愛依斯電力 (AES) 2014 Q4 法說會逐字稿

Good morning. My name is Sean. I'll be your conference operator today.

At this time, I'd like to welcome everyone to The AES Corporation's fourth-quarter and full-year 2014 financial review conference call.

(Operator Instructions)

Vice President of Investor Relations, Mr. Ahmed Pasha, you may begin your conference.

Thank you, Sean. Good morning, and welcome to our fourth quarter and full year 2014 earnings call. 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 fourth-quarter and full-year 2014 earnings call.

Today, I will, first, review our 2014 results; second, discuss the current macroeconomic environment and how it will affect our 2015 guidance; third, provide an update on the execution of our strategy to date; fourth, share my thoughts on capital allocation; and fifth, discuss our priorities for 2015. Then Tom will discuss our 2014 results and 2015 guidance and longer-term expectations in detail.

Turning to slide 4: during 2014 we made significant progress on our strategy and continued to position our Company for the future. During this year, we brought in financial partners to invest $1.9 billion in our subsidiaries; announced or closed 10 transactions for $1.8 billion in equity proceeds from asset sales; broke new ground on six new platform expansion projects, totaling 2,200 megawatts; and won long-term contracts to build 1,400 megawatts of capacity in California. We allocated $600 million to reduce parent debt and improve our credit profile, returned $450 million to shareholders through dividends and buybacks, and announced a doubling of our dividend with an intended growth rate of 10%.

Turning to slide 5: unfortunately our financial results for the year were affected by $0.10 of adverse hydrology in Panama and Brazil. Still, we earned an adjusted EPS of $1.30, which was at the lower end of our original guidance range of $1.30 to $1.40 and slightly better than our expectations at the end of our third quarter call in November. We are disappointed with our proportional free cash flow of $891 million. Although proportional free cash flow came in at the low end of our revised guidance, it is 20% lower than our original guidance, primarily driven by the higher working capital requirements in Brazil and Chile, as well as increased receivables in Bulgaria, all of which we expect to reverse in 2015.

Turning to slide 6, I would like to outline several factors affecting our 2015 outlook. Importantly, we have taken a number of steps to mitigate their impact. Since our last call, we've seen international macroeconomics factors move against us. Currency and commodity forwards have declined significantly. Although we are largely contracted and the majority of our earnings are US-dollar linked, this downward shift in forward curves has affected some of our businesses and consequently our earnings expectations for 2015 and beyond.

We're also seeing continuing poor hydro conditions in Brazil, especially in the state of Sao Paulo where our hydros are located, rather than a return to normal hydrology as we had previously assumed. We've been taking actions to lower our sensitivity to hydrology by adopting more optimal hedging strategies in Panama and Brazil. In Panama, we're bringing in a 72-megawatt oil-fired barge. In Brazil, we're working on creative solutions to supply additional energy, such as pursuing opportunities to restart long-term operations at our 640-megawatt Uruguaiana CCGT plant, which has not operated continually for many years due to lack of fuel. We're also exploring options to export energy from Chile and Argentina to the Brazilian grid. In parallel, we are proactively hedging our FX exposure in Brazil, Colombia, and Europe, where, since our last call, we have entered into additional hedges to shield 40% of our exposed earnings from further volatility.

In our 2015 guidance, we're also assuming that ongoing negotiations in Bulgaria will have some earnings impact on our Maritza business. The energy minister of Bulgaria recently issued a communique in which he committed to paying Maritza's outstanding receivables of approximately $260 million and announced ongoing discussions to reduce the contract price. Additionally, the government is taking steps to improve the financial position of our off-taker, NEK, by reducing the volume of expensive energy that NEK is purchasing from other market participants and compensating NEK through environmental taxes. The Bulgarian government has targeted closing this negotiation and addressing NEK's financial situation in the first half of this year. All the negotiations have not been finalized; we're incorporating modest earnings dilution in our future expectations, which we believe is sufficient to accommodate the outcome of the discussions currently underway.

The combined earnings impact of the macroeconomic factors in hydrology in Brazil, as well as the potential outcome of the PPA negotiations at Maritza, is approximately $0.18. Through proactive steps including additional hedges, revenue improvement, and cost savings, we expect to offset $0.13 of the total, and therefore are reducing our adjusted EPS guidance to $0.05 to a revised range of $1.25 to $1.35.

Notwithstanding the impact on our earnings from these factors, we are also reaffirming our 2015 proportional free cash flow range of $1 billion to $1.35 billion, which is 30% higher than our 2014 results. This growth is largely driven by the recovery of working capital in Brazil and Chile, as well as the reduction in accounts receivable in Bulgaria, and the contributions from new plants coming online this year, such as the 1,240-megawatt Mong Duong project in Vietnam, and 72-megawatt oil fired barge in Panama.

Turning to slide 7, I will discuss our continued progress on our strategic objectives which we laid out in 2011, including reducing complexity, performance excellence, expanding access to capital, and leveraging our platforms. First: reducing complexity. Since 2011, we've reduced the number of countries where we operate from 28 down to 18 and raised $3 billion in equity proceeds from asset sales. In 2014 alone, we closed 10 transactions totaling $1.8 billion in equity proceeds to AES. In addition to simplifying our portfolio, we recently exited riskier markets such as Ukraine, Nigeria, and Cameroon in a timely manner at attractive evaluations. As a result of our efforts, 80% of our 2014 earnings and proportional free cash flow was generated in 10 countries in the Americas. Regarding performance excellence, we believe that we are now the low-cost manager of a large portfolio of international energy assets.

As you can see on slide 8, we have reduced our global G&A by about a third, or $200 million, achieving the goal we established in 2011 one year early. Going forward, we're focusing on additional cost savings initiatives including savings $100 million in O&M by 2018.

Turning to slide 9, through financial partnerships, we're expanding our access to capital and fine-tuning our portfolio's global macroeconomic exposures and commodity risks. In most cases, we earned management, development, or promote or up-front fees. Partial sell-downs of our assets also served to highlight the value of the business in our portfolio. In total, we have raised $2.5 billion in proceeds to AES through financial partnerships. In 2014, we brought in partners at four of our businesses including CDPQ, a long-term institutional investor headquartered in Quebec, Canada, which recently invested in Ipalco in Indiana. We look forward to working with CDPQ on additional partnering opportunities in the US and Latin America.

Turning to leveraging our platforms on slide 10 -- we're exclusively focusing our growth on platform expansions including adjacencies such as energy storage and desalinization. Adjacencies are smaller investment opportunities that are replicable across our portfolio and have higher returns with a much shorter construction period. To that end, we recently made a $25 million investment to acquire Main Street Power, a developer of distributed solar. Although modest in size, this business will provide us with the know-how to implement distributed solar generation in some of our international markets where power prices are higher and solar resources greater. We will focus on commercial and industrial customers.

We currently have a total of 1,141 megawatts under construction, the most in AES' 34-year history. These projects represent $9 billion in total capital expenditures, the vast majority of which is being funded by a combination of nonrecourse debt and partner equity. More importantly, our required equity for these projects is $1.5 billion, of which we've already funded 70%. In terms of where these projects are located, as you can see on the right-hand side of the slide, 40% of the capacity under construction is in the US. The 1,400 megawatts of Southland contracts we recently won are not yet included in these numbers, since we have not yet broken ground. If they were, the US would represent 50% of the new capacity.

We're earning very attractive risk-adjusted returns on these projects. For competitive reasons, we cannot provide details on a project-by-project basis. However, we will provide some general guidelines. For international projects, we're seeing IRRs from the mid-teens to more than 20%, with project-specific returns varying, reflecting project and country risk premiums. For US projects, IRRs are in the low-double digits. Including all of our projects under construction, the average IRR is around 14%, and the ROE is greater than 50%. We would expect to earn at least as much from new projects in our development pipeline.

Turning to slide 11, I would emphasize that, as we have done in the past, we will compete all new projects with share buybacks, and furthermore we will only invest in a new project if it meets the following criteria. First, it enhances the value of an existing business, such as the MATS CapEx program at IPL in Indiana or the oil-fired barge in Panama. Second, it offers compelling risk-adjusted returns while minimizing AES Corp equity by using project level cash or local leverage capacity. Examples include closing the cycle at our DPP plant in the Dominican Republic and energy storage. Finally, for any large project, we would expect to bring in a partner to maximize our returns and allow us to fine-tune our total exposure in the project.

The bottom line is that our successful execution on the four pillars of our strategy that I just discussed have positioned us to deliver average annual cash flow growth of 10% to 15% over the next four years as our construction projects come online. We expect to grow our dividend 10% per year from today's level as cash flow increases. Given all that, we believe that our current share price does not reflect the progress we have made in our Company and portfolio or the value from our largely funded construction program. Therefore, we have taken advantage of low share prices by buying back $150 million of our shares since our third-quarter call. Today, we have announced that our Board has authorized an additional $400 million for share repurchases, the majority of which we expect to utilize in 2015.

Finally, as you can see in slide 12, our overall capital allocation over the last three years has been very shareholder-focused. In fact, we have allocated 78% of our discretionary cash to parent debt prepayments and returning cash to shareholders. Specifically, we've allocated $1.6 billion to decrease our parent debt by 20% and improve our financial flexibility. We've also reduced our share count by 10%, buying back 78 million shares at an average price of $12.69. And with the recent doubling of our dividend, we're now paying $0.10 per share per quarter, and we expect to grow the dividend 10% annually.

We recognize that 2015 will be a challenging year due to negative macroeconomic factors in international markets and poor hydrology in Brazil. Nonetheless, we will continue to execute on our strategy to create shareholder value by pulling the levers we have outlined today.

With that, I will now turn the call over to Tom, who will provide greater detail on our 2014 results and 2015 forecast.

Thanks, Andres, and good morning, everyone.

Today, I'll review our fourth quarter and full year results including adjusted EPS; adjusted pre-tax contribution, or PTC, by strategic business unit, or SBU; and our cash flow. Then I'll discuss our 2014 and 2015 capital allocation plans, 2015 guidance, and our longer-term expectations.

As Andres just discussed, we've achieved a number of our objectives in 2014, despite the impacts from adverse hydrology and other factors. From an EPS perspective, we were able to offset these issues through operational improvements, accelerated cost savings, and our capital allocation decisions, including share repurchases and debt prepayments. Admittedly, our 2014 proportionate free cash flow was disappointing due to higher working capital requirements and increased receivables.

Turning to slide 14, our fourth quarter adjusted EPS was $0.41 compared to $0.29 in the fourth quarter of 2013. Overall, our businesses contributed $0.08, driven by higher earnings of US, Brazil, and Andes SBUs. We also benefited from a 3% reduction in share count, lower parent interest expense, and improved corporate charges, which contributed $0.07. These benefits were offset by a $0.03 impact from tax. The adjusted effective tax rate in the quarter was 25%, which was higher than the 18% rate we had last year. Detailed drivers of our fourth quarter PTC performance by SBU are in the appendix.

Moving to slide 15 and our full year EPS of $1.30 per share, compared to 2013, we benefited from $0.07 of better operating performance at our US SBU and our utilities in Brazil, plus a smaller impact from hydro; $0.03 from several other items including recognition of higher interest income on receivables in Argentina than in 2013; and $0.11 from capital allocation and lower corporate charges. These benefits were offset by $0.06 from outages in the first nine months and a $0.14 impact from a higher adjusted effective tax rate of 30% versus 21% in 2013. We ended up with $1.30, which was at the low end of our original guidance range.

Turning to slide 16 -- our results by SBU were in line with the adjusted PTC modeling ranges we provided in November. The main driver that helped us come in at the high end of our revised EPS range was the 30% tax rate, which was slightly below what we were expecting and equates to a couple cents of earnings. Now to slide 17. Poor hydrology in Latin America continued to be a headwind in 2014, with a $0.10 impact to our adjusted EPS versus normal conditions. Although this was a meaningful impact, it was about 25% lower than what we experienced in 2013 due to favorable hydro conditions in Colombia and our proactive steps in Panama.

Now going to hydrology by market, beginning with Colombia: in 2014, Chivor had favorable inflow conditions relative to the rest of the country, which allowed us to sell excess power into the spot market at attractive prices, adding $0.03. Currently, inflows at Chivor are 92% of average, and we're expecting a normal year in 2015. In Panama, we hit a $0.06 shortfall in 2014, most of which was during the first nine months as inflows improved in the fourth quarter. Inflows are now close to 100% of long-term average, and power prices are at about $100 a megawatt hour, down from well over $200 per megawatt hour for much of last year.

Our downside exposure continues to decrease for two main reasons: first, the government compensation agreement we negotiated last year to offset this exposure; and secondly, lower oil prices helped to reduce our earnings volatility. The spot prices during dry conditions are set by oil-fired generation. In 2014, we were purchasing in the spot market. If oil prices were at today's level last year, the hydro impact would have been about $0.03 rather than the $0.06 we actually experienced. I'll also note, as Andres mentioned, we brought an oil-fired barge to Panama, improving our bottom line.

Finally, in Brazil we had a $0.07 impact from poor hydrology in 2014. Tiete experienced a 10% reduction in generation, or GSF. The impact was magnified by the fact that the average spot price was just under BRL700 per megawatt-hour in 2014, significantly greater than the BRL200 level of our off-take contract. Currently reservoir levels are about 23%. While we've seen some recent improvement, it's difficult to predict how much they'll recover by the end of the rainy season in April. For now, we're factoring in about a $0.05 impact into our 2015 guidance due to an estimated 15% to 17% reduction in generation for the year.

The impact of a shortfall will be less than last year. Spot prices are now capped at BRL388 per megawatt hour compared to the cap of last year which was BRL823. We're not incorporating rationing in to our 2015 guidance at this time. We'll provide an update on our next earnings call in May when we'll have more clarity. Although it's very premature, we estimate a rationing scenario could result in an additional $0.05 impact above the $0.05 we already have incorporated into our guidance.

Now to cash flow beginning on slide 18, we generated $287 million of proportional free cash flow in the fourth quarter, bringing the full-year amount to $891 million versus $1.27 billion in 2013. Although near the bottom end of our revised guidance, it's roughly $250 million less than our original guidance. We're obviously disappointed with this result. This decline was driven by three unanticipated factors: first, an increase of a little more than $100 million in receivables at our Maritza plant in Bulgaria; second, higher receivables at Sul, our utility in Brazil, due to higher energy purchases; and finally a lag in VAT, or value added taxes, related to our construction projects in Chile. We expect improvement in these factors this year.

Now to slide 19 and our capital allocation in 2014. Starting on the left, we generated roughly $1.9 billion of discretionary cash including $1.2 billion from announced asset sales. We're pleased that, despite our shortfall in proportional free cash flow, we generated $523 million in parent free cash flow -- above the $500 million midpoint of our expectation. Turning to the right-hand side of the slide, we allocated 76% of this cash to parent debt and returning cash to shareholders through buybacks and dividends. Meeting our current parent cash flow expectation is especially important. It is the foundation of our dividend and dividend growth. As we've demonstrated through the recent doubling our of dividend, we continue to be comfortable that we'll generate about $525 million in parent free cash flow in 2015 and growth of 10% to 15% annually.

Turning to slide 20 in our capital allocation plan for 2015, with $460 million in announced asset sale proceeds, our total discretionary cash is expected to be about $1.5 billion in 2015. We'll invest about $300 million to fund equity commitments and projects currently under construction, the largest of which is at Ipalco, where we have a $1.4 billion investment program underway to increase the rate base by 70% from 2013 to 2017. After taking into account our growth investments, as well as expected debt prepayments of $200 million, we're projecting about $600 million of remaining cash available for allocation. We currently have a $400 million authorization for share repurchases, of which we expect to utilize the majority during 2015.

Before turning to our guidance, I'd like to take a moment to address our foreign currency and commodity exposures and our hedging practices on slide 21. We have long-term protections built into our business model to manage our exposure to FX and commodity price changes. For example, 82% of our businesses are either utilities or generation businesses, with an average contract term of seven years. This insulates the majority of our earnings from commodity price volatility. Having said that, some of our businesses do have commodity exposure, as they operate in markets where power prices are oil- or natural gas-driven. As shown in our appendix, every 10% move in oil is roughly a $0.025 EPS impact on an open basis, primarily from the Dominican Republic and to a lesser extent, Panama, where we have a modest amount of excess power to sell into the spot market.

On the plus side, in Panama, as I just mentioned, lower oil prices reduce our exposure to poor hydrology. In terms of gas, our largest exposure is at our DPL merchant business, where a 3,000-megawatt coal fired fleet is negatively impacted by declining gas prices. However, although gas has fallen by 20%, dark spreads have held up at around the $12 range. The impact on our EPS has been less than our disclosed sensitivities, which assumed a constant market heat rate.

Regarding currencies, as you can see on the right-hand side, we're largely protected from foreign currency changes, given that more than two-thirds of our PTC is effectively US-dollar denominated. The remaining third is exposed to a handful of foreign currencies, mainly the Brazilian real, the euro, and the Colombian peso. In the exposed portion, we mitigate the risk on a 12-month rolling basis, through shorter-term FX hedging programs or currency linked escalation clauses in our shorter-term contracts.

Now I'll walk through our 2015 adjusted EPS guidance on slide 22. The updated forward curve on commodities and currencies used in the sensitivities we provided in our last earnings deck would suggest a $0.10 negative impact to 2015. However, as a result of additional FX hedges, fuel and power contracts, we have been able to trim the overall impact from currencies and commodities on our 2015 EPS by $0.04. We're also incorporating a $0.05 impact from Brazil hydrology, as I discussed earlier.

Finally, we've also factored in a modest dilution of $0.03 from other factors including PPA negotiations at Maritza. We're offsetting these impacts through the following actions: $0.04 from cost saving initiatives across our portfolio; and revenue improvements, including a modest uplift from Mong Duong, where a new accounting standard better aligns earnings with cash on an ongoing basis; $0.02 from accelerated capital allocation; and $0.03 from various tax opportunities. Net-net, we've offset $0.13 of the $0.18 of headwinds, and therefore revised our guidance downward by $0.05, to a range of $1.25 to $1.35 per share.

Turning to our longer-term adjusted EPS expectations on slide 23, we continue to expect modest to flat growth in 2016 and 6% to 8% growth in 2017 and 2018, more weighted toward 2018, consistent with our prior expectation, but off a lower 2015 base. Our projects under construction will drive our earnings growth, while many of the other actions we're implementing in 2015 will continue to benefit us in 2016 and beyond, largely offsetting what appears at this time to be a negative impact from currency and commodity forward curves, as well as the impact of potential modifications of the Maritza PPA.

Shifting to cash flow guidance on slide 24, we are reaffirming our 2015 proportional free cash flow guidance of $1 billion to $1.35 billion. This implies an increase of roughly $275 million over 2014, which is driven by recovery of working capital and receivables along with cash flow from new businesses including Mong Duong which comes online this year. In Brazil, we're encouraged that recent moves by the regulator will accelerate the collection of purchased power costs by the distribution companies.

On slide 25, we continue to expect 10% to 15% average annual growth in proportional free cash flow driven by contributions from projects currently under construction, as well as the fact that maintenance CapEx is less than depreciation from new projects. In 2014 and 2015, depreciation averages about $315 million greater than maintenance and environmental CapEx. We expect this differential to widen to $600 million by 2017, which explains much of why our cash flow is growing at a greater rate than earnings. We believe cash flow is a key value driver, with strong double-digit growth in both proportional and parent free cash flow over the longer-term. We'll continue to show the value of our cash flow through disciplined capital allocation that maximizes risk-adjusted returns to our shareholders.

Now, I'll turn it back to Andres.

Thanks, Tom.

To summarize, we made significant progress on our strategy in 2014, and are encouraged with the resilience of our platform and the opportunities it provides to increase shareholder value. For 2015, our priorities are: pulling all levers to mitigate the effects of poor hydrology in Brazil, and lower FX and commodity prices; completing the 1,240-megawatt Mong Duong project in Vietnam, which will be a major contributor to our growth; resolving Maritza's outstanding receivables and renegotiating our PPA; executing on platform expansion opportunities, and bringing in financial partners at the project level; and allocating our discretionary capital to maximize returns, including providing for growth in our dividend, and returning cash to shareholders through share repurchases.

We believe that AES is uniquely positioned to offer our shareholders a strong and growing cash flow and dividends. I would like to open up the call for questions.

(Operator instructions)

Ali Agha, SunTrust.

Thank you. Good morning.

Good morning, Ali.

Good morning, Andres. A couple of questions, one, I noticed when you updated your 2015 guidance, you used the commodity and currency curves as of December 31, 2014. As you know, since then particularly on the currency side we've seen further depreciation out there. I'm just wondering factoring all of that in, as we stand here today, does that cause you to relook at the range of earnings that you put out maybe toward the lower end, or have been other offsets that you're still comfortable, the mid-part of this range given the currency movements of the year?

Ali, we're comfortable with the range we're providing.

Are there any other additional offsets that you've made since December 31 [event]?

Again, I think we have a number of initiatives that we're undertaking. Again, in the net-net, we're comfortable with the range we're providing.

Ali, I'd just say that as we look at it, currency's maybe off a penny. Maybe the real is a bit off, but there's some other moving pieces. Maybe commodities will help us a little bit. Net-net, we're in about the same place.

We thought the end of the year was a good baseline. That's what we used for our budget. We thought that was a good place to stick with. We obviously provide you sensitivities.

Right. Second question, with regards to the longer-term earnings outlook, 2016 and beyond, if I've heard you right, I think you've said, we're not going to start off from the lower base and build off from there. I would have thought some of the 2015 hits are not permanent, and currency and commodities can move at other places. Why is that a permanent roll-over effect in the future years that causes everything to move down given the 2015 move down?

Ali, I completely agree that currencies and commodities can move. Hydrology we expect to be one-time hits, but currency and commodity, we're putting in the forward curves that we have to date. We don't have any better information. I agree. They improve, then we'd improve as well. The way the modeling works is you have to take the forward curves and the best estimate of tomorrow's price, today's prices, so we've moved them down accordingly. I agree with you. One thing we're sure of is that they're going to move in the future.

Then Andres, finally, as far as CIC's ownership is concerned, obviously there's representative on your Board resigned last month. They haven't announced a replacement. What's your latest understanding of what their plan is for their ownership in AES shares currently?

Sure. Of course we can't speak for CIC, but what I can say is first the decision of Mr. Zhang to retire is because he hit the age limit of 70. In China, they're very strict about the age limit restrictions in government. That's the first part. The second, as you know, there are things happening in China. They have the right to assign a new director, and they will do so, but as you know because of certain campaigns that are in China today, things have slowed down in terms of rapid decision-making.

Okay. No indication from them on what their plans are for their ownership?

That's correct.

Thank you.

Stephen Byrd, Morgan Stanley.

Good morning.

Good morning, Steve.

We saw an interesting development yesterday in Ohio. I know it's very recent, but it did look, I guess to us at least, somewhat promising in terms of receptivity to PPAs in the state. I'm just curious. I know it's very recent and involves another company, but any immediate reaction to that? Any thoughts as to how that might impact you, or just more broadly on what you saw yesterday?

Yes, Stephen, it's Tom. I'll just hit that briefly. We have been following that. We did notice that it seemed like PCO was receptive of the concept of PPAs, but didn't believe that specific example warranted a PPA or the merits were not sufficiently demonstrated. We continue to monitor the situation.

Stepping back on a bigger picture, we do think capacity will be worth more, and that probably was a significant input to us deciding last summer to retain the generation. We are seeing a lot of that, to be honest, through the PGM premium capacity product that looks like it's on track, so we expect to get more value for our capacity in that fashion.

The last thing I'd say, it's a little harder for us. All of our plants are positive on to-go cost. We don't have any plants that are cash flow negative as we see it. It's a little harder for us to make the case than perhaps some other plants in Ohio, the majority of our plants, we do have a small interest in the OVEC plant that might be in a different situation, but the majority of our plants are cash flow positive.

Okay. Understood. That's very helpful. I wanted to switch over, Andres, to Main Street Power. As you think about solar for commercial industrial customers, I'm just curious how we should think about this in terms of the types of countries that would be most interesting. You talked about the criteria briefly. Is this something you would envision will start relatively small for some period of time? Do you see the potential as so positive that within meaningful, relatively short amount of time it could become sizable? How should we think about this in terms of where this goes in terms of scale?

Great question. We're starting off very modestly. I think as you know, we sold most of our position in utility scale solar in our JV with Riverstone. We've kept some assets. We continue to believe we should have the capability of introducing solar on to our platforms where it makes economic sense. Right now, we're building 20 megawatts of solar in Chile.

One market that's particularly interesting is Chile where you have some of the best solar e-radiation in the world, and you have very low rainfall in the North. It's an optimal place for solar, and also energy prices, because they have limited hydro are quite high. That combination of factors makes it an attractive market. We have other markets such as the Dominican Republic, El Salvador, where high solar e-radiation. You have high energy prices. We feel that this could be a nice addition to our portfolio to address the needs of large customers especially commercial and industrial.

We also think distributed solar is something which is affecting the industry, and we want to have our most current information understand what's happening, understand developments to be able to react faster. We think that we have a unique footprint in terms of places where you have the right combinations of natural factors and of market factors and with this know-how we're optimistic we'll make a good business. Given AES' size and given that we have a modest investment, at this point, it will take some time to grow out.

Lastly, as you know we're the world leaders in the use of lithium ion batteries. We recently won in the Southern California Edison bid, we got 100 megawatts of more additional capacity and we're using it really almost like a peaking plant, I would say. Having distributed solar and having the batteries together puts us in a very good position to react to changes in the marketplace with the growth of renewables. Again, it's part of our having a complete product offering, but again, we're starting off modest and like in batteries, we intend to make money from it.

That's really helpful. If I could, one last very brief question on Uruguaiana. You talked, Andres, about the potential restart and the key challenge in terms of getting fuel. What are potential approaches you could take there? What should we think about the challenges of actually achieving a restart there?

Last year, it ran for a couple months, and it's going to be running this year as well for a couple months, under emergency situations. Of course, it would be more efficient for us to receive capacity payments and be able to run it more. We have, of course, a gas pipeline. It comes through Argentina. The issue really has been to deliver LNG into Argentina and get a equivalent amount of gas in Brazil at Uruguaiana. It really depends on what's the delivered price to the plant.

We've been having relatively high prices of delivered gas to Uruguaiana. We're working on mechanisms using the existing infrastructure to get lower price gas. But what is also very important is that we have been promoting discussions between the governments. We had an interconnection line from Argentina to Chile, from TermoAndes into Chile. Given the situation of increased capacity in Northern Chile, we have reversed that transmission line so that we can now export energy from Chile into Argentina.

There exists the possibility, and that we're exploring, where we would actually pass energy from Chile to Argentina and from Argentina into Brazil, and it would be a win-win for all. We have had considerable government receptivity. It's just that we've gotten the permission for the first step. We'd be looking to the second step.

I think what's important broadly is that we're looking at ways to decrease our hydro exposure. Even if rains come back to normal, we don't want to be as susceptible to a drought. Admittedly, this is the worst drought in 100 years, but nonetheless we want to decrease our portfolio sensitivity to it, so we're looking at these ideas.

Great. Thank you so much.

Julien Dumoulin-Smith, UBS.

Hi, can you hear me?

Yes, we can.

Good morning. I wanted to elaborate a little bit on the cost savings. Can you talk about where exactly you're getting them from, and the sustainability as you look forward on the guidance you guys just released? Perhaps the second factor, do you think on year-on-year, looking towards the hydrology, what kind of assumptions on normalization are you assuming 2015 versus 2016, or is that all largely caught up already within the $0.10 range you have?

Let me take the first one, and Tom will take the second one. The first one regarding the O&M savings that I mentioned, first, the G&A savings, the $200 million, that's sustainable. That's a structural change in how we operate and better use of systems, I think, a better organizational structure. That's, let's say, in the bag.

Regarding the additional $100 million of O&M savings through 2018, basically as you know we had 7,000 additional megawatts which will come online between now and 2018. Really, our challenge is to keep O&M constant, flat, and reducing it on a megawatt-hour basis, is what we're going to be doing, and also keeping our cost flat relative to local inflations. These are our two main mechanisms that we're doing. Of course we have opportunities for additional standardization, for additional aggregation of purchases. We now have the systems to do that. Those are additional things that we'll be looking at.

Julien, the hydrology for next year we're assuming it will be normal, just like we are for Panama this year. Keep in mind that our contract at Tiete, about BRL200 per megawatt-hour, ends this year. We're about 83%, 85% hedged for next year. If there was a GSF reduction like we're predicting this year, let's say 15%, we would lose some sales. We would not be short.

We'll be in a much better position going forward, and that's how we would expect to run our business at Tiete, as well as everywhere else. All our businesses that have portfolios in a market, we'd look to sell some of the power but have some excess that would protect us against reductions in production, and hopefully to capitalize on some opportunities where we've got a little bit of length if prices are high.

Got you. Then moving to Vietnam real quickly, can you elaborate briefly here on your expectations for not just this year but in subsequent years around earnings trends? You chalked it up in terms of 2015 guidance, but in terms of once in service, what does it mean to your latest update on guidance? I know you talked about lower ROE versus cash flow in that project throughout.

Yes, so the ROE as I said, the ROE will now look closer to the cash yields. The cash yield is in the high teens, and the ROE will be in the mid-teens, maybe 14%, 15%.

Julien, we expect this to be fully online. Both units will be online by the second half of the year. Starting 2016, we have a full year of Mong Duong. Again, cash is still front loaded because it's a BOT. It comes under lease accounting or a version of it, and we have to normalize it over the life of the project.

Those are, Julien, benefits, the ROE are sustainable for many years, 10 years plus.

Right. Let me just be clear about combining these factors, you're going to have a better ROE on Vietnam, and so that's another year-over-year benefit in 2016? The 2015 versus 2016 jump is better than you previously disclosed. In addition to that, in theory, there's the normalization factor that's taking effect, 2015 versus 2016 that should be benefiting as well? I just want to make sure I'm capturing some of the changes here as you think forward-looking.

The short answer is yes.

Got it. Excellent. Then lastly just on Bulgaria if you don't mind my asking, I appreciate that you've taken an impact here. When you're thinking about the overall value proposition and the NPV, how are you thinking about that in the context of the conversation? I know that might be sensitive, but I just wanted to get that out there if I could.

Of course, we're in the midst of conversations with the government. For us the real key point is, one, a prompt payment of the 100% of the outstanding receivables, and the second is really solving the source of the problem which is the financial situation of NEK, the off-take. By really increasing the revenues to NEK, especially in the past, you had CO2 taxes which went to the government. The government allocated a portion of that to NEK. Now they'll go directly to NEK.

Second, rationalizing the energy that NEK buys because we are among the thermal plants, one of the few EU16 compliant plants. They really enforce their rules. This will make our plant much more important. I think the exchange, of course would be, that they want a decrease in our energy prices today, and for a number of years. In exchange, we have to look at the overall health of the business. We'll be looking at those factors, taking them in to consideration.

I think the most important is we should end up with a project that we don't have to be talking about receivables next year at this time. That's really our primary interest in this. The government, quite frankly, doesn't want to be talking about this either. I think with the cancellation of the South Stream project of gas from Russia, this plant becomes absolutely vital for Bulgaria, so I feel very confident that we will come to a resolution.

Great. Excellent. Thank you for the time.

Thanks, Julien.

Maura Shaughnessy, MFS.

Hi, Maura.

Hi. Can you hear me?

Yes, very well.

I just had two questions dealing mainly around Brazil. What was the GSF for Tiete in 2014, and what is the assumptions in 2015?

Maura, it's Tom. GSF was down 10% in 2014. That was basically what cost us the $0.07. Our assumption for 2015 is 15% to 17%. Keep in mind, obviously the prices are a lot lower. We are filling our short in 2014 at basically BRL700 per megawatt-hour. Now the cap is BRL388, so it's a larger shortage, but it's cheaper to fill it on a megawatt-hour basis.

The assumption that the GSF could fall into, I guess, you're talking about it down from BRL100. I think about it the other way, so in the BRL70 under a rationing scenario? What's the -- ?

I guess our assumption in terms of percentage of a short energy, flipping it around, we were 90% of assured last year, and we're assuming we'll be 83% to 85% of our assured this year. The nickel that's baked into our guidance assumes there will not be rationing. Obviously, we're watching the rainfall. We'll know more. I think the last week or so has been good, but if there were to be rationing, those different scenarios, we've looked at them. Our sense is if there were to be rationing, it would be an additional nickel. It would be $0.10 instead of $0.05, but it's still far too early to call rationing.

In the short energy level of BRL75 to BRL80 is a short guesstimate on rationing?

There's assured, but then there also goes in to some volume reductions. We start to lose a little bit at Eletropaulo Sul. It's at Tiete. The rationing would be baked in. We'd have some Sul and Eletropaulo sales reductions, as well as Tiete. That's a Brazil number, not just a Tiete number.

The $0.08 expected hit for Tiete in 2016, I think you have something like 17% of that contract still open, what's the assumption in terms of the pricing to get to that $0.08? What are you doing with that open position? What's the strategy there?

I'm sorry. There is reduction, let's say, from normal 2015 to a normal 2016. I want to make sure I separate hydrology from prices. There is a reduction of about $0.06, $0.07, just on a normal hydro year from 2015 to 2016 because this year we're selling at BRL200 per megawatt-hour. Next year it's about BRL135. It's about BRL135. (inaudible) be doing a rolling forward hedge program now for about 13 months, and I believe, about BRL135 is our average price, and we're 83% sold for Tiete next year.

That number goes up a little bit the next three years. The reais per megawatt-hour goes up a little bit, and the hedging level, just like any rolling hedge program, goes down about 20% a year.

By 2018, it's 46% hedged. The average price is BRL141 per megawatt-hour.

Obviously, [that's what it is, but] when you're selling for power today, what would the prices be at today?

We're seeing very high numbers. If you just did a single [16], we're seeing them in the BRL200s.

Right.

We've generally been selling -- sorry, go ahead.

(inaudible) the Eletropaulo contract, (inaudible). I'm just trying to understand what (inaudible) initial power [goal] was very low prices, but now you had last year the opportunity to reset that clock, but the price (inaudible) that much in your expected loss in 2016 versus 2015. I was just wondering is the assumption to be selling power (inaudible) or no?

Maura, that's fair. We've been doing a rolling hedge program, that as I said, started about two years ago. A year ago at this time, we said that we had a fair number of sales for 2016, and they were about BRL115. As we increased our sales, as we filled up the bucket for 2016 over the last 12 months, we've been doing it at BRL160, BRL180. That's why our weighted average is BRK135 for 2016 which basically reflects sales we've been doing for the last couple years.

It is fair that as we've been doing the sales, Andres mentioned we're about 46% sold for 2018, we have often sold them in three-year strips because there's a little bit of backwardation between 2016 and 2019. We've been selling them in three-year strips to take advantage of the 2016 higher prices and basically stretch it out for a couple years.

If I were stepping back and looking at [the caps in] Brazil, you've had a positive in terms of (inaudible) Eletropaulo this quarter, and all the other things, we're supposed to have a special [tariff] increase in March. (inaudible) for the distribution companies, never mind (inaudible) seeing some rational trends (inaudible). Having said that (inaudible) the strategy from the government just seems to be pray for rain. (inaudible) going to wait until April, and that will make a determination? It seems easy for them not to have been doing stuff obviously a year ago, never mind this year. Andres, what do you think, how this is all going to shake out?

I remember last year when we talked about this, we said that we thought rationing was very unlikely given the election. They would do everything possible to avoid rationing. I think that you'll have the extraordinary tariff increase. We expect that in March. I do think that will go through, which will help us pass through near-term cost. I think that the last couple weeks have been good.

One of the big problems has been that the rainfall has been falling in the wrong places. It's been falling further south and the big hydros are in the southeast, so the average rainfall numbers don't give you the real picture. It's the fact they haven't been falling in Sao Paulo (inaudible) the rain. My feeling is they're showing that they're taking active steps to protect the liquidity of the distribution companies. I think they're also taking active steps to run as much thermal as possible.

It isn't just hope for the rains. I think they're taking a lot of steps. I still think it's more likely that we won't have rationing than we will have rationing, but it's a higher percentage than it was, say, last year. It might be 40%, 60% or something like this. We don't know the exact numbers. They are taking the right steps to ensure liquidity at the dis cos, and also to run the thermal, and they are in discussions with us. At Uruguaiana, we are running the plant, and they aren't really looking at the imports of energy. I don't know if that gives you our feeling of what will happen.

That's good. Let's hope it rains some more. Thanks.

Thank you very much.

Greg Gordon, Evercore ISI.

Thank you. Most of my questions have been asked. Great job, guys, navigating through a very tough environment. One question is, when I look at the shortfall in cash flow that you experienced this year below the bottom end of the range, how much of that is stuff that you actually expect to reverse out and come back in 2015 and 2016, and it's essentially baked in to your confidence in the future cash flow?

Greg, I'd say some of it is, especially the near term stuff will be the Chilean VAT. We've already started to see about half of that come back. The Brazilian situation as Andres mentioned, there have been through the [flag] mechanisms and there are some meaningful rate increases expected here, whereby the deferred power purchase expense will get passed through here in the next few months. We have good visibility, and we also have good reasonable contingency in our numbers.

Great. When I look at the spread between proportional free cash and parent free cash, $1 billion to $1.350 million going down to $475 million to $575 million, that's a ratio of 42.5% of the low end of 47.5% of the high end. Is it a good rule of thumb to assume that proportional free cash translates into parent free cash at 45% as we go through time? Does that rise or fall, or is there another way we should think about that?

I think that can rise and fall. I think we showed it last year, where one fell 25%, and the other one grew. I think it will depend on specific circumstances.

Okay, great. Should we concerned that there's a big range of potential outcomes there, or is it within a relatively narrow band?

The parent free cash flow, I think, we've shown over the years is very solid.

Okay, great. My final question is, can you just review what's going on with the Southland projects, and what is the actual timing of when capital investments start to translate into net income?

They would come online in 2020 is what we're looking at.

Would you generate [AFEDC] on those investments in the construction phase or no?

No. No.

Okay. Thank you very much.

Sean, can we take one last question, please?

Insoo Kim, RBC Capital Markets.

Just a couple questions, regarding the Maritza negotiation, in your guidance what percentage decrease in contract prices are you assuming, and I guess, the breakdown of that $0.03, what EPS impact are you assuming?

First, we can't give any details because we're in the midst of negotiations right now. I can't give you any more color on that. It's in that bundle that we put up there, $0.03, and we think that's more than adequate to cover anything that could result from the negotiations.

Okay. Regarding the tax rate for the year, I know it assumes the expansion of the [CFC] [approval]. Do you have any updates or timing on when that decision would come out?

We got it last year. Congress has had a tendency to do it last minute, 12:00 on the 31 of December. We really don't. There is a talk of starting to make some changes in our tax code but there remains significant support for this. We expect it to be passed.

We're also taking steps to minimize the impact, should it not pass as we have in the past. We're now talking about a range of maybe $0.05 or something like that should it not pass, but just a reminder, we do have $3 billion of NOLs. We are generating more, so it will always be non-cash for the foreseeable future.

Okay, great. Thank you very much.

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

This concludes today's conference call. You may now disconnect.