The AES Corporation (AES) Q2 2014 Earnings Report, Transcript and Summary

Good morning, and thank you for standing by. [Operator Instructions] Today's conference is being recorded. [Operator Instructions] And I would now like to turn the call over to your host, Mr. Ahmed Pasha, Vice President of Investor Relations. Mr. Pasha, you may begin.

Thank you, Elan. Good morning, and welcome to the second quarter 2014 earnings call for The AES Corporation. Our earnings release presentation and related financial information are available on our website at aes.com. Today, we will be making forward-looking statements during the call. There are many factors that may cause future results to differ materially from these statements. Please refer to our SEC filings for a discussion of these factors. Joining me this morning are Andres Gluski, our President and Chief Executive Officer; Tom O'Flynn, our Chief Financial Officer and other senior members of our management team. With that, I will now turn the call over to Andres. Andres?

Good morning, everyone, and thank you for joining our second quarter earnings call. Today I will provide a brief update on our second quarter results and our progress on executing our strategic plan. Turning to Slide 4. Our second quarter results were $0.28 of adjusted earnings per share, which keeps us in line to achieve the low end of our guidance range on EPS despite the continuation of the drought in Brazil and Panama. Tom will provide more details on our results today and our year-to-go forecast, but a major driver of lower earnings in the second quarter was a much higher tax rate, which we expect will normalize on a full year basis. Similarly, while our cash flow results to date are significantly below last year's, this is largely due to timing issues at our utility. And we continue to expect to achieve our full year guidance. Now turning to the progress we are making on executing our strategic plan. I am pleased with our results to date. As you can see on Slide 5, the main objectives we set out almost 3 years ago were: first, exiting those markets where we do not have a competitive advantage; second, focusing our growth on platform expansions; and third, reducing our overhead. Since then, we've added a fourth objective, to expand our access to capital through partnerships at the project and business level. Taking one objective at a time, turning to Slide 6 and the simplification of our portfolio. In the second quarter, we announced and closed 2 new asset sale transactions. First, we brought in a minority partner for 41% of our Masinloc business in the Philippines. Second, we announced the sale of a majority of our solar business, Silver Ridge, which was not yielding adequate risk-adjusted returns on our invested capital. These 2 new transactions together represent $631 million of proceeds, implying a P/E multiple of more than 14 from these businesses and in line with our expectation of achieving $500 million to $700 million in asset sale proceeds in 2014 and 2015. Since we began the simplification of our portfolio in the fourth quarter of 2011, we have received $2 billion in asset sale proceeds, which we have used to pay down 20% of our recourse debt, buy back 8% of our stock and invest in platform expansions. Going forward, we expect to raise $500 million in additional proceeds by December 2015, by selling all or part of our interests in certain businesses in markets where we want to exit, decrease our exposure or reinvest our capital in platform expansions. What we seek to do is optimize our portfolio by geography, technology and fuel source. Turning to Slide 7. With regard to our focus on platform expansions, which provide us with a path for growth with higher risk-adjusted returns. We now have 4,500 megawatts of new capacity and 2,400 megawatts of environmental upgrades under construction. Most of these projects are either under long-term contracts or will earn utility-like returns. This is the greatest number of megawatts under construction ever in AES' 33-year history. As you can see on Slide 8, we've achieved commercial operations on time and on budget at the 247 megawatt IPP4 power plant in Jordan, which has a long-term contract with a state-owned utility. We also recently broke ground on 3 new platform expansion projects in the second quarter totaling 702 megawatts in the U.S. and Chile. The 671 megawatt Eagle Valley CCGT at IPL will not only help us diversify the fuel mix at the utility, but will also earn attractive regulated returns beginning during construction. This investment, combined with the mass upgrade currently underway, will result in a 50% increase in IPL's rate base. We see additional investment opportunities at IPL, which will help further grow the earnings power of this utility. In Northern Chile in the Atacama Desert, which has some of the best solar irradiation in the world, we recently broke ground on a 21 megawatt solar project with a long-term PPA with a local mine. Including this project under construction, we are developing a total of 220 megawatts of solar capacity next to our existing Los Andes substation. The entire capacity has environmental approval and will be developed in stages. Turning to Slide 9. The investment in our construction program will be mostly funded through nonrecourse debt and by our partners on various projects. Our total equity contribution in these projects is approximately $1.5 billion, of which we've already funded more than $1 billion and expect to invest the remaining $450 million, largely in 2015 and 2016. We expect a 16% cash return and a 15% ROE on these investments, which will be an important driver of earnings and cash flow growth over the next few years. Furthermore, we're making progress on our advanced pipeline of development projects, including platform expansions, adjacencies and enhancements and select platform expansion acquisitions. These opportunities represent a pipeline of more than 5,000 megawatts in our core markets. Turning to Slide 10. We have significant brownfield potential at our Southland gas-fired facilities in Southern California. We're moving through the permitting process and pursuing long-term PPAs and commercial arrangements. Furthermore, our energy storage solution and site locations position us well to help meet Californian's mandate for at least 1,325 megawatts of energy storage. Turning to Slide 11. As we discussed in our last call, we are closing the cycle at our 236 megawatt DPP plant in the Dominican Republic, increasing its capacity by 122 megawatts. We recently signed a 6-year PPA with the state-owned utility and selected an EPC contractor. We are working on financing and expect to begin construction later this year with commercial operations in mid-2016. This 260 megawatt enhancement will be mostly funded with debt capacity in the Dominican Republic. Moving to Slide 12. Another market where we're looking at growth opportunities is Mexico. We've been in Mexico for almost 15 years and currently own 3 power plants, making us one of the largest independent power producers in the country. Mexico is a big market, and more importantly, has the potential to increase its installed capacity by more than 25,000 megawatts in the next 5 to 7 years through recently proposed reforms to the energy laws. Now on to Asia beginning on Slide 13. As you may know, the Philippines is currently experiencing power shortages as growing demand continues to exceed existing supply. We already have all the necessary permits for the 600 megawatt Masinloc expansion, and we're working to secure EPC and power offtake agreements. We're also developing up to 200-megawatts of energy storage projects to meet ancillary service requirements and peak demand needs for the system. Turning to Slide 14. In Vietnam, construction of our 1,240-megawatt Mong Duong project is progressing well. We recently synchronized to the national grid and achieved full load on unit 1 of 560 megawatts. We expect to achieve full commercial operations on time during the second half of 2015. In its first full year of operations, we expect Mong Duong to contribute $100 million in proportional free cash flow. In addition to our Mong Duong facility, we're assessing further growth opportunities in Vietnam, including both greenfield and privatization of government-owned generation plants. Turning to Slide 15. A significant development that aids the execution of our strategy is our ability to incorporate financial partners at the project and business level. Since we started this initiative 2 years ago, we have closed about $2 billion in equity from partners. Bringing in partners at the project level enables us to optimize our portfolio by tailoring our equity commitments to specific projects managing our aggregate risk profile at the corporate level and improving our returns through promotes and management fees. It also gives us a mechanism to demonstrate the value of our assets in markets where there are few or no listed comps. Some recent examples of these are Guacolda in Chile where we brought in a partner to invest $728 million for a 50% stake in the business; and Masinloc in the Philippines where EGCO, a Thai company, invested $453 million for a 41% stake. Now addressing our third objective on Slide 16, reducing our global overhead to become the low-cost manager of a portfolio of assets. We are well on our way. We're on track to realize our goal of reducing global overhead by $200 million by 2015. From 2011 to 2013, we reduced our global overhead by $143 million, and we expect to achieve an additional $57 million over the next 1.5 years. I'm pleased to report that we have accelerated our savings profile and now expect to realize about 70% or $40 million in savings this year, leaving only $17 million to be achieved in 2015. We're accomplishing these reductions through process improvements and global standardization across our corporate support functions. Therefore, in terms of executing on our strategic plan to increase shareholder value by creating a more streamlined and focused company, which takes advantage of its footprint in attractive markets to pursue high-return projects, I would say we are continuing to make very good progress. Nonetheless, we're facing some short-term challenges in a few of our markets. Moving to Slide 17. This is the second year of drought in Latin America, which has significantly affected our results in Panama and Brazil. As we discussed on our last call, we continue to project an earnings impact of $0.07 to $0.10 in 2014. Turning to Slide 18 in Brazil where we continue to see tight demand and supply conditions having a positive impact on forward power prices, which are now BRL 180 to BRL 210 per megawatt hour for 2016. As you may know, this is about the same price of Tietê's existing contract that expires in 2015 and is almost 50% higher than the price we assumed in our expectations for 2016. 3/4 of Tietê's capacity for 2016 is contracted for 2016 at BRL 125 per megawatt hour. And with today's forward curves, we see $0.01 to $0.02 upside for adjusted EPS in 2016 relative to our expectations. Beyond 2016, on an unhedged basis, every BRL 10 improvement in power prices translates into $0.01 of adjusted EPS for AES. Turning to Slide 19, I will discuss developments at Maritza, our coal-fired power plant in Bulgaria. In June, the Bulgarian energy regulator took certain actions concerning Maritza's PPA. The regulator announced that it had requested the Director General for Competition of the European Commission to scrutinize the PPA under European state aid rules. While the Director General has not contacted us on this matter, Maritza will defend the PPA in any assessment or proceedings initiated in response to this request. Additionally, as we've discussed in the past, the energy regulator has instructed NEK, the state-owned utility that is the offtaker under our contract, to initiate negotiations on the terms of the PPA in order to lower its payments. We have had several discussions with NEK and various government authorities concerning the regulator's actions. Maritza continues to be engaged in resolving this matter, as well as in the recovery of our outstanding receivables. In fact, last week, Maritza signed an agreement to settle $45 million of its outstanding receivables that are more than 90 days overdue from NEK. In that deal, NEK agreed to assume $17 million representing all of Maritza's outstanding obligations to its fuel supplier and restructured the additional amount over 4 months. As of July 31, Maritza had $206 million of receivables due from NEK with $47 million not yet due and $69 million overdue for more than 90 days. As far as the resolution of these issues, it is likely that any action will be deferred until the new government is elected in October. Maritza contributes roughly 7% of our PTC. And while the situation is challenging, Maritza's objective is to preserve the value of the business through a negotiated agreement of our seeking to reinforce its rights. Our guidance is based on maintaining the value of our existing contract. Next turning to Slide 20. Although we have not been negatively affected by the Argentine government's selected defaults, we continue to closely monitor the situation. In Argentina, where we generate about 3% of our PTC, we have a competitive fleet of 3,000 megawatts of generation capacity, which is an important source of reliable generation in the country. Additionally, we have taken steps to dollarize our accounts receivables in Argentina. Although we have factored a devaluation of the Argentine peso into our forecast, an extreme devaluation could have negative impacts on our results. And finally, turning to the situation in Puerto Rico where our 524 megawatt coal-fired plant has a long-term contract with PREPA, a government-owned utility. As you may know, the rating agencies lowered the rating on the commonwealth and its corporations. AES Puerto Rico contributes about 2% of our PTC. PREPA is facing business and liquidity challenges primarily driven by the weak economy, along with other state-owned companies and has a high cost oil-fired generation fleet that serves 70% of the commonwealth's energy needs. We believe that our existing contract is advantageous to PREPA, particularly considering that our plant saves PREPA an estimated $250 million per year. These are some of the key areas that we're keeping a close eye on. Having said that, we have taken actions and will continue to do so in order to mitigate any risks. In the longer term, we're addressing our exposure through selective asset sell-downs and rebalancing our fuel mix through platform expansions to create an even more robust company. With that, I'd like to turn the call over to Tom, who will provide more details on our financial results in the second quarter and year-to-date, as well as our year-to-go forecast.

Thanks, Andres, and good morning, everyone. Today, I'll go through our second quarter results including adjusted EPS, adjusted PTC by strategic business unit or SBU, proportional free cash flow, the 2014 capital allocation plan, and finally, our 2014 guidance. Beginning on Slide 22. This quarter, we benefited from higher pretax contributions from our businesses and also our capital allocation impacts. However, the tax rate in the second quarter was higher than last year and above our full year 2014 expectations. We finished the quarter with adjusted EPS of $0.28 a share and expect to achieve adjusted EPS in the low end of our guidance range. Improvements in our businesses in the U.S., Andes, Brazil and also in Mexico, Central America and Caribbean SBUs together contributed an increase of $0.02, including a lower adverse impact from hydrology versus last year. Partially offsetting these improvements, outages in our Europe, Middle East and Africa and Asia SBUs reduced results by $0.02. Like last year, we recognized benefits from some discrete items, the net effect of which was a positive $0.02. We also benefited from investing in our balance sheet, which added $0.02 to the bottom line. This was driven by 2 factors: First, our share count was down by 3%; and second, in May of 2013, we prepaid $300 million of parent debt and refinanced $750 million, which resulted in annual interest expense reduction of $50 million. Our tax rate was 40% this quarter, higher than last year's second quarter's unusually low rate of 11% producing a negative impact of $0.11. This breaks down into $0.07 related to the expected return to a normalized rate of about 30% to 32% and $0.04 due to interim timing impacts. Before I go into the businesses, I'd like to touch on some developments at DPL on Slide 23. The commission has ruled on all pending matters in the ESP case and extended the generation separation deadline by 12 months to January 2017. Regarding generation separation, based on the PUCO staff's recent comments, we believe we are close to a consensus with the staff on material terms of separation. We expect a commission decision in the third quarter. As you may know, we ran a process to consider selling DPL generation. Although the sale would have been accretive this year, and we received reasonable bids. The offers were not attractive relative to the long-term value to AES. We therefore decided not to sell. Selling the generation would have left the remaining business with a significant amount of debt. At the same time, this high debt level increases our leverage to improvements in the energy market. The following factors contributed to our decision: first, movements in power prices as witnessed in the first half of this year create a more positive outlook. I appreciate these curves would come off their May peaks, however, the market is still higher than what we were projecting at the start of the year. Second, we saw an improvement in PJM RPM prices which doubled, albeit from low level at the last auction and outstanding proposals to provide additional improvement. Third, we are implementing a plan to further improve the operations of the business, particularly related to improved plant performance. And fourth, we'll continue to optimize our positions through our multiyear commercial hedging strategy. Overall through 2016 when the ESP expires, DPL is expected to generate annual EBITDA of about $350 million, of which about $80 million to $100 million is attributable to the generation business with the rest coming from the T&D business and the non-bypassable payments under the current ESP. Based on current forwards, DPL is projected to generate $100 million in free cash flow annually. And our plan is to use any excess cash to repay debt, which is currently $2.3 billion. We provided addition details on hedging and debt maturity profiles of DPL in the appendix. Bottom line is that DPL's generation business was projected to be dilutive over the next several years. However, based on the current market, this business is earnings neutral and has earnings upside potential if we're successful in capturing the market and operating improvements that I just discussed. Now to Slide 24, I'll discuss each of our SBUs, focusing on adjusted PTC or PTC. In the U.S., we reported an increase of $17 million of PTC. This was largely driven by the synchronous condensers at Southland and a new 40 megawatt energy storage resource in Ohio. In our Andes SBU, PTC was up $16 million. We benefited from a higher tariff at AES Argentina and lower maintenance costs and lower FX losses in Chile. In Brazil, PTC increased $37 million for the quarter. This includes a $47 million benefit at Sul from a reversal of a prior interest expense. This compares to a $24 million reversal of a liability at Uruguaiana in the second quarter of last year. Excluding these onetime items, PTC increased by $14 million as we benefited from higher contributions at Uruguaiana and Sul. Moving to Mexico, Central America and the Caribbean, PTC declined $9 million. We benefited from the steps that were taken to offset the adverse hydro conditions in Panama, including payment from the government under the negotiated agreement to compensate for exposure to high spot prices of up to $40 million this year and $100 million total from 2014 to 2016. Turning to Europe, Middle East and Africa on Slide 25. PTC was essentially flat versus last year. This performance was largely driven by scheduled outages in Bulgaria that were offset by higher operating performance at Kilroot in U.K. and a reversal of a liability in Kazakhstan. Finally to Asia, where PTC declined by $17 million. Although we were anticipating a decline, our operations in the Philippines were adversely affected by forced outages in the second quarter with an impact of $13 million. These outages are the result of issues in the boiler, which have been resolved and the units were returned to service in July. In addition, we used these outages to complete some maintenance we had planned for next year. So to summarize, as shown on Slide 26, our total year-to-date adjusted PTC is roughly $583 million or 43% of the midpoint of our expectations. For comparison, last year, we earned 46% of our full year PTC in the first half. Our year-to-date effective tax rate was 36%. We expect a lower rate during the second half of the year that will bring our full year tax rate down to about 30% to 32%. Beyond this year, we continue to expect a low to mid-30% tax rate. Now to cash flow on Slide 27, we generated $47 million of proportional free cash flow in the second quarter, which was impacted by working capital requirements at our utilities in Brazil. This brings our year-to-date proportional free cash flow to $176 million versus $526 million in the first 6 months of '13. We recognize that this year is significantly lower than last year as we've had a $300 million swing at our utilities in the U.S. and Brazil driven primarily by working capital requirements. Specifically, in Brazil as we discussed on our last call, the system operators dispatching thermal generation to preserve reservoir levels causing higher spot prices. These higher spot prices do not affect our utility earnings due to the passive nature of energy purchases. However, there is an adverse impact on working capital as there was a lag due to the periodic tariff adjustments approved on an annual basis. Our guidance assumes that during the second half of the year, our utilities in Brazil will benefit from the recently approved annual tariff adjustments, as well as the pending government support mechanisms. In the U.S., during the first half of the year, cash flow at DPL and IPL were affected by higher working capital requirements, outages at DPL and upfront funding of annual pension contributions at IPL. Working capital requirements at our U.S. utilities were driven by high receivables from our regulated customers as a result of higher fuel prices and energy purchases during the cold weather in the first quarter. Our guidance assumes that both companies will recover these investments through fuel and energy cost regulatory mechanisms during the second half of the year. To summarize, with our year-to-date performance, we expect to generate almost $1 billion in proportional free cash flow during the second half of this year versus $745 million generated in the second half of last year. We do have seasonality in our cash flow. Last year, the second half represented 59% of our proportional free cash flow. This year, in addition to the seasonality factor in the second half, we expect to recover the significant short-term working capital drag that I just discussed. In fact, our utilities in the U.S. and Brazil should contribute about $400 million in the second half of the year versus negative $100 million in the first half. We believe proportional free cash flow is one of our key value drivers. We continue to believe that we'll generate $1 billion to $1.3 billion this year, and we're very focused on our businesses having a strong second half to achieve this goal. Now to Slide 28 in our capital allocation plan for the year. During the quarter, we refinanced a $770 million senior secured term loan with an unsecured floating rate note, increasing our available first-lien debt capacity by 50% to $2.2 billion and reducing our interest expense. When taking into account the recently announced solar and Philippines transactions, we project roughly $1.5 billion of discretionary cash, including about $800 million of cash from announced asset sales as well as parent-free cash flow, which we expect to be $500 million. We've allocated about $275 million this year for investment in a portion of our equity commitments for projects under construction, primarily platform expansions. We used roughly $500 million to $600 million of the excess cash for debt reduction, including the $320 million that we recently called and the $140 million prepaid earlier this year. About half the targeted debt reduction this year relates to our policy of using part of the proceeds from asset sales to maintain credit neutrality. The remaining half was discretionary in an effort to accelerate our credit improvement and reduce financial risks, consistent with our previously stated balanced capital allocation strategy. Since our first quarter call in May, we've invested $47 million in our shares. This brings our overall investment in share repurchases to $758 million since September of 2011, reducing our share count by 8%. After $145 million of dividends to shareholders and a target closing cash balance of $100 million, we're projecting $300 million to $500 million of discretionary cash to be allocated this year, plus any additional asset sales would increase the amount available. In the first half of the year, our allocation of capital to share repurchases has been modest, as we've been more focused on reducing our debt and making investments, that will earn attractive returns and generate growth in our earnings and cash flow. Over the past 2 years, however, we've been returning approximately $400 million per year on average to shareholders, including dividends and repurchases. This year, we anticipate returning at least $300 million as we expect to repurchase more shares in the second half. The bottom line is that we'll continue to be disciplined and invest our cash to maximize risk-adjusted returns for our shareholders on a per-share basis. Now to Slide 29. We are reaffirming our guidance that we expect to be in the low end of our adjusted EPS range of $1.30 to $1.38. In the first quarter call when we updated our guidance, we discussed several items that we expect that will help us to mitigate the $0.07 to $0.10 impact of hydrology. One of these offsets was an expectation of the benefits from selling DPL's generation business and removing it from continuing operations this year. Although we decided to retain this business, and therefore, will not have that benefit this year, the Sul reversal that I talked about earlier, which was not in our original guidance, allows us to stay within the low end of our guidance range. With that, I'll now turn it back over to Andres.

Thanks, Tom. In summary, although we're facing some short-term headwinds, we're taking concrete steps to lower our portfolio risks and increase per-share value. Since we set out our strategy in September 2011, we're on target to reduce our global overhead by $200 million by next year, and we are focusing on additional O&M cost reductions. We raised $2 billion in asset sale proceeds. We paid down 20% of our parent debt; invested $758 million in our shares, reducing our share count by 8%; and we are selectively investing in platform expansion opportunities that yield attractive risk-adjusted returns. Through these actions, we've laid a solid foundation and remain committed to investing our excess cash flow to grow our earnings and free cash flow per share, resulting in proportional free cash flow growth of 10% to 15% per year and a total return to shareholders of 8% to 10% by 2017. Now, I'd like to open up the call for questions.

[Operator Instructions] Our first question today is from Ali Agha.

Just following-up on a few of the topics, first off on the capital allocation front. So if I looked at on the slide, this quarter versus last quarter, it appears you've paid down about an another $390 odd million of debt or plan to do that in terms of -- in terms of that bucket. What are the earnings implications of that, or have those been factored in from that incremental debt reduction?

Yes, those are factored in, Ali.

So is it fair to say the asset sale proceeds, the earnings going away from asset sales are being offset by the lower interest. Is that the way to think about that?

Yes, I would say partially, yes.

Okay. And then with regards to the unallocated bucket, and I know, Tom, you alluded to the fact you will be buying more shares in the second half, given that roughly 300 million or so number. Is there a thought of getting even more aggressive on the buyback given where the stock is, Andres? I mean just your thoughts on that, as you're investing in new projects versus buybacks looking at the valuations, how are you thinking about potentially getting even more aggressive on buybacks?

That's a very good question, Ali. When we're looking at the investments that we're making, as I've said in the past, we compete that -- those against share buybacks. So obviously, when you look at the returns that we're projecting, 16% cash returns and a 15% ROE, we think that those are superior to what we're getting back from buybacks. So we're taking a balanced approach. We're saying that -- we said last time that we would buy back shares. We're doing that. Do realize that the cash that we received from these asset sales was also quite recent. We only received it, say, in the last month. But I think we're doing exactly what we said that we would do that we would buy back shares. But we'd also complete the new projects. And so obviously, if we're doing these new projects it's because we feel that those are the projects that maximize our shareholder value over time.

And then Andres, just coming back to DPL for a second. So the merchant, as you said, the pricing you thought was not good, so you pulled back on that sale. So should we view these assets now as core holdings and that sale is completely off the table? And related to that, as you know Duke is going through the similar process, and you do have joint ownership with them on a bunch of your plants. Would you look to participate through that joint ownership in the Duke process?

You're right, Ali, one of the factors and one of the reasons we proceeded to go out and get a market read on these assets were that some of our partners were out there selling. And obviously, that will have an impact on these assets. It depends on who buys them, how they will be running these operations. So we will continue to closely monitor that process and see what ways we can continue to increase value there. I mean, as you know, we have a program to get more out of these plants from a performance point of view. Maybe Andy would like to just comment on some of the things we're doing there.

Thanks, Andres. We -- in keeping the plants, we have a few things that we're focusing it on, and I'll just talk to the 3. Obviously, we continue our cost reduction program. We've already achieved about $65 million in O&M reductions to date, which is currently in our forecast. We're also looking at 2 other things. One is reliability and improvements at the major stations. For our fleet at DPL, every 1% increase in -- decrease in E4 [ph] gives us about approximately $2 million of adjusted PTC. And also heat rate, which again on a fleet basis, every 1% improvement in heat rate gives us about $3 million to us. So we're focused on both of those programs. We have a lot of experience there, and we should start to see those improvement results in 2015. And lastly, one of the lessons we took away from last year's polar vortex was we really had to refocus on our commercial strategy in working with our risk flow. The operating people are trying to increase operational flexibility by improving the ability to turn down and be much more responsive to markets. So those 3 things we're going to pursue much more aggressively now. And we think we'll start to see the benefit of that in the 2015 timeframe.

To sort of close the topic, also some of our other firms in Ohio are looking at, for example, PPAs and other things. so we're monitoring those things. And we took a decision based that we thought there was more upside at that price than selling it. It would have been a -- I think it shows our discipline in terms of executing on our strategy. I think all of our asset sales, we've executed quite well and really tried to get value from those assets. Even though sometimes we could have done things faster, I think we would have left some money on the table.

Our next question is from Julien Dumoulin-Smith.

So first question here, could you reconcile a little bit what the assumptions are baked into your long-term growth rates? Specifically, I noticed you talk about a higher growth rate in '17, '18. What's embedded in there from both the DPL perspective as well as the hydro and recontracting perspective in Brazil?

I'm going to pass this question off to Tom. But I think that the basic assumptions -- what I can say in terms of the longer forecast -- I mean this is based on the projects that we have under construction today. A big factor is Mong Duong coming online next year, which will produce a lot of cash. We also have Alto Maipo. We have these 4,500 megawatts, which we're constructing. And in terms of the hydro in Brazil, we do assume a return to normal, but we are looking at higher contract prices.

Tom, were you going to add something?

Yes. Sorry, Julien. So the 5-year forecast, we look at it on an annual basis. That's when we talked in our year end call, we laid out. And that was based upon market assumptions at that time. So those were PJM forwards at that time and also Brazil numbers that were around, more like 115 at that time. So as we sit here today, DPL's probably up a couple of cents. And as Andres went through Tietê, we'll probably be up a penny or 2 based upon the forward curves as we see them today. I think that said, we're reluctant to update 5-year guidance on a piece-by-piece basis. But just in isolation, those 2 things would be tailwinds for us. We would plan to give a wholesome 5 year update at the same time next year, which is in Feb when we announce our year end earnings.

Got you. And can you just reconcile a little bit on DPL. I think I heard you saying that it generates, perhaps, breakeven or even negative EPS prospectively. When would you think about next reevaluating this business? Is this really about waiting it out in terms of maturity and seeing what happens in terms of the market, or is it something else?

I think Julien, getting back to sort of our decision, this year it would have been accretive to sell DPL, as Tom pointed out in our last earnings call and mentioned today again. We think given current forward curves that it will be neutral to slightly accretive to have kept it going forward. Now in terms of -- we are always evaluating all of our businesses and updating it. But what I would say is that, as Tom mentioned in his speech, we're thinking about things very much in the portfolio and in terms of looking what's our aggregated risk at the corporate level. And so here, we're saying that basically, given the various factors that are happening in Ohio and the forward curves, we think there's potential upside from having kept Ohio. Of course, we have to always revalue our decisions over time.

I'll move on. On the D -- sorry, on the share repurchase side of the equation, when you're thinking about allocating the rest of the to-be-allocated capital on that pie chart, at what point in time could we see a potential revision in share repurchase? I know it's a little bit re-asking the last question, but I just want to be a little clearer about this.

What I would say, Julien, is that again, we've said that we would buy shares at these prices, and we are doing so. And I don't think that at this stage, we have a number of interesting projects. And we also have the opportunity to pay down debt, which we've announced. I think we've -- Tom stated that we wanted to be a solid BB, and we're keeping our credit metrics within that range. So we'll maintain that balanced capital allocation, say, philosophy going forward.

And then could you talk a little bit about the expansions here? Again kind of with respect to the guidance there, I assume this isn't in there. But the Dominican Republic expansion, how much does that contribute in EPS? And then also Mexico, given increasing competitive pressures, I mean is this something that is attractive to you? How are you thinking about your own participation, and how soon could that come?

Okay. I'd say let's take first the Dominican Republic. This is in our forecast in terms of -- so we expect this to come online mid-2016. So this is in our forecast. This is an attractive project. We have a very good portfolio there in the Dominican Republic. I would say that in terms of Mexico, we have a great brand name there. We have a very good brand name because of the turnaround that we did on 2 pet coke plants. They're [indiscernible] and Tietê. And our offtakers were Grupo Penoles and CEMEX . And so we have a good brand name. People want us to build more plants there and would like to be our offtaker. We have some potential projects. We have to see if those pan out. But I think that the -- it's an attractive market for us. We've done well there. I think it's a market very correlated, let's say, with U.S. risk, in terms of the economy itself. So we're well positioned. We're looking at the opportunities. And let's see if some of these projects are concrete, and we can announce them.

Our next question is from Christopher Turnure. Christopher Turnure - JP Morgan Chase & Co, Research Division: Could you give us a little bit more color on the drivers of the increase in solar power prices in Brazil? And then give us some color as well on how you're thinking about contracting going forward? We see the slide today that shows where you are now, but has that changed? Have you been more aggressive given the power price increase, et cetera?

What's interesting in the case of Brazil -- I mean what is driving it? You had medida provisória, MP 579, which let's say, reduced some of the concession life. Some of the company did not renew their concessions on some of the generation assets. And there was somewhat of a slowdown in new construction. Because of that, there's also been a delay on some of the mega hydros on the tributaries of the Amazon. So put that all together, I think that's partly what's driving the higher prices. There's also been the drought in Brazil. But really, when you’re talking '16 onwards, I think it's -- the bigger effect is MP 579. Our strategy was when we had the sort of, cliff falling off in our contract. We actually took a conservative approach and didn't contact everything right away. Had we done so, we would have re-contracted at the then going price of 95 to 100. We thought that it was likely the market would get tighter, of course, based on our conditions. So -- and that has come true. So I think that in terms of our contracting strategy going forward, we're going to continue to take advantage, let's say, of these higher prices and contract more. But it's a little bit sort of a rolling average. So as you go out over time, we're less contracted. It's also you can't get that many long-term contracts in Brazil. It's going to be these sort of 2 to 3-year contracts. Christopher Turnure - JP Morgan Chase & Co, Research Division: Is there any chance that 2 consecutive years of dry hydrology have actually impacted the outer years at all, even though that's, by definition, a short-term phenomenon?

I don't think so. I really don't think so because I think that everybody expects the droughts to reverse and enter more into a normal cycle of El Niño and La Niña-type phenomena. Christopher Turnure - JP Morgan Chase & Co, Research Division: My second question is on cash flows in the back half of the year. Could you just walk us through how the Eletropaulo kind of true-up works with the regulators there, or with the government subsidy or help plan that they give you? And then kind of how much of a percentage of what you have to make up for in the back half of the year that actually equates to for overall AES?

I'm going to ask Tom to take this question. But basically, the essence is that in both cases, we have higher energy prices that first, we have to pay for the energy and then we bill clients.

Yes, so it's really 2 things. There's tariff adjustments. Both Eletropaulo and Sul have had major tariff adjustments that would capture some of the shorter-term costs, such as purchase power, which is the largest one. And then also there's been a government funding mechanism by the regulator that provides, I think, about $1.2 billion to collectively EP and Sul that allows some direct payment of those higher cost power payments. For us, the big swing factor is Sul. Eletropaulo, we only own 16% of it. It's a more modest amount. But of the $400 million swing that I talked about, of all the utilities, which is down 100 -- or $500 million swing, I'm sorry, down $100 million to plus $400 million from first half to second half, a, about 70% of that is coming out of the U.S. And for us, the lion's share of the Brazilian portion is coming from Sul.

Our next question is from Kit Konolige.

So just to get back to DPL, at least, briefly. Obviously, there have been a few questions on the withdrawal of the capacity for sale. Do you -- can you give us any idea of what you're kind of looking for or what kind of timetable you're looking at that might lead to a remarketing of that capacity, or is that really not in the cards at this point?

I would say at this point, it's -- we're not in the cards. I mean we've taken a decision. We expect to improve the performance of those assets. And we think that there are several factors, several different avenues to significant increase in volume in the future of those generation assets. So of course, we don't know exactly how the future, but we think there are several paths where this could have significant upside.

And when you looked at the bids that were coming in and looked at your process for putting those plants up for sale, what's your conclusion, in retrospect, about the difference between your expectations and the bids you got in? I mean what were the buyers seeing there? Was this just too small of a fleet for people to want to buy into? It would have seemed like a pretty good environment with prices having run up some?

Well, I -- again, I can't get into the minds of the potential buyers. What I would say is that the run-up in forward curves in the better outlook for the RPM capacity also helped us in terms of what we consider our whole value would be.

Kit, it's Tom. I'd just add that obviously, we've done a lot of asset sales around the world, many billions of dollars that have brought $2 billion of cash back to AES. So we've shown an ability to transact. I guess that said, at any -- for all those transactions, when we looked at where the numbers were finally coming down to, we made a judgment ourselves and the board as to whether the assets were worth more to us or more to somebody else. So at least in this case, through a whole lot of factors, it was a tough decision. It was a -- certainly had a lot of discussion. We looked at it hard. We did get real bids from real players, so it certainly was transactable. But it was -- we just thought it worth more to keep than to take the money now.

And then one other area that I'd like to touch on. You sold your position in some solar assets that you had. And you're investing in other solar assets. Can you give us an idea -- I mean you mentioned for the ones that you're selling that you weren't getting adequate returns. And obviously, for the ones that you're going to invest in, you're expecting to get adequate returns. Can you give us an idea what the difference was? In other words, what was wrong with the solar investment that you made previously? And why is the future one going to be better?

Well, the big difference is that going forwards, we're really looking at geographic markets. So we're building solar where we have an existing business. So when I mentioned we have 220 megawatts of permitted solar in Chile, we already have a substation there. We already have all of the infrastructure. So it's far less expensive to operate. It's far less expensive to do the development. So that's really the big change in strategy. What we're looking at is the total cost of doing the project and taking advantage of our platforms. So what we did was exit a number of countries. We had relatively small number of megawatts operating them. And what we're doing is we will build solar in the future because we do many types of energy. We will do the energy -- type of energy that is most attractive and makes the most sense for that market, but that also compliments our portfolio. So that's the big difference. We're going to where we have assets, where we can do the development and operations much cheaper than going into markets where we don't have a presence.

Our next question is from Stephen Byrd.

It's actually Rajeev Lalwani on for Stephen's team. 2 questions, the first, just as it relates to Latin America. We've seen some issues in Puerto Rico and Argentina. How concerned are you that, that could spread to other regions? And then likewise, as you look at the Middle East and Russia and places like that, there's been some more headlines. How can that impact your operations? And then a follow-up.

Okay, talking about -- I think the situation in Argentina is particular to Argentina. I really don't see that spreading. That was a selective default. I'm sure you followed the court cases in New York. And we have 3,000 megawatts of terrific assets in Argentina. They're cash positive and have very little debt on them. They have about $180 million debt for 3,000 megawatts. So [indiscernible], we'll continue to monitor the situation, but we've had really no effect whatsoever to date. If you look at the case of Puerto Rico, it's a case where you do have the commonwealth, as you know, has been downgraded twice. And the reason I mentioned it in my script, we think we have a very strong operation there because we're selling energy at $0.095 per kilowatt hour to PREPA that would cost it $0.20 for itself to self-generate because these are inefficient oil-fired plants. So we have a good contract. It's in our interest. So we're just highlighting that because we wanted to make sure that we covered all of the things that were potential risks. So I don't see those particular situations spreading. Puerto Rico is very unique. Argentina's guys [ph] is very unique. Chile is a very strong economy. Mexico is doing well, Colombia, these are our main other businesses there. Of course, we've already discussed Brazil. So I don't see any contagion. Now moving to Eastern Europe, we talked about Bulgaria. Bulgaria, is somewhat of a unique case, because it actually has a relatively small foreign debt. And so had -- was not that affected by, for example, contamination from Greece. We have been reducing our position in Eastern Europe. We sold Ukraine, you may remember, about 10 months ago. And we're very happy with that decision. How could Bulgaria be affected? Well, Bulgaria does get its gas from Russia, which comes through the Ukraine. So if there were any cut-off of gas from Russia to the Ukraine, it would affect Bulgaria. And that would make our plant even more valuable because it operates on local lignite. And the other thing I would mention about our plant, it's the only EU 16 environmentally compliant thermal plant in the country. So that this is also an important factor to take into account. Now what we've had basically is a transition from the 2 parties and a lack of a firm government. And in that you had a little -- the regulator came out with some rather unexpected statements, which we are trying to manage. So the issue really has been the liquidity situation of the offtaker NEK.

And then maybe a question for Tom. In terms of additional asset sales, can you talk about maybe regions you're targeting and the process for looking at where you're going to sell?

Yes. I think consistent with our prior practice, we'd rather not talk about or speculate on things we might do. Keep in mind that some of these businesses are -- obviously have a lot of relationships with people, stake holders, regulators, et cetera, so we'd rather think through something and then announce it rather than creep it out. Andres talked about a $500 million that would be cash back to parent that may be selling entire stakes or selling minority stakes out on the Philippines.

What I think is important is that -- what I'm saying today is that we had basically met our target for 2014 and 2015 this year. We're saying that we think there could be another additional $500 million. But that would not necessarily be exiting. That could be bringing on partners. Because what we're really focused on now is optimizing our portfolio, optimizing our position in different businesses. So by bringing in partners, this permits us flexibility to try to achieve that optimal portfolio.

Our next question is from Charles Fishman.

Following-up that last question about [indiscernible]. I mean just to make sure I understand. Really, you're dealing with a plant there [indiscernible]. It's a low-cost plant under -- environmentally, it's adequate or even more than adequate. There's, to the best of my knowledge, no talk of nationalization of that plant. So it's really just a receivable from a utility that has a [indiscernible] purchase, that has what appears to be a liquidity issue at the moment. Is that a fair assessment?

I think what you said is fair. One thing I'd say is that our contract in Maritza is not the low cost in the country. Because we had a really state-of-the-art waste disposal facility, which is part of that contract. But you're right in a sense that, really the issue is the liquidity of the offtaker [ph] NEK. NEK sales of energy, it generates us well. Sells energy to the distribution company and also exports energy. Now Bulgaria actually has one of the lowest -- actually has lowest retail tariffs in the EU. So the fact is if the EU rules are enforced, that would retire about 1,000 megawatts in country and make this -- our thermal plant more attractive. And it's also a big employer because again, it uses local lignite. So you're right. I mean the essential problem there really is keeping track of the receivables at NEK and the regulator trying to find various ways to continually to lower retail tariffs. But this has not been [indiscernible] an issue with the government, per se. It's been an issue with the regulator, which is independent of the government.

And then second question. [indiscernible], is that a similar technology to Tietê?

Yes. But we're thinking about putting in it is -- it's basically our energy storage, which are lithium ion batteries in containers. And what we really have is proprietary algorithms to help with the ancillary services. So we tested it out, we're the world leader in this. And that's exactly right.

So it's a lot like Tietê?

It's virtually identical. I mean it's the same containers and it would be used in the same fashion.

And then you mentioned the opportunity for energy storage in Asia. Is that technology, or is that [indiscernible] storage or something else?

It would be exactly the same technology. It works really well in islands where you have sort of isolated grids because you have more instability, especially as you put on more renewables. So we operate on a lot of islands, Hawaii, Northern Ireland, Puerto Rico, and the Philippines, there's a lot of islands. So this is something I spoke to with the President of the Philippines and also his Minister of Energy and Minister of Finance that they're very interested in putting more renewables in, and we could also help that, make it more feasible by putting in the same technology on various of the islands in the Philippines.

And I assume now you're -- I don't know if you're quite a year into Tietê, but the performance has been good. And that's given you a showcase to illustrate the technology.

Yes, you're right. The performance has been very good. And it gives us a showcase here in the States. I mean we are also operating larger units in Chile, so those were some of the first units that came out. So I think that the when you have situations like the polar vortex in Ohio, et cetera, it's very good to have a facility like Tietê, so I think it's been a great time to showcase its abilities.

Our final question today is from Paul Patterson.

Just to follow-up on Argentina and the -- you guys mentioned that an extreme devaluation might change the outlook or something. Could you just elaborate a little bit more exactly? Sort of what's in guidance, and what your comments -- what that meant?

Ahmed, you want to...

Paul, I mean we have assumed devaluation when we gave our forecast for 5 years outlook. We assumed roughly 20% on average annual depreciation in Argentine pesos, and it was more front-end loaded. But we did assume devaluation when we gave our outlook. And just to give you, in context, anything beyond that 20%, every 10% is roughly $6 million pretax earnings for us.

Okay. Then in terms of the DPL assets, there was some discussion, you did touch on the fact that I think FirstEnergy and AEP are looking to have PPAs, sort of for fuel diversity or stability or what have you. I'm just wondering do you see -- are there any opportunities like that for you guys? Is that any part of what your discussion or decision was in terms of retaining these?

What we have said is that we look favorably on this because we do think that if you had a replay of the polar vortex post-'16 and you retired as many plants as would be slated for retirement, coal plants, you would have a problem in PGM and in Ohio. So we look favorably on something like that, that would help secure the stability of the network. Because again, that's the last -- how do I say, the worst time possible to be short power. And you don't have adequate transmission capacity. So we look favorably upon it, and certainly, we will be following that very closely. And it could apply to DPL's generation as well.

And then just -- not to beat up on the DPL thing. But is there any potential for a partial sale of assets associated with the Duke joint ownership process that they're going under? Since you guys own some of the same plants, could some of those go with them, or how should we think about that? Or it's just too early to say?

I'd say it's too early to say. Let's see what happens with their process. What we're interested in is really optimizing the performance of those plants.

I'll now turn the call back to the speakers for closing remarks.

We thank, everybody, for joining us on today's call. As always the IR team will be available to answer any questions you may have. Thank you, and have a nice day.

Thank you, and this does conclude today's conference. You may disconnect at this time.