&A stood at over $3.50 per megawatt hour. And our O&M cost per megawatt hour was over $8.50. If you put this in context of an energy margin per megawatt hour, a cost structure of this magnitude was a significant drag on the profitability of the Company. Our cost structure is materially different today. Through a combination of disciplined growth and cost management and our PRIDE program, we have driven the G&A per megawatt hour at Dynegy below $1 per megawatt hour, reducing G&A per megawatt hour by approximately 75% versus 2010. Over that same period we reduced O&M per megawatt hour to approximately $7.25 per megawatt hour, or a reduction of approximately 15%. These reductions translate into significant shareholder value, as significantly more EBITDA and free cash flow is generated per megawatt hour with Dynegy's low-cost portfolio. Turning to our conclusions slide on slide 19, this transaction represents the right assets in the right markets, with the right structure, and at the right price. The ENGIE portfolio improves the combined fleet's longevity and environmental profile, given that the fleet we are acquiring is largely modern, clean natural-gas-fired capacity. The transaction also expands Dynegy's presence in PJM, ISO-New England, and establishes a scale position in ERCOT -- three of the best competitive power markets in the US. We are also acquiring ENGIE with the right structure, as the formation of the joint venture with Energy Capital protects the Dynegy balance sheet, facilitates financing in a period of challenging capital markets, and minimizes the Dynegy Inc. equity required to fund the acquisition. Turning to the future, we will look to continue to refine the portfolio to its core assets and core markets as well as optimize the portfolio to drive down leverage. To conclude as I started, this transaction offers a compelling value proposition to Dynegy shareholders. At this point,

Certainly. We'll now begin the question-and-answer session. [Operator Instructions] And with that, our first question comes from the line of Mr. Jonathan Arnold of Deutsche Bank. Sir, your line is open

Good morning, guys.

Good morning, Jonathan.

Good morning, Jonathan.

Just a quick one on -- you gave a lot of details on the financing of the ECP bridge. Can you give any details of the bank's financing commitment, costs thereof, and maybe its term? How long do you have to get the permanent financing done?

Yes, so Jonathan, it's a $1.85 billion secured financing structured as a term loan, but can be flexed into -- a portion of that could be flexed into bonds. The reason that we structured it that way was to have flexibility to refinance that out to the extent that we needed to. From an indicative pricing, I think the indicative pricing is around L plus 5.25%. With flex up to, I think maybe, another 2.75%. And OID, I believe, is maybe 98 on the indicative pricing. And that could be flexed as well.

Okay. But your intent is to finance this in the market before close.

That's right. No, we look at this as a backstop financing to ensure that we have the money to close, but I think our plans for this would be to ultimately take this out and replace it in the capital markets.

And I am not -- did you comment on the question on how long this would run for? You said a portion of it is flexible into bonds.

Yes. It is just one of the flex terms. Again, what we tried to do is to maximize the amount of secured capacity available to the joint venture. And that's one of the provisions that was necessary.

Okay. So -- but how long could this $1.85 billion be outstanding should it need to be? Can we just answer that one?

Yes, yes. I'm sorry. So -- and you are asking in the event that it is actually drawn?

Yes.

Yes. I think it is a seven-year facility.

Okay. Great. And that's the full amount, not just a portion.

That's right.

Okay. Sorry. Another question: you mentioned at one point -- I think Bob mentioned this there would be free cash flow up from the joint venture, and it would be potentially roughly equivalent to the $200 million of PJM capacity financing. So is that -- should we be anticipating, like, $100 million a year dividend out of the JV? Are there any restrictions on that in the financing terms? Any more color you can give on that?

Yes. I guess our -- the backstop financing, and I think our assumption in that, is that there is a 50% excess cash flow sweep from the joint venture. And so I think, as we go forward, particularly starting in 2018; in 2017, again, there is a lot of CapEx there and so the free cash flow is being generated, but at a lower level. But stepping up into 2018 and beyond, particularly given the capacity revenues, our expectation obviously is that there is a significant free cash flow generation. The assumption is that 50% of that gets swept to repay the debt, and that the balance is dividended out to the partners based on the pro rata ownership. And when you kind of look through all of that, that order of magnitude of what you were just talking about, $100 million a year or so from 2018 and beyond is about the level that we would expect, based on what we see today.

Okay. Perfect. Thanks very much for that. And then if I may, just on one other topic: you didn't say much about your strategy for getting approval and potential market power concerns, particularly, I guess, New England and maybe PJM, but where you are going to have much bigger positions. Could you speak to that a little?

Yes, Jonathan. We have done the screens, and we have worked with the outside firm that does this work with us. And generally it screens pretty clear. There is potentially a little bit of mitigation that could possibly -- that we view could possibly be needed in Connecticut, just because when you look at the existing holdings of Energy Capital, they have a small unit there that they own through Wheelabrator. There could be some mitigation that needs to be done to address that. But largely it screens pretty clear throughout PJM and the vast majority of New England.

Great. Okay. Well, thank you; I will let someone else go. Thanks a lot.

Okay. Thanks Jonathan.

Thank you. And our next question is coming from the line of Mr. Steve Fleishman. Sir, your line is open.

Just first, you mentioned capital markets access in terms of the guidance update. Is that mainly related to this bank financing that you want to come to market with? Or is there some other capital markets financing in there?

No, that is right, Steve. We view it as if, you know, we were going to be going out and raising capital during the year. So when we took a look at guidance, we thought, since we were bouncing around towards the bottom of the range, it would be appropriate to do a slight adjustment in the light of capital raise for the joint venture.

Okay. Okay. And then, secondly, the $400 million of your equity investment that is coming from your general liquidity -- should we assume that is the use of the $300 million free cash midpoint that you have, roughly, for 2016? Kind of think about it that way?

Yes. That's a fair assumption, Steve.

Yes, Steve. I would view it as kind of a combination of cash balance and potentially some revolver draw to fund that.

And one other point on that, too, Steve, is that we are increasing the revolver at the parent level as well. That is being increased as part of the transaction as well.

Okay. And then, the PIK loan or the bridge loan that could be PIK, just -- there is that provision where it could -- you had mentioned could be become equity in the JV. Could you give a little more detail on how that -- if it ended up being that, how that would work?

Yes. This instrument has been designed where it is obviously a bridge component of the financing, and it exists for 12 months post-closing before it could potentially be converted to equity. And if it is converted to equity, I think the ratio is for every $1 of debt, it converts to $1.50 of equity. So it is an expensive piece of paper if it gets converted down to equity. So certainly our objective here will be to take that piece of paper out. But I would say that bridge financing was the key element in this transaction -- because, as you know, the capital markets really are not available. And to be able to put in place something that has a no-call provision, no fee -- it really facilitated getting this transaction done rather than trying to force an unsecured bond in that you would have to live with for seven years at double-digit interest rates with call provisions. So it is -- actually, it is a very good piece of paper, but you want to take it out within the first year.

Okay. Before this deal, even though you talked -- your megawatts have been about 50%/50% gas/coal, I think you have talked about 80% to 90% of your EBITDA and free cash coming from the gas plants. With this transaction, maybe is it -- you gave it -- it is now 63% gas capacity. How about kind of your EBITDA cash flow, gas versus coal?

Yes, Steve, I think if you just look at -- if you look at this entity as 100% fully consolidated up into Dynegy, just collapse the two entities together -- you know, I think before we said kind of the 80%, 85% is coming from gas. Obviously, it will be higher. So I would think it would be pushing 90%, if not higher.

In today's commodity market.

Right. In today's commodity market.

Okay. Thank you.

Thanks Steve.

Thank you. Our next question is coming from the line of Mr. Julien Dumoulin-Smith of UBS. Sir, your line is open.

Hi. Good morning. And congratulations on the ENGIE transaction here.

Thanks, Julien.

So perhaps just a quick question, kind of following up on the last -- on the target leverage back on the holdco, could you kind of talk about how you think about it, given the greater contributions from gas; and, obviously, the nonrecourse nature of a number of the subsidiaries here, too? How does that change your thought process on ultimate capital structure and target at the parent?

At the parent level?

Yes. But I suppose, implicitly, long-term leverage thoughts at the new JV, as well, would be interesting.

Yes, Julien, I am not sure that it really changes our view on the trajectory that we want to be on. I assume you mean if we were ultimately going to own 100% of this entity, given the composition of the gas weight, does that change our view on leverage? And maybe…

Right. I suppose -- given the transaction and given the wider macro out there of late.

Yes. I would say that it would not change our view. I think it would be helpful to achieving our objective of strengthening our balance sheet, de-risking the cash flows, and migrating toward BB-type of credit statistics. I think adding this fleet to our existing fleet would certainly help and potentially accelerate that process. But I don't think it would change how we think about or ultimately the direction that we want to go in with the balance sheet or leverage profile.

I think our goals remain the same, of targeting that BB-type credit metrics. And the JV actually will have less leverage than the parent. So again, longer-term, it makes sense for this portfolio to be blended into the overall corporate portfolio and improve the leverage statistics for the Company.

Got it. And then, turning to the MISO capacity auction coming up here, just latest views and thoughts. Will the region break out, in your view? And how -- if so, or if not, how do you think about imports?

Julien, this is Hank. I will comment on that. As you know, the MISO auction employs a vertical demand curve, which in some instances conveys a binary outcome -- either a very low price or a very high price. The local clearing requirement versus last year initially has been taken down by about 1,300 megawatts, so that in a stand-alone basis would make it less likely that the zone would clear versus the other regions. I think that is the general idea. The system -- our perception is that the overall system, at least in MISO classic, has tightened because of increasing retirements with minimal new build. So we will have to wait and see how it goes. I believe the results are out on April 14, but we are not necessarily of the view that

Got it. Last little detail here on the synergies from the transaction. What are the procurement synergies that you are talking about? I would be curious; specifically, you have had success with Kincaid in the past. Are you reflecting Coleto Creek in that synergy number? The initial one?

No. The vast majority, as you know, is the corporate overhead and then, beyond that, it's mostly O&M. I think really the second wave of synergies we would expect would be from sources more like procurement, when you have got a more fulsome understanding. Also, the CapEx that's actually shown for 2017/2018 actually has some up-rates in it of about 50 megawatts that will be helpful. And then also, in talking to our ops team, they view that you have upward to another 100 to 150 potential of up-rates that would be further synergies down the line. So the bulk of the synergies coming out of the gate will be corporate plus restructuring of long-term service agreements, which have been a good source of synergy in our past transactions.

And just to clarify that last answer, the up-rates that is reflected in the outlook, that is the 2017 CapEx member with the 230 versus the 80 in 2018 -- kind of the delta there of, call it, 150 is for the up-rates?

No. It is a small component of what is embedded in 2017 and 2018. So it is in there. That is not the reasons you see the big step down. The big step down is really driven by just the timing of some large steam turbine maintenance requirements, as well as, I think, some general generator maintenance requirements as well. Add these are kind of like one in 10-year events for some of this maintenance work. That is really what is driving the CapEx. There is just some level of CapEx in there for some up-rates at two of the New England units in 2017 and 2018.

Got it. But a good ongoing CapEx number should be closer to the 80? Or what do you think?

Yes, Julien, I think it is probably 80 to 100 on a kind of a recurring maintenance basis.

Got it. And the up-rates that you are describing in New England -- how many megawatts is that?

It is about 28 megawatts. And then we are looking at other up-rating opportunities across the fleet, which could potentially reach the 100 to 150 megawatt range. But we will know more once we take ownership.

Great. Thank you for the time, guys. Congrats again.

Thanks Julien.

Thank you. Our next question is coming from the line of Mr. Greg Gordon with Evercore ISI. Sir, your line is open.

Hi Greg.

So just recapping a few things, because most of the questions have been answered: all the debt is nonrecourse to Dynegy. You're looking at a 50% cash sweep. So if I just do the quick math, really, that translates into a practically -- a practical free cash flow yield in 2018 of around 15% for the equity? Around $100 million on $683 million of equity investment. Does that sound right?

I think, Greg, the way that we think about it is that the cash flow sweep -- I think if you are looking at it after the cash flow sweep, that is probably the right

Okay. That makes sense. Second, given past precedent, how soon -- not to jump the gun, but I'm going to do it. How soon -- how many quarters ahead should we look for an update on the impact of the PRIDE rollout on the acquired fleet post-close?

Greg, at the next update around that would really be more at closing or immediately post-closing, because we will need to get a better analysis of the different opportunities, and spend, and the like. So I wouldn't expect any updates prior to the close.

Okay. Great. And then finally -- if it was mentioned, I apologize -- but just looking at the math, obviously, ECP's buying the shares from you, $150 million at a little less than $11. But at a 15% ownership, that means they already own -- is it right -- they already own around 6 million shares?

They have accumulated a position of just right around 5% -- just under 5% or so. So I don't know their exact holdings, but they had accumulated some prior to us even contacting them about this transaction. So when you put the two together and you get to closing, we would expect it to be around 15%.

Great. Thank you. Have a great day.

Thanks.

Thank you. And our next question is coming from the line of Mr. Ali Agha from SunTrust. Sir, your line is open.

Thank you. Good morning.

Good morning, Ali.

Good morning. First question: how much of the JV portfolio is hedged currently for '17 and '18? And what price deck did you guys use to come up with your EBITDA assumptions?

This is Hank. I will speak to the hedge position and then hand it over to Clint for your second question. The ENGIE will continue to -- over the normal course of business, over the course of this year, continue the hedge as they have been in the past. Can't speak to specifics about their business, but they are at modest hedge levels, focused primarily in the first couple of years.

And then on the forecast, the price deck and that was used was as of January 7, so earlier in the year. That was the analysis that we used in evaluating the transaction. So for 2017, it was market prices on January 7; for 2018 that incorporated the market price for natural gas, but had our internal view on what market heat rates would be for 2018.

Okay. So that is what shows up in the EBITDA numbers you have given us?

That is correct.

Okay. And also, if I read the footnote right, in each of the years 2017 and 2018, you assumed $80 million out of the $90 million of synergies -- the JV component of it. Did I read that right?

Well, we have -- on day one $60 million would come in for the synergies. And then I would just kind of spread the balance as it comes in ratably over the next two years. So, I mean, you probably have roughly $75 million in the first year, and then you would reach your $90 million in the second year.

Okay. Okay. And just to come back and just be clear, modest hedging assumed -- is that, like, 20%, 10%? Just to get some rough feel as to the extent of that.

I really can't speak to that, given that it is not our business. I mean, it is not our place to communicate. But they are at modest levels, running 18 to 24 months into the future.

Okay. And you mentioned ECP had already accumulated some shares in Dynegy, and now they are getting more shares. Is there any lockup that goes with this on ECP post-closing?

Yes, we do have a lockup of six months.

Okay. And then my last question: coming back to the existing Dynegy fleet, in the past you had talked to us about a cumulative three-year EBITDA potential for the existing fleet. Can you update us on how you see those numbers today?

Yes. We generally did that kind of a one-off thing, but I would say that one of the underlying tenets of that was -- you know, and it was really one of the key questions -- was: what does the capacity market look like in MISO over that time period? And I would say that, particularly with the significant accomplishment of IPH and the retail group just yesterday of procuring nearly 1,000 megawatts of capacity over the next three years at a very significant, very good clear relative to the history of MISO, you know, that was kind of the big question mark. Are you going to be able to fill the capacity up and coming out of MISO? And I think the progression has been very much in line with what we had hoped, going back to what we talked about on investor day in establishing that three-year range. So to me, that was one of the biggest open questions of whether you can achieve those levels or not. And I would say the capacity sales have, I would say, at this point in time exceeded our expectations. And we will see what the upcoming auction is like in April. But directionally, it's going the right way.

Yeah so Bob, just to be clear -- so when you put it all together, the capacity and the latest energy given the forward curves, would you at least say you're probably still in that same range that you gave us back at investor day?

I don't extend kind of the thought process that far, because I am looking at the curves, and New England swings pretty big. And so I don't really want to go into the -- and then speculate on that. We haven't necessarily run the math on that relative to investor day. I think really the other component versus investor day that is significantly different is the environmental spend. I mean, when you look at things that have really changed, our estimates around complying with the three big environmental rules recently coming from the EPA, we are down about $126 million from investor day on what we actually think it will cost to comply with coal combustion residuals, the effluent limitation guidelines in the 316(b). So I would say capacity is a plus; environmental spend is a plus; and probably looking at natural gas forwards and the like is probably a minus.

Understood. Thank you.

Thanks.

Thank you. And our next question is coming from the line of Mr. Neel Mitra of Tudor, Pickering. Sir, your line is open.

Hi. Good morning. Could you clarify what you meant regarding possibly asset sales in PJM? Or was that trying to sell forward some of your capacity revenues? And would that be asset sales from the existing fleet or from the newly acquired fleet?

This is Hank. I believe you are referring to the capacity sale forward. And what we are in discussions -- we are in discussions with a few banks on taking a portion of the capacity revenues for a two-year period and bringing those forward, with the future cash flows from PJM being the payback to the bank. And to package those up, we look at a combination of -- across a broad number of units, and no more than 50% of it would be CP. Portions of the other remaining piece would be base product, and against -- it would be for 2017/2018, 2018/2019 planning year.

And, Hank, to add to that -- and correct me if I am misstating this -- but PJM is unique in the standpoint where you can actually take these future receivables, if you will, and really finance against it. It is essentially what it is. And that is kind of a unique feature in PJM. And we are taking advantage of that and pulling some of that forward.

And Neel, just to give you order of magnitude, whether you are looking at each planning year or each calendar year, we are talking about order of magnitude 15% to 20% of the total PJM-specific capacity revenues for that period. So that gives you an order of magnitude.

So would that be part of the equity contribution that you'd funded against, or would it be a component of debt?

We are drawing that from the Dynegy corporate level and utilizing those cash proceeds as part of our equity injection into the JV.

Okay. Great. And then my second question: any initial thoughts on how you plan to position Coleto Creek going forward? Your thoughts on coal and a pretty good gas portfolio to go along with it in Texas?

Well, I think the question has got to be: what do the forwards look like, and the CapEx requirements, and the regional haze requirements? I mean, even in our -- just the analysis, we assigned a -- when looking at the implied purchase price for Texas, we assigned a zero value to Coleto. So it is one that we will have to evaluate. I think with the regional haze requirements coming in and Coleto needing to make a significant capital investment, we would have to evaluate whether that provides the right level of return or not. So it's certainly is going to be one of those issues where it is going to be a close call as what happens next. But they would have to comply by 2021, if you're going to make the investment.

Is there any timeline by when you want to make a decision? Is that cash flow negative at this point, even without capital investment?

I imagine it would be similar to many of our plants. It is hovering around a free cash flow breakeven. I would expect it to be about that level. So again, depending on what happens with the four power markets in Texas, and new supply coming in, and natural gas prices, I think certainly it's -- as many coal plants face in different regions - it's probably going to be pretty challenging for Coleto.

Okay. Great. Thank you very much.

You're welcome.

Thank you. And our next question is coming from the line of Ms. Angie Storozynski of Macquarie. Ma'am your line is open.

Thank you. So my first question -- prior to this transaction, clearly investors haven't been necessarily rewarding the stock for your strong free cash flow yield, with some concerns about the level of leverage impeding the appeal of that free cash flow. You are, in a sense, doubling down on this business that is unloved in this market. And I know that you are not increasing your leverage, because it is a nonrecourse financing. But can you talk us through the rationale, at least in the near term, about how you have chosen to increase the use of cash -- not to, say, pay down debt or buy back shares, but instead double down on generation assets?

Sure, Angie. I mean, underlying the business, you have to have the right assets in the right place. And bottom line is: do you have the right physical assets that have longevity? And we have been building a portfolio over the last several years to that provides a lot of strength in the right markets. And adding this portfolio to our existing portfolio, when you talk about it doubles down on the strength of what you need to have the longevity in this business with -- and you could see from even our results on how successful the combined-cycle units we have that have great access to low-cost gas, and we are really doubling down on that type of strategy. So when you think about long-term cash flows being able to survive in any commodity market -- and the point in time when natural gas comes back again, the coal plants will be there to provide additional cash flows -- it is building a strength of a portfolio that can withstand any commodity environment and benefit from any commodity environment. And that is the underlying foundation of this power generation business. And we have built a very strong profile of that. And when we looked at buying back our shares, even when we looked at the fundamental value of ours -- which, I can tell you, is multiples and multiples higher than where it trades today -- this transaction that we have done today was the highest and best use of our capital, being where we believe that earnings are going to come from; how it delivers -- helps delever the Company over time; and how it strengthens the underlying position of the Company. So I 100% believe in this transaction. And like I said, even with looking at the alternatives of debt paydown, share buybacks, and this transaction, the compelling return here -- leveraging our platform, having the assets in the right market, the entry point in the ERCOT at $250 a kW was the best use of capital. And you don't want to make a decision based upon a short-term market where capital markets are closed, and they hate the energy sector, and we are unloved. For the long-term benefit of the Company and the shareholders, this was the right transaction for us.

Okay. And changing the topic a bit, so you have been really outspoken about the Ohio PPAs. Now, can you -- given the structures within PJM, do you really believe that these assets would have a negative impact on the value of capacity and energy, or the value of your assets in Ohio? Given mopern and capacity, and given the fact that PJM could actually ensure that these assets are dispatched economically -- I am talking about the assets that would potentially be covered by PPAs.

Yes. Well, first of all, I think the way FirstEnergy and AEP always described us, they are -- they continuously put misleading stories out there about why you need it. And clearly, this is something that is trying to reward their shareholders, and I get that. But what concerns us about it is it changes bidding behavior. And you take a look at all of these plants that -- even though, like AEP says these plants will all shut down, we know that is not true, because we co-own them with AEP. So that is not going to happen. But what you saw in the last capacity auction is FirstEnergy and AEP just blindly put in their megawatts into the capacity auction for the capacity performance product, because they think they have got this big cushion on the other side with ratepayers that will pick up any penalties that they have. We have put the same units in it, and at the base product, because we know they are not ready yet for CP. So we have to come up with capital investment plans that get it CP-compliant. But on the other hand, they don't, because if it doesn't work, well, they just pass the higher cost of the penalties for CP to the citizens of Ohio. So it changes how they bid into the market. And it not only impacts of Ohio; it impacts the entire capacity clear for PJM. So it is very counter-competitive. And we view PJM as the best constructive market that is in the United States for the competitive markets. And this is clearly something that undermines that for the benefit of just a couple of companies. And it shouldn't work that way.

Okay. But being that they have already bid that way, right -- so in a way, you're trying to say that those PPAs would limit upside to prices for energy and capacity as opposed to provide downside, right? Because they have already been acting in a way that basically, in your opinion, undermines pricing. And yet pricing for capacity has been pretty strong.

Well, they are going to -- for the very next auction, they are going to do the same thing. For first one, day in and day out on the energy markets, so you just put in at zero, because you really don't care what price you get. Because we know we are getting a return; we just don't know if it is coming from the wholesale market or we're going to stick it to the people of Ohio. They don't really care as long as they get their return. But that is not how you want to bid -- that is not how we bid into the market. We bid based upon economics, and they are hurting the economics of the competitive market. The next capacity auction comes up just in a few months. And, again, they will just put everything in at CP at zero, and they will work on just clearing that. And if they get penalties, well, they will hand that to the citizens of Ohio as well. So that's why we are against it. That's why EPS is against it. And that's why competitive generators, whether it is Calpine, Cawlen, NRG, ourselves -- we are just against that. We just want to compete on a level playing field. And this upsets that.

Okay. Thank you.

Thanks Angie.

Thank you. Our next question is coming from the line of Mr. Michael Lepides from Goldman Sachs. Sir, your line is open.

Hey guys. Congrats on today's transaction. Two questions on the legacy Dynegy business. One, given how the credit markets have traded, any thoughts on plans or, more importantly, maybe, opportunities you see with the Illinois Power Holdings debt, given where it is trading, and kind of your long-term thoughts around that asset base as being a core part of Dynegy? That is question one. And question two: we are kind of getting to the tail end of the PG&E rate case in California. Can you give an update a little bit on your thoughts and plans for the California plants, given that you have talked about those over the years?

Well, on the IPH question, Mike, that is certainly something we would look at and look at the trading guidance of the debt, and look at capital allocation. And that is always one of the things that we consider. As I mentioned earlier, getting this retail contract which benefits completely IPH is a big win for IPH. I think what we are really waiting for with IPH in terms of kind of next steps and looking at the overall portfolio is what happens in the upcoming capacity auction. And I think Hank, who had talked about it earlier -- we don't necessarily see

Got it, Bob. Thank you. Much appreciated.

Thanks Michael.

Thank you. And our next question is coming from the line of Mr. Devin Mcdermott of Morgan Stanley. Sir your line is open.

Hello Devin.

Mr. Devin, sir, just disconnected his line. Let me just proceed with the next question and that is coming from the line of Mr. Praful Mehta, Citigroup. Sir, your line is open.

Thank you. Hi guys.

Hi.

My first question is on valuation. And I know you mentioned that you applied your fundamental e-trades, I think, from 2018 onwards. I guess on a relative basis, if you apply to your fundamental assumptions, like you have done to value this portfolio, to Dynegy's fleet, what kind of valuation do you think you come up for Dynegy itself? I am just trying to understand relative value here, and whether the fundamental assumptions that you have used are meaningfully above whatever the Street is implying today in terms of your stock price.

I would say no, they are not -- you can even look at the step-up from 2017 to 2018 for the ENGIE portfolio; it is -- virtually all of it is just cleared capacity. So we are not really talking about much of a difference between the two years.

Yes, and Praful, I think when we look at -- and I think Bob touched on this a little bit earlier -- when we look at acquisitions like this and investments like this, we do compare it to a fundamental valuation of Dynegy using similar assumptions, and price decks, and so forth. And we look at it on a risk-adjusted basis on the use of capital, and is it a compelling use of capital relative to the alternative. So I think -- I wouldn't want to necessarily put our own view of -- valuation of Dynegy out there. But, again, I think we do look at it on an apples-to-apples basis. And when we make decisions like this on acquisitions, it means that we find the opportunity in front of us particularly compelling.

Yes, I mean, you know, 2017 EBITDA range that was in the slide deck for ENGIE was completely at market, period. And then you have an uplift of $125 million going to 2018. $85 million of that is known capacity, and then you also know synergies is taking that up to over $100 million. So you're getting down to less than $20 million impact for overlying a fundamental view on some of the heat rates and the like. So it is not that big of a difference.

Fair enough. And it is good to hear that you do the fundamental comparison, which is helpful color. Secondly, in terms of the financing of this transaction, I am assuming that your first goal was to try and get the entire secured debt from banks, but you were limited to the $1.85 billion and had to go to the bridge with ECP. Firstly, is that a fair assumption? And secondly, does that mean that the banks are more concerned and are unwilling to step up to the full secured bridge? And what does that tell us in terms of their view on value, I guess?

Well, I think we could have obtained from the banks committed financing for a full $2.3 billion. But the piece of that that was the most difficult one is that that would include an unsecured piece. And having an unsecured element in this capital structure in this market is not nearly as cost-effective as the ECP bridge. So it wasn't that the banks would necessarily limiting that, you know, the only thing you could get is $1.8 billion. It was the structure we elected to pursue would be just for secured of $1.8 billion, and then we would pursue -- and then ECP provide the bridge, rather than having them provide committed financing for an unsecured, which would have been significantly more expensive.

Yes. And I would just add that we looked at a lot of different alternatives. We have looked at: what would this look like if we tried to do this ourselves? We also looked at different alternatives in partnering up with Energy Capital. And we went through different iterations. And like Bob said, I think it wasn't necessarily a limitation in capital availability from the banks. It was simply under what terms, and conditions, and pricing, and so forth would they be willing to provide more debt financing. And just given the current market conditions, it was just more challenging than obviously what we would have seen a couple of years ago for the previous transaction. So when we looked at all of the different alternatives, the plan that we have now seemed to be the best plan, the most executable, the most cost-effective, the one with the best terms. And so that is the approach that we chose.

Fair enough. Got it. And just quickly, on the PJM capacity sales, what is the nominal value for the $200 million net NPV, effectively, that you are getting of cash for these capacity options? How much EBITDA effectively on the nominal basis is going down between 2017/2018 and 2018/2019?

Well, I don't want to necessarily put a nominal number out there. I think how you should think about this is that the pricing is very attractive from our perspective, because the counterparty is really looking toward PJM as their credit risk. So the pricing, meaning the discount on this, is very competitive. So if we are looking at, say, $200 million in proceeds, the nominal amount would be higher; but the discount that is applied is -- I would say is very competitive with the best financing terms that we have. So the nominal number would be a little bit higher, but I don't want to necessarily give you a number, because then our potential counterparties out there could then imply what our expectations are for carrying costs.

And I think, again, I would also say this won't affect EBITDA. This is more of a financing structure, and the spread between the nominal and the realized is basically interest expense.

Yes. I think the way to think about this is that this is a two- to three-year financing, and that it is basically pre-allocation of capital from those years into this year for this purpose.

Yes. So just to be clear, the EBITDA does not go down in '17/'18, '18/'19. It is just that you are getting the cash today, so effectively that year that EBITDA won't show up in your book; the bank look at that EBITDA, whichever has given you that cash, effectively?

It's almost like factoring a receivable.

Yes.

So our cash -- we are accelerating the cash flow from that EBITDA.

Yes, yes. Got it. That's exactly what I was thinking. Okay. Appreciate it. Thank you, guys.

Thank you.

Thank you. Our next question is coming from the line of Mr. Ashar Khan of Visium. Sir, your line is open.

My questions have been answered. Thank you so much.

Okay. Thank you.

Thank you. And our last question for today is coming from the line of Mr. Charles Sharett of Credit Suisse. Sir, your line is open.

Hey. Good morning. I just wanted to follow up on the ECP bridge loan. It sounded like after year one, if is not refinanced, your equity is diluted. I guess I wanted to see what your options are to refinance that after year one or during year one -- and would you need to issue more equity? Or would you look at refinancing that at the Dynegy level?

Yes. I think the way to think about that is that at the end of the day, as part of our financing, we would like to replace that as soon as we can, but to the extent that it is still remaining outstanding after a year -- you know, a number of things can happen, but I think the first step would be that each of the partners can pay it off in their respective ownership pro rata basis. So ours hours would be 65% of that $400 million. And you can either do that -- you could finance that or pay for that in any way, whether that is just from your cash balances or finance it somehow. But I think that would be certainly one of the options. And as we think about the other option as far as being diluted down, particularly at the multiple that Bob mentioned a little bit earlier, we obviously wouldn't want to do that.

Right. So you would look potentially to refinance this, or your piece of it at the Dynegy level.

Our objective would be certainly be to take this piece of paper out, which also is the same objective from -- you know, Energy Capital has the same desire not to have this thing roll over, go the full term. And first and foremost the objective is, as we go and finance the entire transaction, as credit markets open up, we will want to take it out even before closing. That would be the best-case scenario. The second-best-case scenario would be credit markets open up post-closing where we can finance it out. Then the third alternative would be, if that is not possible, then look at our corporate-level liquidity position to see if that is possible. So we would look at the various different alternatives, kind of in descending order, and what is the best use of our capital. And, again, we want to limit the impact on the Dynegy balance sheet. And I certainly would also say that this is part of the collateral package going forward. So our debt holders at the Dynegy level are well protected by having this portfolio that's a very high quality portfolio, less leverage than the Dynegy portfolio. So they have that protection. But we want to limit the impact on our balance sheet. But certainly, our goal is to take that piece of paper out. And ECP has the same objective. And the best way to do it will be just to finance it out as we put in the permanent financing.

And just -- what would happen after year one? Could you give a little more detail on that?

Well, after year one, it can be converted to equity. And then for every $1 of debt, it gets converted to $1.50 of equity. So as you said earlier, we would be diluted down to below 50% ownership in the JV. And that is assuming that we don't pay any of our share off. We also have the ability that -- to the extent that we can't pay back the full -- our full 65% share, we can pay a portion of that down and have the balance of that roll into equity -- be converted into equity and be diluted down, but to a lesser extent. So we have got a lot of options around how to manage this. But as Bob said, there certainly are several alternatives that we would pursue in advance of that.

Okay. And could you also just confirm the amount of cash that is leaving Dynegy's balance sheet as part of the initial transaction?

Yes. I think at this point it is about -- in total, about $620 million, comprised of proceeds from the sale of PJM capacity; about another $420 million in either cash or revolver draws -- it is fungible between the two, just from our liquidity. And then on top of that would be using the proceeds of the equity sale from ECP. So as we stand today, before the sale of that equity, it is about $620 million. And that we would also add the $150 million in equity proceeds coming in from ECP to that.

Got you. Thank you very much.

Thank you.

As it stands, sir, no further questions on queue.

Okay. Well, thanks, everyone, for joining the call. Thank you.