愛依斯電力 (AES) 2014 Q2 法說會逐字稿

(Operator Instructions)

Today's conference is being recorded. If you have any objections, please disconnect at this time.

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, Elon. 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 www.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 the 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. 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 to date 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 utilities, and we continue to expect to achieve our full-year guidance.

Now, turning to the progress we're making on executing our strategic plan, I'm pleased with our results to date. As you can see on slide 5, the main objectives we set out almost three 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 up-tick 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 two 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 two new transactions together represent $631 million of proceeds, implying a PE multiple of more than 14 from these businesses and in-line with our expectations 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 interest in certain businesses in markets where we want to exit, decrease our exposure, or reinvest our capital in platform expansion. 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 expansion, which provide us with a path for growth with higher risk adjusted return, we now have 4500 megawatts of new capacity and 2400 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's 33-year history.

As you can see on slide 8, we have achieved commercial operations on time and on budget at the 247 megawatts IPP4 power plant in Jordan which has a long-term contract with the state owned utility. We also recently broke ground on three new platform expansion projects in the second quarter totaling 702 megawatts in the US and Chile.

The 671-megawatt Eagle Valley CCGT and 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 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 of the world, we recently broke ground on 21-megawatt solar project with a long-term PPA with a local mine. Including this project under construction, we're 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 non-recourse debt and by our partners on various projects. Our total equity contribution in these projects is approximately $1.5 billion, which we 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 in cash flow growth over the next few years.

Furthermore, we are 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 5000 megawatts in our core markets.

Turning to slide 10, we have significant brown field potential at our Southland gasfired 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 California's mandate for at least 1325 megawatts of energy storage.

Turning to slide 11, as we discussed on our last call, we are closing the cycle at our 236-megawatt DPP plant in Dominican Republic, increasing its capacity by 122 megawatts. We recently signed a six-year PPA with a state owned utility and selected an EPC contractor.

We're 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 are looking at growth opportunities is Mexico. We've been in Mexico for almost 15 years and currently own three power plants, making us one of the largest independent power producers in the country. Mexico was a big market and more importantly has potential to increase its install capacity by more than 25,000 megawatts in the next five to seven years through recently proposed reforms to the energy loss.

Now onto 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 are ready have all of the necessary permits for the 600 megawatt Masinloc expansion and we are working to secure ETC and power up-tick agreements. We're also developing up to 200 megawatts in energy storage projects to meet ancillary service requirements and peak demand needs for the system.

Turning to slide 14, in Vietnam, construction of our 1240-megawatt Mong Duong project is progressing well. We recently synchronized to the national grid and achieved full load on unit 1 of 560-megawatt.

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 are assessing further growth opportunities in Vietnam including both Greenfield and privatization of government owned generation plants.

Turning to slide 15, significant development that aids the execution of our strategy is our ability to incorporate financial partners at project and business levels. Since we started this initiative two 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 commitment to specific projects, managing our aggregate risk profile at the corporate level and improving our returns through promotes and management fees.

It also gives a mechanism to demonstrate the value of our assets in markets where there are few or no listed comps. Some recent examples of this are Guacola 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.

Addressing our third object on slide 16, reducing global overhead to become the low-cost manager of a portfolio of assets, we are well on our way. We are 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 year and a half. I'm pleased to report 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 are accomplishing these reductions through process improvements in 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 higher return projects, I would say, we are continuing to make very good progress. Nonetheless, we are 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, we continue to see tight demand and supply conditions having a positive impact on forward power prices, which are now BRL180 to BRL210 per megawatt hour for 2016. As you may know, this is about the same price as existing contract that expires in 2015 and is almost 50% higher than the price we assumed in our expectations for 2016. Three quarters of [Chiete's] capacity 2016 is contracted 2016 at BRL125 per megawatt hour.

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 BRL10 improvement in power prices translate into $0.01 of adjusted EPS for AES.

Turning to slide 19, I will discuss development 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 for proceedings initiated in response to this request.

Additionally, as we discussed in the past, the energy regulator has instructed NEK, the state owned utility that is offtaker under our contract to initiate negotiations on the terms of the PPA in order to lower its payment. We have had several discussions with NEK and various government authorities concerning the regulator's actions.

Maritza continues to be engaged in resulting this matter as well as in recovering our expanding 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 four months. As of July 31, Maritza has $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 EPC. While the situation is challenging, Maritza's objective is to preserve the value of the business to a negotiated agreement while seeking to enforce 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 selected default, we continue to closely monitor the situation. In Argentina, where we generate about 3% of our PTC, we have a competitive fleet of 3000 megawatts of generation capacity, which is an important source of reliable generation in the country.

Additionally, we have taken steps to dollarize our accounts receivable in Argentina. Although we have factored the evaluation of the Argentine peso into our forecast, and extreme devaluation could have negative impact on our results.

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 of the commonwealth and its corporations. AES Puerto Rico contributes about 2% of our PTC.

PREPA's facing business and liquidity challenges primarily driven by 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 our plant saves PREPA an estimated $250 million per year.

These are some of the key areas we are 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 are addressing our exposure through a selective asset sale down and rebalancing our fuel mix through platform expansion to create an even more robust company. With that, I would 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 will go through our second quarters 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 pre-tax 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. We expect to achieve adjusted EPS in the low end of our guidance range.

Improvements in our businesses in the US, Andes, Brazil and also our 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 discrete items, the net effect of which was positive $0.02.

We also benefited from investing in our balance sheet, which added $0.02 to the bottom-line. This is driven by two factors. First our share count is down by 3%, 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.

Tax rate was 40% this quarter, higher than last year's second quarter's unusually low rate of 11%. (inaudible) 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 would like to touch on some developments at DPL on slide 23. The Commission has ruled on all pending matters on 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 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, we received reasonable bids, the offers we're not attractive relative to the at long-term value AES, and we therefore decided not to sell.

The only generation would have left the remaining business with significant amount of debt. At the same time, this high debt level increases our leverage to improvements in the energy market.

Following factors contributed to our decision. First, movements in power prices as witnessed in first half of this year create a more positive outlook. We appreciate these curves have come up and made peaks; however, the market is still higher than what we projected at the start of the year.

Second, we saw improvement in PGM RPM prices, which doubled albeit from a lower level at last auction. Outstanding proposals could provide additional improvement.

Third, we're implementing a plan to further improve operations of the business, particularly related to improved plant performance. Fourth, we will continue to optimize our positions through our multi-year commercial hedging strategy.

Overall, through 2016 when ESP expires, EPL is expected to generate annual EBITDA of about $350 million, of which about $80 million to $100 million is attributable to generation business with the rest coming from the TND business and the non payments under the current ESP. Based on current forwards, EPL is projected to generate $100 million of free cash flow annually, and our plan is to use any excess cash to repay debt which is currently $2.3 billion. We provided additional details on hedging and debt maturity profiles of DPL in the appendix.

Bottom-line is DPL 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 are successful in capturing the market and operating improvements I just discussed.

Now to slide 24, I will discuss each of our SBUs focusing on adjusted PTC or PTC. In US, we reported an increase of $17 million of PTC, largely driven by the synchronous condensers in Southland and new 40-megawatt energy storage resource in Ohio.

In our Andes SBU, PTC was up $16 million. We benefited from a higher tariff in 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 $24 million reversal of a liability at Uruguaiana in the second quarter of last year. Excluding these one-time items, PTC increased by $14 million as we benefited from higher contributions that Uruguaiana and Sul.

Moving to Mexico, Central America and the Caribbean, PTC declined $9 million. It benefited from the steps that were taken to offset adverse Hydro conditions at Panama, including payment from the government under negotiated agreement to compensate for exposure to high spot prices up to $40 million this year and $100 million total in 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 the UK 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 Philippines we're adversely affected by forced outages in the second quarter with 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 use these outages to complete maintenance we have planned for next year.

To summarize, as shown on slide 26, total year-to-date adjusted PTC is roughly $583 million or 43% at 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 expect a low to mid 30% tax rate.

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 in utilities in Brazil. This brings our year to date proportional free cash flow to $176 million versus $526 million for six months of 2013.

We recognize this year is significantly lower than last year, as we had a $300 million swing on utilities in the US and Brazil driven primarily by working capital requirements. This is typically in Brazil, as we discussed on our last call, system operators dispatching thermal generation to preserve reservoir levels, causing higher spot prices. These are spot prices did not affect our utility earnings through the passage nature of energy purchases.

However, there is an adverse impact on working capital as there's a lag due to periodic tariff adjustments approved on an annual basis. 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 pending government support mechanisms.

In the US, during the first half of the year, cash flow at EPL and IPL were affected by higher working capital requirements. Outages at EPL and upfront funding annual pension contributions at IPL.

Working capital requirements at our US utilities were driven by high receivables from our regulated customers as result of higher fuel prices and energy purchases during the cold weather in first quarter. Our guidance assumes 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 seasonality factor, the second half we expect to recover significant short-term working capital drag as discussed. In fact, our utilities in the US 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 it will generate $1 billion to $1.3 billion this year. We're very focused on our businesses having a strong second half to achieve this goal.

On to slide 28 and capital allocation plans 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.

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 have 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 we recently culled and the $140 million prepaid this year. About half of the targeted debt reduction this year relates to our policy 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 risk, consistent with previously stated balanced capital allocation strategy.

Since our first quarter call in May, we invested $47 million in our shares. Brings our overall investment in share repurchases to $758 million for September 2011, reducing our share count by 8%. After $145 million in dividends to shareholders, any target closing cash balance of $100 million, we are projecting $300 million to $500 million discretionary cash to be allocated this year plus any additional assets sales would increase the amount available.

First half of year, our allocation capital to share repurchases has been modest as we've been more focused on reducing our debt and making investments and attractive returns to generate growth in earnings and cash flow. Over the past two 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 purchase more shares in the second half. The bottom-line is we will continue to be disciplined and invest our cash to maximize risk adjusted returns to our shareholders on a per-share basis.

Now to slide 29, we are reaffirming our guidance we expect to be in lower-end of our adjusted EPS range of $1.30 to $1.38. Our first quarter call, when we updated our guidance we discussed several items we expected would help us mitigate the $0.07 to $0.10 impact of hydraulogy. One of these offsets was the expectation for benefit from selling EPL's generation business and removing it from continuing operation of this year.

Although we decided to retain this business, therefore, not had that benefit this year, the Sul reversal 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 will now turn it back over to Andres.

Thanks, Tom. In summary, although we're facing short-term headwinds, we are taking concrete steps to lower our portfolio risks and increase per share value. Since we set out our strategy September 2011, we are on target to reduce global overhead by $200 million by next year, and we are focusing on additional O&M cost reductions.

We have raised $2 billion in asset sale proceeds. We have paid down 20% of our parent debt, invested $758 million in our shares, reducing share count by 8%, and we are selectively investing in platform expansion opportunities to yield attractive risk-adjusted returns.

Through these actions, we have 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 a proportional free cash flow growth of 10% to 15% per year. In total return to shareholders of 8% to 10% by 2017. Now, I would like to open up the call for questions.

(Operator Instructions)

Our first question today is from Ali Agha, SunTrust.

Thank you, good morning.

Good morning, Ali.

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

Yes. Those are factored in, Ali.

Is it fair to say the asset sale proceeds, are the earnings going away from asset sales or being offset by 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 that a thought on you getting even more aggressive on the buyback, given where the stock is, Andres? 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. We are looking at investments that we are making, as I have said in the past, we compete those against share buybacks. Obviously, when you look at the returns that we are projecting, 16% cash returns, and a 15% ROE, we think those are superior to what we are getting back from buyback. We are taking a balanced approach. We are saying that -- we said last time we would buy back shares. We are doing that.

We do realize that the cash that we received from these assets sales was also quite recent. We only received it in the last month. I think we are doing exactly what we said that we would do, that we would buy back shares, but we'd also compete for new projects. 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.

Okay. And then, Andres, 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. Should we view these assets now as core holdings and that sale is completely off the table? 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 the joint ownership in the Duke process?

You are 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. Obviously that will have an impact on these assets. It depends on who buys them, how they will be running these operations. We will continue to closely monitor that process and see what ways we can continue to increase value there.

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 comment on some of the things we are doing there.

Thanks, Andres. Good morning, Ali.

In keeping the plants, we have a few things we are focusing in on. I will just talk to three. Obviously, we continue our cost reduction program. We've already achieved about $65 million in owned in reductions on to date, which is currently in on our forecast.

We are also looking at two other things. One is, reliability and improvements at the major stations and for our fleet at DPL every 1% increase in -- decrease in E-4 gives us about approximately $2 million of adjusted PTC. Also heat rate, which again on a fleet basis, every 1% improvement in heat rate gives us about $3 million to us. We're focused on both those programs; we have a lot of experience there. We should start to see those improvement results in 2015.

Lastly, one of the lessons we took away from last year's polar vortex was we really had a refocus on our commercial strategy in working with our risk folks. The operating people are trying to increase operational flexibility by improving ability to turn it down and be much more responsive to markets. Those three things we are going to pursue much more aggressively now, and we think we will start to see the benefit of that in the 2015 time frame (multiple speakers).

To close the topic, also some of our other firms in Ohio are looking at, for example, EPAs and other things. We're monitoring those things. We took a decision base that we thought there was more upside at that price than selling it.

It would have been -- I think it shows our discipline in terms of executing on our strategy. I think all of our asset sales, we have executed quite well and really tried to get value from those assets. Even though sometimes we could've done things faster, I think we would have lost -- left some money on the table.

Thank you, Andres.

Thank you. Next question from [Julian deMullen Smith].

Hello, good morning.

Good morning, Julien.

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 growth rate in 2017 and 2018. What is embedded in there from both a DPL perspective, as well as a hydro and recontracting perspective in Brazil?

I'm going to pass this question off to Tom. I think that the basic assumption is what I can say in terms of the longer forecast, this is based on the projects that we have under construction today. A big factor is Long John 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 constructiing. In terms of the hydro, in Brazil we do assume a return to normal, but we are looking at higher contract prices.

Tom, are you going to answer me?

Yes, sorry, Julian. The five-year forecast we look at on an annual basis, and that's when we talked on 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 million at that time.

As we sit here today, DPL is probably up a couple cents and, as Andres went through, Tiete will be up a penny or two based upon the forward curves as we see them today. That said, we are reluctant to update five-year guidance on a piece- by-piece basis, but just in isolation those two things would be tailwinds for us. We were planning to give a wholesome five-year update at the same time next year, which is in February when we announce our year-end earnings.

Got you. 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 the maturity and seeing what happens in terms of the market, or is it something else?

I think, Julian, getting back to sort of our decision, this year it would've been accretive to sell DP&L as Tom pointed out in the 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. What I would say is, as Tom mentioned in his speech, we are thinking about things very much in the portfolio in terms of looking, what's our aggregated risk at the corporate level? Here, we're saying that, basically given the various factors that are happening in Ohio and the forward curves, we think there is potential upside from having kept Ohio. Of course, we have to always revalue our decisions over time.

All right. Great. I'll move on.

Sorry -- on the share repurchase side of the equation, when you are 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 this is a little bit re-asking the last question, but just want to be a little clearer about this.

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

Got you. Could you talk a little bit about the expansions here, again, with respect to the guidance? I assume this is not in here. The Dominican Republic expansion, how much did that contribute in EPS? And then also Mexico? Given increasing competitive pressures there, is this something that is attractive to you? How are you thinking about your own participation and how soon could that come?

Okay, I would say -- let's take first the Dominican Republic. This is in our forecast in terms of -- we expect this to come online mid-2016. 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, a very good brand name because of the turnaround that we did on Tupat coke plants there (inaudible) and our off-takers were Grupo Penoles and Semex. And so we have a good brand name. People want us to build more plants there and would like to be our off-takers.

We have some potential projects; we have to see if those pan out. But I think that the -- it's a attractive market for us. We have done well there. I think it is a market very correlated, let's say, with US risk in terms of the economy itself. We are well-positioned. We are looking at the opportunities. Let's see if some of these projects are concrete and we can announce them.

Great. Thank you.

All right. Thank you, Julien.

Next question is from Christopher Turnier.

Good morning. 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 are thinking about contracting going forward? We see the slide today that shows where you are now. 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 Provisoria NP 579, which if they reduced some of the concession lines, some of the companies did not renew their concessions on some of the generation assets. And there was somewhat of a slowdown in new construction because of that and there has also been a delay on some mega hydros on the tributaries at the Amazon.

So put that all together, I think that is partly what is driving the higher prices. There has also been the drought in Brazil. But, really, when you're talking 2016 onwards, I think it's -- the bigger effect is NP-579. Our strategy was, when we had this sort of cliff falling off in our contract, we actually took a conservative approach and did not contract everything right away. Had we done so, we would have recontracted at the then going price of [$95 to $100].

We thought that it was likely the market would get tighter. Of course, you know, based on our conditions, so --and that has come true. I think that in terms of our contracting strategy going forwards, we are going to continue to take advantage, let's say, of these higher prices and contract more. It is a little bit sort of a rolling average. As you go out over time we're less contracted. And it's also you can't get that many long-term contracts in Brazil. It's going to be these two-, three-year contracts.

Is there any chance that two 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 Nino and La Nina type phenomenon.

Okay. Great. My second question is on cash flows in the back half of the year. Could you just walk us through how the Eletropaulo true-up works with the regulators there or with the government subsidy or help plan that they give you? 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. First, we have to pay for the energy and then we bill clients.

Yes. It is really two things. There's the tariff adjustments, both Eletropaulo and Sulo had major tariff adjustments that would capture some of the shorter-term costs such as purchase power, which is the largest one. Also there has been a government funding mechanism by the regulator that provides about $1.2 billion to collectively EP and Sul that allows some direct payment of those higher cost of power payments.

For us, the big swing factor is Sul. Eletropaulo, we only own 16% of it, it's a more modest amount. Of the $400 million swing that I talked about, of all the utilities, which is down -- or $500 million swing, I'm sorry, down $100 million to plus-$400 million from first half to second half. 70% of that is coming out of the US. And, for us, the lion's share of the Brazilian portion is coming from Sul.

That is helpful. Thank you very much.

Next question, Kit Konolige.

Good morning, folks.

Good morning.

Just to get back to DPL at least briefly, obviously there have been a few questions. On the withdrawal of the capacity for sale, can you give us any idea of what you are looking for or what kind of timetable you are 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 that at this point, we are not in the cards. We have taken a decision. We expect to improve the performance of those assets. We think that there are several factors, several different avenues to significant increase in value in the future of those generation assets. Of course, we don't know exactly how the future, but we think there's several paths where this could have significant upside.

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? 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.

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

Kitt, it's Tom. I would just add that, obviously, we've [fell on] asset sales around the world, many billions of dollars that have brought $2 billion in cash back to AES. We have shown an ability to transact.

That said, 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 someone else. And so, at least in this case, through a whole lot of factors -- it was a tough decision. We certainly had a lot a discussion. We looked at hard -- we did get real bids from real players. Certainly was transactable. But it was -- we just thought it was worth more to keep than to take the money out.

Great. Thanks for that. 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 are investing in other solar assets. Can you give us an idea -- you mentioned before the ones that you are selling that you weren't getting adequate returns.

Obviously, for the ones that you are going to invest in, you're expecting to get adequate returns. Can you give us an idea what the difference -- in other words, what was wrong with the solar investment that you made previously? Why is the future one going to be better?

The big difference is that going forwards we are really looking at geographic markets. We are building solar where we have an existing business. 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. It is far less expensive to operate. It is far less expensive to do the development.

That is 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. What we did was exit a number of countries. We had relatively small number of megawatts operating them. What we are doing is we will build solar in the future. We do many types of energy. We will do the type of energy that is most attractive and makes the most sense for that market, but then also complements our portfolio.

That is 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.

Great. Thank you.

Our next question is from Steven Byrd.

It is actually [Rahay Volyani] on Steven's team. Two questions. The first, just as it relates to Latin America. We have 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 have been some more headlines. How can that impact your operations and then a follow-up?

Okay. Let's talk about Lat -- think the situation in Argentina is particular to Argentina. I really don't see that spreading. That was a selected default. I'm sure you have followed the court cases in New York.

We have 3,000 megawatts of terrific assets in Argentina. They are cash positive and have very little debt on them. We have about $180 million of debt for 3,000 megawatts. So our (inaudible) will continue to monitor the situation but we have had really no affect whatsoever to date. If you look at the case of Puerto Rico, it is a case where you do have the Commonwealth, as you know, has been downgraded twice.

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 costs it $0.20 for itself to self-generate because these are inefficient oil-fired plants. We have a good contract with -- it's in their interest. We are just highlighting that because we wanted to make sure that we covered all of the things that were potential risks.

I don't see those particular situations spreading. Puerto Rico is very unique. Argentina's case is very unique. Chile is a very strong economy. Mexico is doing well. Columbia. These are our main other businesses. And, 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. It was not 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. We are very happy with that decision.

Could Bulgaria be affected? Bulgaria does get its gas from Russia, which comes through the Ukraine. If there were any cut-off from 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.

The other thing I would mention about our plant, it's the only EU-16 environmentally compliant thermal plant in the country. This is also an important factor to take into account. What we have had basically is a transition from the two parties and a lack of a firm government. In that, the regulator came out with some rather unexpected statements which we are trying to manage. The issue really has been the liquidity situation of the off-taker NEK.

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

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

Yes. What I think is important is that -- what I'm saying today is we had basically met our target for 2014 in 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 are 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.

Perfect. Thank you, gentlemen.

Thank you. Next question from Charles Fishman.

Thank you. Following up that last question about (inaudible), just to make sure I understand, really, when you're dealing with a plant there, as you are, that'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 to that plant. So it is really just a receivable from a utility that has a (technical difficulty) 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 would 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. You are right in the sense that the -- really the issue is the liquidity of the off-taker NEK. NEK has -- it sells energy. It generates as well, sells energy to the distribution companies and also exports energy.

Now, Bulgaria actually has one of the lowest -- actually has the lowest retail tariffs in the EU. The fact is that if the EU rules are enforced, that would retire about 1,000 megawatts in country and make this -- our thermal plant more attractive. It is also a big importer because it uses local lignite.

You are right, the essential problem there really is the keeping track of the receivables at NEK and the regulator trying to find various ways to continually lower retail tariffs. This has not been, it sounds like, an issue with the government, per se. It's been an issue with the regulator, which is independent of the government.

Okay. Second question, Warrior Run, is that a similar technology to Tiete?

Oh, yes. But we're thinking of putting it -- it is 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. We are the world leader in this and that is exactly right.

So it is a lot like Tiete?

It is virtually identical. It is the same containers and same -- it would be used in the same fashion. You mentioned the opportunity for energy storage in Asia. Is that technology or is that pump storage or something else? It would be exactly the same technology. It works very well in islands where you have some isolated grids because you have more instability, especially as you put on more renewable.

We operate on a lot of islands, you know, Hawaii, Northern Ireland, Puerto Rico. And the Philippines is a lot of islands. This is something I spoke to with the President of the Philippines and also his Minister of Energy and Minister of Finance. But they are 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.

I assume now you're -- I don't know if you're quite a year in the Tiete, but the performance has been good and that's giving you a showcase to illustrate this technology?

Yes. You are right. The performance has been very good. It gives us a showcase here in the states. We are also operating larger units in Chile. Those were some of the first units that came out. I think when you have situations like the polar vortex in Ohio, et cetera, it is very good to have a facility like Tiete, so I think it's been a great time to showcase its abilities. (Inaudible - multiple speakers)

Certainly. Our final question today is from Paul Patterson.

Hello. Can you hear me?

Yes. We can hear you.

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

We have assumed devaluation when we gave our forecast for five-years outlook. We assumed roughly 20% on average and will depreciation in Argentine pesos. It was more front-end loaded, but we did assume the devaluation when we gave our outlook. Just to give you, in context, anything beyond that 20%, every 10% is roughly $6 million pretax earnings for us, which is --

Okay. That sounds fine. I just wanted to make sure I wasn't missing something. In terms of the DPL assets, there was some discussion. You did touch on the fact that I think First Energy and AEP are looking to have PPAs for fuel diversity or stability or what have you. I was just wondering, are there any opportunities like that for you? Is that any part of what your discussion or decision was in term of retaining these?

What we have said is that we look favorably on this because we do think if you had a replay of the polar vortex post -2016, and you retired as many plants as would be slated for retirement, coal plants, you would have a problem in PJM and in Ohio.

We look favorably on something like that that would help secure the stability of the network. Because, again, that is the last -- how would I say? The worst time possible to be short powered. You don't have adequate transmission capacity. We look favorably upon it. Certainly, we will be following that very closely. If it -- it could apply to DP&L's generation as well.

Okay. And then 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 are going under? Since you don't [sit on] the same plant? Could some of those go with them or how should we think about that, or is it too early to say?

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

Okay. I got you. Thanks a lot.

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

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

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