Steven D. Davis
Good morning, and welcome to Sempra Energy's 2012 Analyst Conference. I'm Steve Davis, Vice President of Investor Relations and Corporate Communications. I'd like to thank those in attendance with us here in San Diego, as well as those of you who are joining us by webcast. We want this to be an interactive conference, so our webcast audience will also have the ability to ask questions via the link located at the bottom of the webcast screen.
Before getting started, I'd like to remind everybody that presentations we'll be discussing today contain forward-looking statements within the meaning of the Private Securities Reform Act of 1995. Actual results may differ materially from those discussed today. The factors that could cause our actual results to differ materially are described on this slide and are further discussed in the company's reports filed with the Securities and Exchange Commission. I'd also like to note that the forward-looking statement contained in these presentations speak only as of today, March 29, 2012, and the company doesn't assume any obligation to update any forward-looking statement in the future. In addition, some of the financial information we'll be discussing contains non-GAAP financial measures. In accordance with Regulation G, you'll note that we reconcile these financial measures to the most directly comparable GAAP figures and you'll find that information in the appendices of the financial and U.S. Gas and Power presentation. We've got a lot of information to cover today, so let me begin by introducing Sempra Energy's Executive Chairman, Don Felsinger.
Donald E. Felsinger
Let me also add my welcome to those on the webcast. And for those of you here in the audience, thanks for making the trip to San Diego. Your time is valuable and we appreciate the effort that each of you have made to be with us today. Those of you that attended last year's conference may recall that I told you that our board was engaged in a succession process in light of several planned executive departures. And that was Neal Smalley, who was our President and COO, was leaving at the end of last year, and Darcel Hulse, who was the CEO of our LNG business is retiring next month, and then my retirement coming up the end of this year. And today, I'm pleased to be able to report to you that we've completed a very seamless leadership succession process for all these positions. And to me, that just exemplifies the quality and the depth and the breath of Sempra's management pool. As a management, we take our responsibility of providing our employees an opportunity to learn, to grow, to be challenged, exposing them to different parts of the business. And we do this to ensure that we have a depth of leadership succession for management. And the Board of Directors has a similar oversight. But with respect to the CEO position, and they want to, see that have management talent that's developed, that they want to be able to assess the progress of that management development and look at what there is available for CEO succession that's within the organization. And Sempra's board, unlike any other board that I've been exposed to, takes this process very, very seriously. And I can speak firsthand about this, because I went through a very rigorous process in 2005 when I became the CEO.
Starting about 2 years ago, our board decided to initiate a very structured process to review the list of internal CEO candidates. And the first thing we did was we quickly determined that given the depth and breadth of the management team within Sempra, that my replacement would come from within. Next, our board then took several steps to better familiarize themself with all the candidates, and this process included a lot of board interaction with each of the candidates. We had each of the candidates confidentially reviewed by their peers, their co-workers, subordinates. The board engaged an external consultant that specializes in CEO succession. And finally, we had each of the candidates go through a very structured process with the board where they made presentations and then engaged in Q&A. I have to tell you that having gone through this process in 2005 as a candidate, and then having led our board through this, this past year, it was a lot more fun being on the other side of the table directing the process and being a participant. Or as many of you know, this process culminated in June of last year in the selection of Debbie Reed to succeed me. And we had a discussion at the time about the process of succession, and we decided that it would be healthier for the organization and for the outside people that we do business with to have this become a blip in the transition versus a drama that played on for months, and we decided to make Debbie the CEO immediately and have her pick her team immediately and get on with business and get this behind us, which we did.
Some of you know something about Debbie and her previous Sempra roles, and a lot of you have learned more about her since she has become CEO. Let me share you with you who I know her to be. After graduating summa cum laude from the University of Southern California, Debbie started working for SoCalGas as an engineer. She had a long and successful career at our utilities, culminating in becoming the CEO at SoCalGas and SDG&E. Debbie also gained valuable experience on what it is to be responsible for shareholders in her service on outside boards. She currently serves on the board of Halliburton, and she previously serves on the boards of Genentech, Dominguez Services and Avery Dennison. And locally, she chairs a Board of Directors of the Regional Economic Development Corporation. I had the chance to meet Debbie for the first time in 1996 when we were forming Sempra, and I followed her career for the past 15 years. A few years ago, when Debbie was the CEO of SDG&E and SoCalGas, I offered her the opportunity to come to work for me in a corporate position. And the reason for that is because of the strong affiliate rules in California. Debbie had never had the chance to be exposed to the businesses that are outside our regulated California utilities. Debbie took on that assignment, and for the last 2 years, had been a study on the other side of the Sempra fence with the unregulated affiliates. Debbie not only took on this role with enthusiasm for both learning about these other businesses but she was a very quick study. She was thoughtful, she was inquisitive, and I can see that today in the way that she performs as CEO. She's also a team player, as evidenced by our more recent leadership announcements, where she's put strong capable people like Mark Snell and Joe Householder around her. I'm going to leave Sempra later this year as probably one of its largest individual shareholders. And I do so knowing the company is in great hands with Debbie and the rest of the management team, and that my investment's going to be well taken care of. On a personal note, let me thank all of you for your continued interest and support of Sempra. I have enjoyed and benefited from the interaction we've had over the years. And Debbie, why don't you now come up and take these people through our strategies and priorities for the next 5 years.
Debra L. Reed
Thank you, Don. And I would be remiss if I didn't comment on what Don has brought to our company. Don talked about when we first met during the time that we were forming Sempra. And it was his vision and his view of Sempra being more than just 2 utilities that really got us to where we are today. He was very focused on growing our business and doing that in a way that we managed risk effectively. And I think if you look at our history of TSR performance, he can take great pride in the leadership that he provided to all of us in his tenure as CEO, and before that, of leading our global businesses. On a personal note, and sometimes people say it's very difficult to have the person who was your predecessor stay on, I would say that in Don's case, he has been an incredible mentor to me, and I greatly appreciate that. And we all are going to wish him well later this year in his retirement where he can go and enjoy himself. So thank you very much, Don.
Now I'd like to begin our presentations for today and start with an overview of the areas that we're going to be covering. And I'll start with a high level presentation on our strategies and our key focus areas and priorities. And then, we will have the California utilities come up and do a Q&A session. After that, the international utilities come up with Mark Snell talking about LNG, about our energy infrastructure business and the opportunities for MLPs and do a Q&A. And U.S. gas and power led by Jeff Martin doing that. On the whole opportunities with our North American renewable business and our Gas business. And then George and Eduardo are going to do a deep dive into our international businesses. You've had a lot of questions about that, and we want you to understand how regulation works in Chile and Peru and how good these businesses are and how they set in the portfolio. And then finally, Joe is going to come up to do a financial recap, and then Mark and I are going to join Joe at the end to answer all of your questions remaining for the day. So you'll have plenty of opportunities through the course of the day to ask your questions and get them answered. You will also have a great opportunity to meet our senior leadership team. And I encourage you to do that, because I think this is a fantastic team that has great diversity of background and experience that comes together in a synergistic manner for us to make really good business decisions. You have people like Mark Snell, who's been very much involved in project development, has worked largely on the unregulated side, have strong financial background, coupled with people like myself and Jessie, who have a lot more experience on the regulated side of the business. And we have a really, really solid team. I am so pleased with having now Mark Snell as my President and overseeing our unregulated businesses, and then Joe Householder, who moves up from our SVP and Controller as CFO. We just have a real solid team. So please take some time to meet everyone today, get to know them. They're the same faces in a lot of new jobs, including Jeff Martin. He's has taken on a bigger role. And in spite of his activities with the President, he's taken on a bigger role and now is responsible for all of Sempra's North American operations.
I'd like to start with our 2011 accomplishments because, quite frankly, these lay the foundation for our future, and we just had a very, very strong year in 2011. As Don mentioned, often times when you go through a transition, things are up in the air and performance drops. That was not at all the case in Sempra. We had 14% increase year-over-year in adjusted earnings per share. And that came from not just one of our businesses hitting a home run, but from all of our businesses performing well and exceeding their goals. The other thing that we accomplished in 2011 is our earnings now have grown to the point that we have replaced the earnings that we lost during the sale of our Commodities business. And we replaced those earnings with very stable types of predictable earnings in areas like renewables, our utility growth both in the U.S. and internationally and then our LNG business, and then we'll be talking about all of those in more detail today.
Another key accomplishment in 2011 was to move forward and get construction on Sunrise so far and so effectively. We are on track to deliver this nearly $2 billion project on time and on budget. It's probably the most difficult state to build infrastructure because of all of the environmental concerns and regulation. I was out visiting the Sunrise Powerlink construction with Mike Niggli the other day, and it is really an engineering feat and a construction feat because most of the towers have had to be set by helicopter. We have 150 environmental engineers every day watching our performance on this. And in spite of all of these challenges, this project is coming in on time and on budget, which shows we can build major infrastructure projects in Sempra. We also closed the transaction for the 2 South American utilities to take controlling interest in the utility in Peru and the utility in Chile. And these have been integrated during the course of the year very, very well into our business. As you might recall when we made this announcement last year, we were looking at $0.15 accretion in 2011 and $0.22 accretion in 2012. And we do expect to see that. We've also, in the renewable space, Jeff Martin stood up here last year and told you he had this really big goal of 1,000 megawatts in renewables to be in service by 2015. And Jeff Martin's going to stand up here today and tell you that he has substantially increased that goal. The renewables business is a case of us being really a leader in solar technology in the West, and we think that, that is where the growth is going to occur in this space
And then finally, the dividend. When I meet with all of you, the one thing I usually hear is what are we going to do about the dividend? Can we build a stronger way to bring capital back to shareholders? And 2 years in a row, in 2011, we increased the dividend by 23%, and in 2012, we had another 25% increase in the dividend. And you'll hear more about the strength of that dividend based upon the strong cash flows from our businesses as we go through the day.
So let's move on to the next slide, which is focused on how we approached our strategic review of our business. And before I became CEO, we had already been in the process of kind of doing a strategic review of Sempra, largely because we had exited the trading business and we were looking at where we wanted to grow in the future, and we continued that process over the last few months. Some of the things that we did is to really look at all of our assets and to look at the markets where those assets sit and how markets may evolve over time. We did an assessment of every one of our assets and whether it would be better to maintain that asset or to look at exiting and selling the asset, and we looked at what kind of performance we could expect to get from all of our assets. And the key things that came out and trends that kind of drove our decision making are on this slide. And I'm not going to go through them in a lot of detail because you're certainly familiar with these trends, but one thing that's very clear is that there is going to have to be a lot of capital put into utilities across the U.S. over the next few years to provide the supportive infrastructure. And in our own 2 California utilities, we're looking at spending $11 billion out of over $14 billion of capital over the next 5 years in those 2 California utilities. And we expect to see some trends that we are seeing on the West Coast move to the East Coast. Certainly, pipeline safety and the focus on how do we run safe gas systems is something that we see here very much as the focus in California that we also see going through the rest of the U.S. The other thing is certainly coal-to-gas conversion, and you saw that EPA came out with some was yesterday for knowing who to call for electric generation. But we see that the coal-to-gas conversion is going to be driven not only by environmental reg, but by the next trend in that shale gas. Because shale gas has really changed, and we believe will continue to change the economies of gas for generation. We also believe it will change the economy for gas for other uses. You're hearing now companies looking at coming back into the United States to actually manufacture here or develop plastics or fertilizers. You also hear increased focus on liquefied natural gas or fuels -- for vehicle fuel. And so we see that this is something that's here to stay and it is also the thing that we think will make LNG export a reality. Now the other trend that we believe influences our business and is here to stay for some time is renewables. And we think that this is driven largely by the renewable portfolio standards that 36 out of the 50 states have adopted. And we also believe that Sempra is well positioned in this because if the PTC doesn't get renewed, as looks like may be the case now, then solar is going to be the future for the next several years. And you couldn't have a much better position than we have in terms of solar development. And we also have a terrific wind project that we'll be building in Mexico that is not reliant on the PTCs. In terms of emerging markets, this is the type of growth that we believe is a value in the Sempra portfolio that we get from our Chile, Peru and Mexican investment. In there, we're looking at 3% to 4% customer growth each year, and 5% to 6% load growth where, if you look at U.S. utilities, that's expected to be relatively flat. And then the final trend that influenced our thinking and certainly influenced our view on repatriation is what's going to happen in the way of tax. And our answer there is we really don't know what's going to happen in the world of tax. What we do know is that we want to try to use all of the tax credits and any net operating losses as quickly as we possibly can, and that is the reason we made the decision to repatriate dollars.
Next slide. So when we started on this process and we looked at these trends driving our business, we really had 3 strategic imperatives for Sempra, what we wanted to accomplish from this review. We wanted to look at how we could streamline our business and integrate aspects in a way that when they operated together, you could get more value. We wanted to focus then our capital allocation on where we thought the greatest growth greatest value creation would occur and then limit capital allocation in other areas, and then we wanted to really focus on some of the prior investments where we had already spent quite a bit of capital and we felt that we could get greater performance out of those assets. And that was a huge priority because there's not much you can do better than to create shareholder value than to get some value out of those assets that we'd already invested in. So out of this, we created the 3 growth platform that Sempra will be focused on in our future. Our U.S. utilities where we're expecting 5% to 6% growth between our 2 California utilities, and a lot of that now moves to SoCalGas about -- SoCalGas is looking at about 8% growth over the next 5 years. Our South American utilities and Mexican midstream where we are looking at 8% to 9% earnings CAGR over the 5-year period, and we have a great foundation there to support Mexico and its oil to natural gas conversion. Both have been one of the key energy partners in Mexico now, having been there 20 years, and then having a strong partnership with PEMEX to help make that happen. We also have very strong organic growth in these 2 utilities. And then finally, our U.S. gas midstream and renewables business. And this is where we can focus on our utility and municipal customers. Those are the customers for both our gas storage business and for our renewables business. And we understand what their needs are because we run large utilities ourselves. And so we believe that these businesses can grow, and they can grow on the foundation of an LNG export and the infrastructure that's going to be needed to support this changing gas environment. Also the coal to gas conversion, and we can help some of these companies as they make the coal to gas conversion, because with SoCalGas, we run a very large storage facility. We have experience serving electric customers and we run electric utilities that have to think about reliability and gas-based fuel. Our goal with all of this is to deliver superior shareholder return. And that comes from both very high growth compared to our peers, 6% to 8%, plus a strong dividend that's supported by predictable strong cash flows from our businesses. And we've aligned our organization based upon these 3 growth platforms so that we can look at the integration of assets of our international assets in Mexico, how those can be integrated in a way that we can get more value out of them. And then in our U.S. assets between our North American gas assets, our renewables business, how can we integrate to better serve the needs of the customers.
So, when we think about the future, and in 20 minutes being able to try to picture for you, draw a picture for you of where we believe Sempra is heading over the next 5 years. That's the best way to do that quickly is to tell you we believe where we are today, what our key goals and initiatives are and where we see our company in 2016. So let me start with that with the U.S. utility. I would say that our headline for our U.S. utilities is to stay the course. We have great organic growth in those utilities, and the 2 CEOs will be talking about why we believe we can pursue that growth without having tremendous impact on rates. Because our focus is really on looking at capital investments that benefit the customer, either in providing rate reductions to customers over time, or reducing future rate increases over time. They're also focused on doing the things the regulators have asked us to do, whether its pipeline safety and integrity, or it's really implementing the state, goals on clean energy and renewables. And we think by making these investments that we will be able to provide good value to our shareholders. Now we also believe that when we look at our scale, having built a major transmission line overhead, 500 kv; built a major transmission line underground, 230 kv; implemented full rollout of smart meters throughout our service territory with little of any reaction -- negative reaction from our customers, now doing that at SoCalGas, being a leader in pipeline safety, we believe that all of these skills that we have are very transferable to other utilities and in the U.S, and that we will be looking at ways that we can enlarge the Sempra footprint and create more value. I would say that we're particularly interested in utilities that are adjacent to our current service territories or adjacent to our midstream businesses, and that also have maybe 2 potential growth platforms: The utility business and the midstream business.
Now in terms of South American utilities and Mexican infrastructure, that what we want to do here is we want to build upon our strong franchises. That we have great growth opportunities right in the footprint that we're in today, and so we're very much focused on those footprints and adjacent to those current franchises. You'll hear about the Hydro opportunities that we're pursuing in Peru, and a transmission opportunities that we're pursuing in Chile. You'll also hear about the midstream growth opportunities that we have in Mexico, and as Mexico does make that conversion from oil to natural gas, how we feel that we're really well placed to play a large role in that. The thing that I would say is a change here in this area is that we want to have the right capital structure for these businesses in the long term, and we think that, that means that these businesses should have local debt and local equity. And we think that the model that we have in Peru, where about 20% of that company is owned by the public, largely pension fund, but that is a good model for these businesses going forward. And so that is what prompted us in one respect to look at how this could all integrate together to provide the right capital structure for these businesses over time, and bring those dollars back to help support our business growth in the U.S. and support our dividend.
It also gives you all an external benchmark, because I hear from many of you that you're not quite sure how to value these businesses. And George will be talking today about our Peruvian utility and how the market value is back. So it'll give you a sense of how that business is valued. The other thing, I would say, on these businesses is the question of how do they integrate in the Sempra portfolio. And I think that what we were just able to do was repatriation and looking at taking the proceeds from these businesses, the earnings on a current basis from these businesses and bringing those earnings back into the U.S. that we could utilize earlier than we otherwise would've, net operating losses, costs from bonus depreciation and the renewable tax credit. I think that shows how we can get some synergies between these businesses and the rest of the portfolio.
In terms of U.S. gas and midstream, in the long term, we believe that an MLP will be the best way to integrate and grow our midstream business. And we believe that the strong cash flows that we would anticipate from an LNG export business would be a great foundation to have a very robust MLP. For Sempra, one of the largest shareholder value creation opportunities we will be talking about today is really that LNG export opportunity. Because we've already made the investment there, and this is just upside for us in terms of future earnings potential. And when you look at that business, we're looking at growing a business that could be about the size of Southern California Gas Company today in terms of earning somewhere between $200 million to $300 million-plus in earnings depending on the size of the liquefaction facility. Next Slide.
In the renewable space, we have a strong solar position, as I've mentioned. What we're doing in the renewable space, though, is changing the financial structure of this business on to what we have been doing on wind. We've been in a 50-50 joint venture with BP on our wind project. We really like to project finance these projects. And what we want to do and are doing is to have a bigger pie of projects with more diverse technologies, more diverse customer base, more diverse off takers, more diverse regulatory environment, and to have 50% of this bigger pie. And as you'll see in the presentation that Jeff makes today that by doing that, we can grow this business by 2016 to about $100 million a year business that has 20 to 25-year contract. And we think that is the way we should approach it. On gas generation, I will say we are not going to be a merchant generator. We are definitely not going to be a merchant generator. And we're in the process now, because of a number of RFPs that are out, of looking at contracting those generation assets. And we feel that the value of those assets will increase if they're contracted should we decide to exit them, or would provide us greater value in our portfolio because we are not going to be taking market risk and generation. I would remind you, too, we only have 2 plants and we have already been exiting this business for a number of years. So what does this deliver in terms of the Sempra picture? It delivers 6% to 8% earnings growth with very tangible ways of achieving that earnings growth. It delivers capital allocation based upon where our growth priorities are, with $11 billion out of the $14 billion of capital we have in this plant going to the utilities, and most of the remainder going to do renewables business. And it delivers some reallocation of capital. One of the things that we're doing is that we are going to build out the gas storage that is currently under construction of about 20 Bcf, giving us 43 Bcf operational by -- into 2013, and then we're not going to put any more capital in that business until the LNG export market starts to come forward. Because we have the great advantages that doesn't take us too long to mine these caverns and get them online, and so we're going to cut back capital until we see that on the near term. We're also looking at a model that Mark will talk about for our LNG business where we would not be putting a lot of additional capital into that business, but using the investments that we've already made in our Cameron, and potentially ECO [ph] facilities. Over the 5 years, we grow at 6% to 8%, and this is the chart that we talked about on the call where there are a lot of questions about how that growth occurs over time. As you can see from this chart, it's not even from year-to-year, but from 2013 to 2016, it is pretty even year after year. And this chart reflects both the change in solar accounting, which was about $0.40 a share, and the change due to the repatriation that we're planning beginning in 2013, which is about $0.30 a share.
In summary, the key takeaways I'd like you to have from today is that we're really focused on where we're going to grow our business, and we're allocating our capital to where we're going to grow. We are also extremely focused on how do we get greater value out of the assets that we have already invested in because that is going to deliver the greatest long-term shareholder value. We've taken concrete steps to increase the transparency and certainty of our earnings. We made the change in solar accounting after hearing from many of you that you've thought that, that would make it easier for you to value those assets. We also are now re-segmenting our business, and Mark will talk about what information you will be receiving on segments. It'll give you much greater visibility including clarity as to what our international earnings are and what our domestic earnings are. We have a clear path to 6% to 8% growth, and we can show you where that comes from. And our business generates strong, predictable, reliable cash flows over time, and that allows us not only to be a high-growth business, but to be able to return capital to our shareholders. So with that introduction, I'm going to now ask Mike Allman to come up, and we will begin the session. And after Mike and Jessie have presented, there will be a Q&A. Mike Allman, is President and CEO of Southern California Gas Company, and he took that position in 2010, and has really been an advocate for safety at SoCalGas since he's been there, which is so important as we've seen in running a utility. He also previously served as President and CEO of our generation business unit and was responsible for helping us get our toe in the water on renewables. So with that, Mike Allman.
Michael W. Allman
Thank you very much, Debbie. Thank you for that introduction, and I'm pleased to be with you this morning to talk about the Southern California Gas Company. So this is what I'm going to cover today. A brief overview of our business, what we've been able to accomplish in 2011, then I'll provide an update on 3 of our most important regulatory proceedings. And those are our Pipeline Safety Enhancement Plan, our general rate case and the cost of capital proceeding. I'll provide an update of our 5-year capital plan, and as part of that, discuss the major projects that we'll be working on over this period. And finally, I'll bring it together and provide a financial outlook for the company, and then Jessie Knight and I will take questions and answers after Jessie's presentation.
So let me first just provide a brief reminder of the gas company. That's the nation's largest natural gas distribution utility covering about 20,000 square miles, serving over 21 million consumers to nearly 6 million meters. And we've been providing safe, reliable and low-cost service to our customers for over 143 years now. We have some substantial storage capacity, 134 billion cubic feet in our territory of working gas, which provides us system flexibility to meet our customer demands. And our existing infrastructure and access to large customer base positions us well as demand for natural gas will grow as prices remain historically low due to some of the shale gas that Debbie mentioned and the economy begins to improve.
As a reminder, in California, natural gas is the primary fuel source for heating our homes, serving more than 90% of the homes in Southern California, and that's our primary fuel for generating electricity with more than 50% of the total electric generation coming from natural gas. At the end of 2011, the gas company ended the year with a rate base of about $3 billion.
Now 2001 (sic) was a good year for the company on several fronts. First and foremost, as Debbie mentioned, it is about serving our customers safely and reliably. I'm proud to say that in 2011, we received the highest rating in the country for customer satisfaction among residential gas utilities according to a survey conducted by J.D. Power & Associates. That's #1 in the entire country. Our motto is glad to be of service, and this award, I think, really shows that we're doing that and more.
In addition to a high-level of customer service, we started to make our product as inexpensive for our customers as we can. And again, we're delivering. Our gas prices are among the lowest in the nation, about 23% less than our peer group and our average residential bills continue to be among the lowest in the state and about half of the national average.
Of course, a common objective that we share with our regulators is our continued focus on providing safe, and efficient service. And again, we had a fantastic year. We improved both system and safety for both the employees and our system, to record levels. We continue to move forward on our pipeline integrity program, both on the transmission and distribution side, to ensure that the pipeline safety is a top priority for our company. And for the second year in a row, we improved employee safety to record levels, a decline of more than 20% over the prior year.
And of course, from a financial perspective, we recorded $287 million of earnings in 2011, which is backed by strong cash flow. Our operational cash flow has averaged about $600 million per year over the last 3 years.
Let me talk a little bit about our -- one of our very important regulatory proceedings is the Pipeline Safety Enhancement program. We call that PSAP, Pipeline Safety Enhancement Plan. The California Public Utilities Commission ordered gas transmission operators to file plans to either pressure test or replace all of the gas transmission pipelines that have not met modern pressure standards. SoCalGas and SDG&E jointly filed a comprehensive Pipeline Safety Enhancement Program. We submitted that in August of last year. And out of the about 4,000 miles of total transmission lines in our system, about 1,600 of those miles are in populated areas and they're going to be addressed in the first phase of our plan, the remaining 2,400 miles will be addressed in later phases. In addition to the replacement or testing of our pipelines, our PSAP also includes adding more remote control valves to enhance our system.
We asked the California Public Utilities Commission for a memorandum account so that we can begin this important project, and on March 20, the AOJ in charge of this OIR issued a proposed decision that if approved by the commission, and we expect that to happen next month, would allow us to file an advise letter so we can get a memo account. What this memo account does, it would allow us to track our costs for this project and provide us a clear path to full cost recovery of all of our investments so that we can begin this important project right away. The final decision on the PSAP plan is expected to begin 2013, and is likely to be decided as part of our tri-annual cost allocation proceeding.
Now our second important regulatory proceeding is our general rate case. Last month, we filed an update to our application where we are requesting a total revenue increase to about $2.1 billion for 2012, about a 6% increase over our system average rates over 2011. We asked for a 4-year term, with revenues increasing in the interim years by various inflation indices, which we anticipate would increase revenues by about 3% a year in the interim, but they would be based on the actual, as realized, levels of inflation.
We expect opening briefs to begin in April, we file briefs in May and a final decision on our rate case sometime in the second half of 2012. Now it's important to recognize that the revenue requirement established in the rate case will be retroactive to January 1 of this year. So please note that until a final decision is reached, we're going to be recording revenues based on last year's authorized revenue levels. That means you should expect relatively lower earnings until our rate case is decided. We'll record the retroactive increase in authorized revenues all the way back to January 1 in the month that our rate case is finally decided. Again, we expect that to happen in the second half of this year.
The final regulatory proceeding I'd like to discuss this morning is our cost of capital case. Our current authorized rates of return have been in effect since January of 2003 and are currently the lowest in the State of California. Next month, we expect to file a cost of capital application that would set our authorized returns beginning on January 1 of next year, 2013. Now although the interest rate environment is currently lower than when our rates were last determined, it's important and we fully expect that our new authorized returns will reflect the increase of risk that we've seen in the Gas business that will consider the increased regulatory legislative focus, particularly on pipeline safety, and that importantly they'll be sufficient to continue with it to attract capital in support of our important investments. We expect the decision in the fourth quarter of this year and again, they would be effective January 1 of next year.
Let me shift now to our 5-year capital plan. We're projecting a total capital expenditure of about $5 billion over the 5-year plan, which is the largest capital spending program in the history of the gas company. A little more than half of this capital would be in our traditional business, areas such as system maintenance, new customer business, other what I might call, ordinary capital expenditures, roughly $2.6 billion in total. In addition to that, we have significant amounts of capital for new investments that total about $2.4 billion over the planned period, about $1.4 billion is associated with the new Pipeline Safety Enhancement Program or PSEP. We also have our advanced meter infrastructure, AMI, which will total about $700 million of capital. And then we have some capital to expand and enhance our storage field operations.
So let me give you a few numbers on our PSEP plan. This is for the SoCalGas business, and as I mentioned, our plan would be implemented in 2 phases. Phase 1 is a 10-year plan that will address pipelines in populated areas. Phase 2 will address the pipelines that are in non-populated areas. Phase 2 is going to be addressed later down the road through a separate CPUC proceeding.
So focusing on Phase 1. We broke that in 2 individual pieces, we're calling them Phase 1a and Phase 1b. Phase 1a covers the first 4 years of the 10-year program. That represents the highest priority pipelines and the new valve installations. In Phase 1a, we anticipate pressure testing or replacing about 650 miles of the transmission pipelines, which is really all of the pipelines that haven't been tested to modern-day standards. Phase 1b addresses replacement of pre-1946 pipes and a few of the projects in the populated areas that will take longer to complete. We are, at this time, only asking for cost recovery for Phase 1a, so for the first 4 years of our program. We propose that the remaining years of Phase 1 be approved in subsequent proceedings.
Our PSEP calls for our filing as for total cost of about $3.1 billion for the gas company over the 10-year period of Phase 1. About $1.7 billion for Phase 1a, which covers through the year 2016. This $1.7 billion is what we have in our 5-year plan and what we expect will ultimately be approved by the commission to ensure that we meet the goals of enhanced pipeline safety with minimal customer impact and maximum cost-effectiveness. So the state is shifting to the new standards for pipeline integrity, primarily to ensure that all transmission lines are hydrostatically-pressure tested. We support these changes and our proposed plan is what we think we need to do in order to implement these standards.
Another large component of our capital plan is our AMI project, where we will be upgrading approximately 6 million meters over the next 5 to 6 years. We're currently in the process of developing a software and installing the communications networks and we anticipate an initial deployment near the end of this year and mass deployment beginning in 2013.
Overall, we remain on track for this project., this important project will allow us to provide more timely and relevant information to our customers, as well as reduce costs for our customers. So the effect of this capital plan is to increase our rate base to over $5 billion by the end of the planned period in 2016, an increase of over $2 billion from where we ended in 2011. This represents a compound annual growth rate -- of rate base growth in the 12% to 15% range.
So here's our earnings profile. Forecasted ranges for 2012, we're forecasting $265 million to $295 million of earnings; for 2013 between, $273 million of net earnings; and for 2016, in the range of $350 million to $390 million.
Now let me anticipate a couple of your questions. One is going to be, how do you reconcile these earnings ranges with rate base? Well, let me remind you that we make money not only through our authorized rates return and rate base, but also, for example, through AFUDC, which is the allowance for funds used during construction, which is the capital we have spent and that we earn on before it's actually placed into service in the rate base. Of course, we also earned through various incentive mechanisms that we have in place such as our gas cost incentive mechanism and our unbundled storage program, where we share in the benefits with rate payers if we outperform benchmarks and we earn by managing our cost in between rate cases to the benefit of our shareholders and to our customers. For the 5-year plan, we've assumed that all new projects, the PSEP, the AMI, they all earn authorized rates of return, so as such you can see that the fraction of our earnings from incentives, AFUDC and other efficiencies tends to shrink throughout the period.
Another reasonable question you might have would be, well, what's the impact of this investment going to be when it comes to customer rates? Here we have a very good news. Due primarily to the drop in natural gas prices, our typical customer bills are lower than they were just 4 years ago, down from about $50 a month to today closer to $40 per month. With some of the lowest gas commodity charges that we've had in recent years, this is a great time for us to invest in the infrastructure without significantly impacting our customers' bills. When we look forward towards the end of the plan in 2016, we can expect our typical customer bill to increase back to about $50 a month, including factoring in the forward price curve for natural gas and all of the enhancements that we've planned for safety and all the other capital in our plan. I think the fact that we can go from 2008 to 2016, an 8-year period, with no nominal increase in the typical bill for residential customers is really quite an amazing result.
So for outlook for 2012, '13 and '16, as you can see, we're forecasting earnings ranges of $265 million to $295 million, $270 million to $300 million for '13, and $350 million to $390 million for 2016. And you can see on this page our capital expenditure and investment forecast. Our CapEx is expected to grow from about $700 million a year in 2012 to about $1.1 billion per year over the planning period. The effect of this capital investment net of depreciation over the period is to grow our rate base from today, about $3 billion to approximately $5 billion by the end of 2016.
So in summary, the Gas business is looking very positive. Consistent with the regulatory pack that has a long history in California, if we continue to provide safe and reliable service, we should be well-positioned to capitalize on new and emerging opportunities. The investments in our plan are aligned with the goals of our external stakeholders, particularly the legislators and regulators who want to see improved pipeline safety. We have a capital plan in place that will provide a platform for stable and relatively predictable earnings growth for the next several years. And at some of the capital projects, particularly our Pipeline Safety Enhancement Program become more clear, it looks like we will be increasing our capital expenditures through about -- to about $5 billion over the planning period, which is an increase in expectations from what we told you last year.
So thank you very much. I'll be glad to take any questions you have along with Jessie Knight after the SDG&E presentation. So let me now reintroduce you to Jessie Knight, the CEO of San Diego Gas Electric.
Jessie J. Knight
Thank you, Mike. Good morning, and it's a pleasure to be here with you here today. First off, over the next half hour, I plan to give you an overview of SDG&E and review our recent accomplishments and outline our strategic direction going forward and showing how we are very positioned well for future success.
From a financial perspective, we continue to experience excellent results and we expect to continue that trend. Our management team and our employees are committed to our vision and we are able to strategically execute that vision by making smart, prudent investment decisions and delivering on our major projects on time and always on budget. The execution and implementation of our projects leads to operating excellence providing a safer, more reliable and more efficient system to serve our customers. And finally, I plan to discuss SDG&E's role as a leader in the utility sector for technological innovation, which has positioned us well in the changing electric and natural gas industry. But first, let start off with a brief overview of our company.
SDG&E's business reflects the distribution and transmission of approximately 20 million megawatt hours of electricity and 47 billion cubic feet of natural gas to over 3.5 million consumers from the southern portion of Orange County to the Mexican border. Essentially, all these consumers now have smart meters, that is about 1.4 million electric meters and 900,000 gas meters. Our rate base has grown to over $5 billion in 2011, with an additional $2 billion in construction work in progress, a significant portion of which relates to the Sunrise Transmission line, which is scheduled to be placed in service during the middle of this year. The composite of rate base reflects the growth in our electric transmission business, regulated by the FERC, which is necessary to enhance reliability and provide access to renewable energy. San Diego continues to be a leader among U.S. cities in the implementation and the utilization of new technology. And as I'll discuss later in this presentation, SDG&E's business continues to evolve with the technological transformation of how we are interacting with our customers. This provides us with an opportunity to leverage our core strengths in deploying new technology and infrastructure to lower our overall energy costs and our rates, while connecting to the changing demands of our customer base.
Let's take a quick look at how SDG&E performed in 2011. 2011 was an outstanding year for SDG&E. We achieved significant milestones on key projects that will provide lasting benefits to our customers with the completion of the mass deployment of the smart meter program and the near completion of Sunrise, which is now 83% completed on the overall construction. Debbie showed you the chart that showed that we were over 70%, but we have been moving fast and furiously, that we're 83% done at this point in time. Operational excellence and reliability and safety continues to be at the heart of our core values in providing outstanding service to our customers. We have a very positive regulatory compact in California, which supports recovery of prudent utility investments and other costs in areas that align with the state's goals in energy efficiency, system reliability, renewable energy development and also greenhouse gas reductions. In addition, the CPUC continues to recognize the risks that we faced by, again, approving the recovery of our excess wildfire insurance premiums at the end of the last year.
In the area of renewable energy, we are achieving our state renewable mandates. In 2011, we signed 17 new renewable contracts totaling approximately 1,500 megawatts and received regulatory approvals on the Rim Rock wind project, which represents the first ever utility tax equity program. Financially, all of this great work by our employees has resulted in our 2011 earnings increasing by 17% over the prior year. Our capital expenditures were the highest ever fueled by investments in the Sunrise project, smart meter and also the purchase of the Desert Star power plant from our affiliate. And finally, our fiscal strength combined with solid credit ratings, gave us the ability to access the capital markets at all-time low interest rates.
Next, I would like to discuss with you the status of 2 of our very important key regulatory proceedings, the general rate case and the cost of capital program. The GRC procedural milestones and the case status was discussed earlier by Mike Allman in his SoCalGas presentation. But it is important to know that for SDG&E, the $1.85 billion proposed revenue requirement represents the update that we just filed back in February. The increase of $235 million includes recovery of costs necessary for improving and enhancing our system, including the deployment of smart grid technology and the higher cost of wildfire insurance premiums compared to what is reflected in our current base rates. And as also mentioned in Mike Allman's presentation, SDG&E's earnings for the first half of 2012 will be based on our 2011 revenue requirement. But will be trued up retroactively to January 1, once the final decision in the GRC is issued.
The next slide covers our cost of capital proceeding. Again, the procedural timing of the CPUC cost of capital application was discussed in the SoCalGas presentation, but it's important to note that for SDG&E that the ROE for FERC jurisdictional earnings and revenues is filed separately in a FERC proceeding, which will become effective in September of 2013.
We believe that the inherent risk associated with our business, including renewal compliance, deployment of new technologies and ongoing wildfire risks, justify the new ROE to be adopted in the upcoming proceedings and should be very consistent with our current authorized returns. We expect that ultimately, the ROE adopted in the CPUC cost of capital proceeding to be on par with the other California investor-owned utilities. The cost of capital establishes the authorized returns we can recover on our capital investments.
Next we'll take a look at the investments SDG&E has planned over the next 5 years. SDG&E continues to implement the aggressive capital investment program that improves and enhances our infrastructure, solidifying our leadership role of investing in projects that align with regulatory and state energy policies. With the near completion of the Sunrise project, our capital spending transitions more to the base business. In fact, combined CPUC and FERC base capital, is up 12% from last year's plan as a percentage of total capital spent. That is 69% versus 57%. This is providing more stable and predictable earnings. Capital investments in our base business are necessary to maintain and harden our electric and gas systems to improve operational efficiency and increased reliability. Some of those key initiatives include our wood to steel pole conversion program, our condition-based maintenance technology to optimize the timing of replacing aging equipment, and also the deployment of smart technologies.
From a project perspective, as Sunrise is completed in 2012, we are focusing on substation infrastructure investments that further enhance reliability and access to renewable energy. Other key projects in our 5-year plan are the gas pipeline safety and enhancement projects and renewable investments including Rim Rock and other solar and wind projects.
Let's take a look at some of the more significant project investments. First, Sunrise Powerlink. This project represents a major success for SDG&E in executing the largest single project in the company's history and it will provide a tremendous benefit to customers for many, many years to come. I'm extremely proud of the work of our employees in reaching these critical milestones to complete a project of this magnitude, on time and on budget in a very tough environment. The 117 mile transmission line significantly advances our current infrastructure and will play a critical role in enhancing the overall reliability of our system, while providing access to important renewable resources necessary to meet California's aggressive renewable energy goals. As it stands today, we have made further progress on the December milestones that you see here, including $1.6 billion now invested and 83% overall construction now completed as I said. The project remains on track to be energized during the summer of this year, at which the total net investment will move from the construction work in progress account into our rate base. The amount of investment that will be placed in the rate base when Sunrise goes into service, will be approximately $1.2 billion. This is lower than the total gross investment because of the impacts of bonus depreciation. We expect that by 2015 a significant amount of the energy delivered via Sunrise will be renewable, and that by 2016, approximately 35% of our total renewable deliveries or 15% of our retail sales will be dependent on Sunrise. The completion of Sunrise provides us an excellent avenue of further development of substation infrastructure going forward. Electric substation investments are a key component of our capital program over the next 5 years and directly support our strategic objectives of developing infrastructure to facilitate the transmission of renewable energy and enhancing reliability of our system. The construction of our Suncrest substation, which is part of the Sunrise project, confirms our ability to execute and deliver on these important kinds of projects. While these investments are reflected in our capital plan as growth projects, they are in essence on facilities that are part of our core utility infrastructure that represents the bread and butter of our business.
These projects provide a variety of benefits to our customers, including the adjacency of key renewable facilities via Sunrise, the upgrade in the enhancement of overall reliability and the support of economic development in our local communities. As always, the timing of these projects depends on securing the applicable environmental permits and regulatory approvals, but we are very confident that the process will allow us to get the projects approved and built within the timelines that we specify.
In the case of our newest project, the South Orange County renewable project and to enhance transmission, we have already seen a favorable response from our local business community who has embraced the merits of the project. The substation projects are an important element in support of SDG&E's investments in renewable energy. SDG&E continues to aggressively grow its renewable portfolio to meet or exceed the state renewable goals, not only through the execution of purchase power agreements but also through investments being made by the utility itself. Upon completion of Sunrise, we will have access to a region that has great potential for incremental wind and solar renewable projects. We look to invest in projects where SDG&E's financial involvement can lower the overall cost of renewable energy for our customers. Of our $600 million planned investment in renewables, approximately 60% applies to projects that are already approved by regulators.
The Rim Rock project stands as grand testimony to this. We are particularly pleased that in 2011, SDG&E was able to secure regulatory approvals for the Rim Rock project in Montana, marking a further advancement in our renewable portfolio growth with an innovative, first of its kind utility tax equity investment, partnering with a proven renewable developer in NatureEner.
In obtaining CPUC approval, SDG&E works with regulators and interveners to develop a mechanism that will flow a substantial portion of the tax credits back to ratepayers to reduce the overall cost of the purchased power transaction, which in effect, helps to lower the rates for our customers.
Earlier this year, financing for the project was obtained by NatureEner and construction was commenced. SDG&E will invest in the project at the commercial operation date, so there is no SDG&E capital at risk until the project is completed. We believe the tax equity framework is a very creative and innovative and successful model that could be applied to future investments of this nature to reduce the overall cost of renewable energy to our customers.
Let's take a quick look as how SDG&E is doing in meeting the state's renewable energy targets. As you can see, SDG&E is well-positioned to reach its renewable requirements through a combination of portfolio management and additional purchases and investments. This graph shows where SDG&E stands at the end of 2011 in terms of our renewable target and where we expect to be in the year 2016. And as I mentioned, in 2011 alone, we signed 17 new renewable contracts for a total capacity of 1,500 megawatts, which is comprised primarily of solar and wind resource. As it stands today, SDG&E is exceeding its renewable goal of 20% for the 2011 to 2013 measurement period, and our contracted portfolio for 2016 is significant enough that we expect to exceed the 2016 RPS requirement of 25%. All of our renewable contracts are preapproved by the CPUC prior to any delivery of actual energy.
With Sunrise coming on later on this year, we expect solar to significantly increase its relative share, approximately 16% beginning in 2013. Solar will primarily replace geothermal and hydro contracts that roll off by 2016. Electricity from clean, renewable resources provides our customers with a tremendous environmental benefit.
Next, I would like to discuss with you what SDG&E is doing with technology that further environmental and economic value is brought to our customers. As I mentioned earlier, SDG&E continues to be a leader in the implementation of smart technology to further enhance the reliability and the efficiency of our system. Investing in smart technology is now a part of our core business and is embraced by the CPUC and FERC. Smart technologies enhance our ability to communicate with our customers and empower them to evaluate products and make decisions regarding their usage. We invest in projects that are aligned with California's energy policies to encourage energy efficiency, the development of clean and renewable energy and also to reduce greenhouse gases, and overarching, to make sure they deliver economic reliability and/or environmental benefits back to our customers. The completion of our 2-year mass deployment of smart meters, among the first in the nation to do so, was achieved in 2011. And we look to leverage this technology to offer our customers a full array of enhanced services. Smart grid investments are reflected in our comprehensive deployment plan filed by the CPUC last year and are included in our 5-year base capital plan. The San Diego region is a leading adopter of electric vehicles in the nation, and SDG&E will play a vital role in the development of the infrastructure to support the growth of this industry.
Now let's take a look at the financial impacts of our capital plan. Based on SDG&E's estimated capital expenditures, we expect rate base to grow by 7% to 9% over the next 5 years. And as I discussed earlier, much of the growth in rate base is due to our electric transmission business, a 17% increase for FERC jurisdictional rate base and that includes the in-service of Sunrise and eventually our other substation infrastructure projects. Because our investment strategy is targeted at projects that will provide customer value via enhanced reliability and/or efficiency, the impact to customer rates will be mitigated by the economic benefits.
And lastly, since our capital projects are aligned with the regulatory and state policies that we operate under, we believe that new projects will receive timely regulatory approvals to begin construction and ultimately, will be placed in service as scheduled.
The next slide shows the projected earnings over the next 5 years. SDG&E's financial outlook continues to look promising with steady, sustainable earnings growth. Allowance for funds used during construction or AFUDC as we call it, is a greater component of our earnings in 2012 due to Sunrise, which will be placed in the rate base from CWIP, construction while in progress, during the middle of this year. The growth in earnings from the FERC component reflects the service of Sunrise and the eventual completion of the substation infrastructure projects. Because our investment strategy is targeted at projects that provide long-term customer value, our investments will produce benefits that mitigate the impact on customer bills. Despite the annual growth of our rate base of about 7% to 9% over the next 5 years, our residential electric bills are expected to increase by only 3% to 4%, a little bit above inflation, and I should further point out that our bills are 40% lower than the national average. The main driver of the overall bill increase is the commodity cost, which reflects projected fuel costs and the growth in our renewable portfolio to comply with California's renewable energy mandates. And as I mentioned earlier, our capital program is largely driven by investments in core utility infrastructure that utilizes smart technology to reduce ongoing operational expenses and the cost of future investments. We are already starting to see these benefits with the deployment of our smart meter program.
In addition, with the growth of our FERC jurisdictional investments, including Sunrise, a significant portion of these costs are spread to all California transmission owners, reducing the overall allocation to SDG&E customers. And finally, even with the increase in cost due to renewable growth, our creative approach in delivering investments such as Rim Rock, help to lower the overall commodity cost from what customers would have otherwise had to pay absent our investment.
The next slide summarizes our 5-year earnings and capital targets. With our track record of executing on major projects and effectively operating our system, we are very confident that we will achieve these earnings targets. Capital expenditures for 2012 and subsequent years are still robust despite the completion of Sunrise and include the growth in our base business, substation infrastructure investments and the gas safety and enhancement project.
So let me summarize the key message points that I've covered. SDG&E has demonstrated a proven and consistent track record of operating excellence, project execution and innovation that have driven our strong financial results. Our strategic plan and investment strategy is in alignment with the policies of the governor, the state legislature and our regulatory agencies both at the state and at the federal level. We focus our capital investment strategy on projects that provide value to our customers and help to reduce overall rates, and we have proven that we can deliver on our major investments, getting projects built on time and always on budget.
At SDG&E, we have established a deep culture of providing a safe and reliable service to our customers, and this is reflected in recognition that we have received not only for the large projects that we implement but for what we do every day in the operation of our electric and gas systems and in the interactions that we have with our customers. Going forward, we plan to continue leveraging our existing assets and our expertise in managing major infrastructure projects to implement technologies that will enhance our ability to safely, reliably and more efficiently serve our customers. The financial targets you see here today show our conviction in SDG&E's vision for the future and also for our employees, and their ability to be able to deliver on that vision.
Thank you for your time this morning and I'd like to invite my colleague back up on the stage and we will entertain your questions.
I have a general question as it pertains to the customer rate impact assumptions because de-coupling is such a big aspect of how you set rates. Really, my understanding is that over time for you guys to be able to socialize all these investments, you've got to have population growth. So there has to be some assumption that overall customer base continues to grow, so that you can hopefully spread the cost of a lot of the fixed infrastructure over a wider base of customers. Can you talk about what your demographic assumptions are in terms of underlying customer growth, population growth, your base case California economic assumptions as it pertains to the rate impacts?
Jessie J. Knight
Well, for customer growth, for SDG&E, it's about 0.6% as compared to last year was 0.5%. So we'll have about 8,000 new customers on the electric side. And so the -- it's not so much population growth that is a big contributor for how we are managing this, it's really the portfolio of options as I described in my presentation that will help us drive our cost down by becoming much more efficient and utilizing the technologies that are evident, that are being introduced in this business, for us to become much more efficient to help get rates down.
Michael W. Allman
Let's not forget that for the gas company that for the last 4 years, our customer count growth has been less than 1% a year and we're forecasting that to continue for the foreseeable future.
Michael Goldenberg - Luminus Management, LLC
Michael Goldenberg, Luminus Management. Looking at your assumptions, SoCalGas is very clear as to how much of net income comes from incentive mechanisms. I did not see the same kind of disclosure for SDG&E. Would you be able to shed some light as to what you see as levels of earnings above authorized and where it's coming from?
Jessie J. Knight
Right. For SDG&E, the incentives are not as robust as we had in the past. It's about $2 million in the plan as compared to -- we had $14 million last year, for example, for energy efficiency. The majority for us is really driven by AFUDC equity earnings on CWIP. So that's the difference that you'll see there and operating efficiency, obviously too.
Faisel Khan - Citigroup Inc, Research Division
Faisel Khan with Citigroup. Just a couple of questions. On SoCalGas, the levels of incentive mechanisms that you talked about, I think, $5 million to $6 million seems a little bit lower compared to the past. Why do you think that number is going to be lower going forward than what's in the past? I got a couple of other questions.
Michael W. Allman
Okay. The incentive mechanisms for the gas company, the 2 major components are our gas cost incentive mechanism and our unbundled storage, both of those provide opportunities for rewards for our shareholders if we're able to be the benchmark. And the first one in buying gas less than the benchmark and the second one is selling storage. Both of those markets are depressed given the pricing impacts that we've seen lately. It's -- in fact, it's just harder to beat an index when the buy-dollar amount when the price of gas is low and as you know, the value of storage has declined recently. So those 2 drivers are reducing our opportunity for profits in those mechanisms.
Faisel Khan - Citigroup Inc, Research Division
And then SoCalGas, again, you talked a little bit in your prepared remarks about the cost of capital proceeding later this year and how you're going to try to include in that proceeding the increased risk of operating a gas utility. Can you talk a little bit more about that and how you guys are proposing to make that part of the proceeding?
Michael W. Allman
Look, clearly, the risk of the operating a gas utility has changed. Go back a couple of years and ask yourself what probability would you have assessed in a gas distribution company in California would have a shareholder loss over relatively short time that exceeds the rate base of their transmission system. I think you probably would have assigned that something close to 0. But it looks like given what happened up north that, that's likely to happen. The continued to mandate for greater and higher levels of safety, I think, point to a clear direction that we need to entice shareholders to put money into our company for these important investment. We can't mandate that you invest in our company, we have to invite them through an adequate rate of return. So I think when you look at the cost benefit trade-offs, there's no doubt that the risk -- the gas risk is higher and therefore the return should be higher. And I will also point out that the current rate of -- authorized rate of return on equity of the gas company is the lowest across the state. It's traditionally been a little bit lower than where the electric companies are. Today, there's no reason for that -- there to be a difference there.
Faisel Khan - Citigroup Inc, Research Division
Okay. On SDG&E, 2 questions, the FERC ROE process that takes place in 2013, what are the risks that, that number goes, I guess, the downside, it goes down or the risk that it goes -- the benefit, it goes up? Like what's going to drive that process? And then the last thing on SDG&E, is the renewable energy mandate in the state, are you seeing any sort of political friction from consumers or customers that, that should slow that down at all?
Jessie J. Knight
Okay. The first one on the process for the FERC, the same rationale for the business in that, for the FERC and the PUC to look at what are the risk inherent in this business and what is the right level for -- and ROE and so the same considerations would be there, the same case is going to be made in both proceedings. As far as political friction on renewables, I think it's just the opposite. I think consumers are clamoring for more renewables. There's a talk about even trying to increase the level over the 33%, which we're not sure that's going to happen. But nevertheless, we don't see that, that interest on the part of consumers and our regulators and policymakers that that's going to wane anytime soon. I see fewer hands because I think we answered so many questions last night.
Greg Reiss of Catapult Capital. Just really a quick question to clarify, when I look at the rate base slide, when you showed the ranges there and then the dotted boxes for the CWIP. Do those ranges included the CWIP or is the CWIP on top of those ranges?
Jessie J. Knight
Yes. It's in the range.
It's within the range. And the same thing with the earnings? The earnings include the AFUDC?
Jessie J. Knight
Winfried Fruehauf, W. Fruehauf Consulting Limited. Two questions. Debbie provided estimated earnings growth rates for the California utilities and for Sempra International, but she shied away from disclosing expected growth rates for U.S. electricity and gas, what is that rate or the range?
Jessie J. Knight
The rate of electricity gas earnings?
Jessie J. Knight
Okay, we're showing 7% to 9% growth now.
Well, earnings, I think, is 8.8% if you look at it specifically.
I'm talking about U.S. gas and electricity.
Jessie J. Knight
Oh, that I don't have. We can give that to you.
In fact, it may be covered in Jeff's presentation.
Second question is why is SDG&E's expected earnings growth rate so much lower than the expected rate base growth rate?
Jessie J. Knight
I think it goes back to, I think, something that everybody has to pay attention to is that there's 2 segments of our earnings. One is we have so much in the construction work in progress, in 2012, about $1 billion, the earnings off of that has to be combined with the rate base. If you add those two together, you will see that, that's in line with our earnings CAGR. Okay. I think we're good.
Steven D. Davis
Okay. Now I'd like to ask a Mark Snell, the President of Sempra Energy, to come up for the next part of the presentation.
Mark A. Snell
Okay, good morning. Change of role here for me, being President. Used to be when it goes, my spot always stood between you and the bar. Now I stand between you and lunch. So I'm not sure that's better.
Okay, what we're going to talk about today is really -- I first want to start off by kind of going through our new structure. I knew Debbie touched on it. I'm going to give you a little mapping of how we got there. And then the other thing that I want to talk about today, too, is part of the process that we went through. Debbie had talked on the conference calls earlier this year and also mentioned that we went through a fairly rigorous sort of evaluation of our assets and what we thought fit and what didn't fit, and I want to talk about those and kind of where we are in that process.
And then lastly, I want to talk about liquefaction and what the opportunities are for that. And then at the end of the presentation, I'll take questions on liquefaction and on some structural things that we're looking at, mainly the MLP. But specific questions on the Gas business or the International business, we'll take those when -- after Jeff and George have finished their comments later today.
This is a slide that you saw before, what our new operational or organizational structure is. And I would say that first and foremost, what we wanted to do here was we wanted to realign the company in a way that we thought that we could best most effectively manage the businesses. And then a sidelight to that is that we really wanted to be able to distinguish between our foreign earnings and our domestic earnings. And that plays into some of the things we're doing. And then along that lines is we also listen to you. We had a lot of feedback on the way we were -- on the way that we were presenting some of our data in the past, and we try to incorporate that feedback into giving you something that we thought was more clear and provided greater transparency to how our operations really work.
Now with the international assets, what we're trying to do here again is trying to group these assets so that it's very clear what earnings come from outside of the U.S. It's fairly simple. It’s our South American utilities and our Mexico assets. Now, and with this, those 2, Sempra Mexico and Sempra South American utilities, those are also reportable segments, and you will get that segment data on a historical basis every quarter. And we'll, of course, be providing guidance on Sempra International.
Now the same with the U.S. gas and power assets, we split this up into renewables and Sempra natural gas. And in this split here, again, you'll get that 2 segments, the renewables and natural gas would be reportable segments, and we'll be again providing guidance for the business unit.
Also, too, I just mentioned that we do plan to file an amended 2011 10-K, which will restate all of our segments, our old segments into this new format, so you'll have all that data going forward. And I think the guys that probably suffered the most from this organizational change are the accountants as it usually goes, but that's what they get paid for, and they're working away at getting this done. But it should be done fairly quickly here.
Okay, now as we talked about a little bit a lot, I guess, is that we did do a fairly extensive look at our assets. We really wanted to find out what was the strategic fit for each asset in our portfolio. And then we kind of did an evaluation. We said, "Look, if this doesn't have a strategic fit, then what should we do with this asset?" Obviously, we could keep it or sell it or -- we took a look at those options and really the things, the criteria that we looked at and the way that we focused on this was probably similar to the way how you would look at assets. As we looked at it, so okay, what can we sell this asset for and then what can we reinvest those funds in that will give us similar kind of return. And if we thought that we could reinvest in something that was more strategic to our ongoing businesses, then we would choose to sell the asset. And if we thought that, for whatever reason, that the asset value was at a period that didn't make a lot of sense to sell it or we couldn't reinvest at that kind of return, then we'll probably hold on to it for a while.
And then finally, we also took a look at the way that we were organized around all of our assets and what was the optimum kind of capital structure for each class of assets that we had. And then we made some decisions around all of that. So now let's look at some of the key assets you've been asking us about in more detail.
Gas-fired generation. Debbie fairly emphatically said we're not going to be in the merchant generation business. And I think we really haven't been in a merchant generation business in the past in the sense of the way we think about it. Our merchant generation fleet has really always been pretty much 100% contracted until just recently. And where we sit right today, we have about 1,800 megawatts of mostly uncontracted combined cycle natural gas generating plants. They're relatively new. I mean they're 10 years old, but they're still relatively modern, low-heat rate plants, but fairly desirable as far as gas plants go, but they are largely uncontracted since the DWR contracts expired.
Now I will say that we have managed to place some contracts on these plants, but those contracts don't start for a couple more years, but they do have significant value. One of the things that we looked at was what was the value of these plants. So we did a fairly extensive market study. We looked at a lot of existing transactions. We actually had several different banks come through and help us with valuations. And we even test-marketed the plant to see what we thought we could sell them for. And what we discovered was probably, maybe not news to any of you, but we do have a book value of about 470 a kW. And really the market for plants in Southern -- in the California market or in the western market is about that, maybe a little more, a little less, depending on where the plants are located and different things. But one of the things we didn't know, too, as I said, we started to layer on contracts. And the contracting value of these plants, what we can turn them out on the long-term basis is closer to $600 a kW or better.
And we think the best strategy right now is to layer on some contracts, get these plants having more significant cash flow. And then if we decide to sell them, it will be a lot easier to do that, people will be able to finance them a lot better. And it also opens up a broader universe of purchasers. So we think that there's some value in at least temporarily working with trying to hold on to these and contract them up.
The other asset that we took a long look at was storage. We do have a fairly significant investment in storage, and we're clearly at the bottom of a market cycle. If you can see from this chart, the values that we were getting a few years ago for high-turn and even low-turn storage were significantly in excess of the values today.
So we did a couple of things. One, we made a decision to drastically reduce our build-out program. As you know, we have caverns under development in Mississippi and Louisiana. But we've cut that way back. So we're just going to build out the current value -- the current caverns that we have under construction. That's going to leave us with about 43 Bcf of total storage capacity. The total capital, we're going to pay for that. It's about $150 million or it's about 1% of our capital over the net years. So it's relatively insignificant.
We do have the opportunity to continue to build out the full 57 Bcf if the market starts to turn around. But we don't need to do that right now. We can actually do that relatively quickly. The other thing that we did, too, was we really -- well, as we do build these out, we're really just building out the caverns, and we're not really developing a lot of compression, which would give us the higher turns. So instead of 9, 10 turns storage that we originally had planned, these caverns will be more in the 4 to 5-turn kind of storage. But it really doesn't matter because the market wasn't paying us for those extra turns anywhere.
So this is what we're doing with this now. You'll see later, when we talk about LNG, why we think that these assets are still very strategic to us and has a real high -- has an important role to play in the way that we develop our midstream gas business. And as you see, we also believe, too, that storage is going to become more and more valuable in the future as we sort of see this coal-to-gas shift and as most utilities go on a more gas-oriented development base where they have -- where they're using gas for electricity. To produce electricity, storage becomes much, much more important. And so we think the value will go up overall.
Now we're in an interesting kind of dilemma right now, too. We're actually running out of storage in the country because of excess gas production, and there's no place to put it. We haven't really seen where that's going to spike the prices yet, but it looks like it's going to be an interesting outcome here in the next few months if we keep putting the amount of gas in storage that we're currently doing.
Okay, now I'm going to switch gears a little bit and talk about LNG. Really, this is the most exciting thing that we have in front of us, especially on a non-utility side. It is a wonderful opportunity, but before we get to that, let's just take a little overview of where we are. We currently have 2 LNG import facilities. Costa Azul is located in northern Baja, California. That's a fully contracted facility, and it has a very significant cash flows, about $175 million of EBITDA. And then Cameron LNG in Louisiana, it has -- it's a bigger facility. It has about 1.5 Bcf per day of send out, but it's only about 40% contracted. Now, Cameron does operate a positive cash flow today, but it's about break even on a net earnings basis.
But this story is all about reversing the flow. And this chart that you're looking at, you've all seen probably before. Our friends at Shaner used something similar. But what it does is it shows the large amount of headroom that we have both between the European oil prices or oil link LNG and also the Asian oil link LNG, $14, $17 an Mcf. So there is -- this is obviously what's generating all the excitement. And it's one of the reasons that we have such a high degree of interest in turning these facilities into export facilities.
And you can imagine on the Asian stuff, what's happening in Japan with the shutdown of their nuclear plants, their total need for LNG has gone up by about 20 million metric tons a year or 20 million, 25 million metric tons a year. And they really are looking for a source of supply. So they're going to be turning ever more to the U.S. for that.
So this is the project, the current project that we have in mind and that we're in the market right now talking to customers about. 2 to 3 trains of liquefaction. Each train is about 4 million metric tons a year. But the ultimate size of the facility will actually be driven by the customer demand. So the customers are going to tell us how big this facility is going to be. We do plan to use a commercially proven technology. We're not doing anything kind of new or different. It's an air products technology. I think the most recent example was the facility in Peru. That was built fairly quickly and on time and on their budget. And it's the same technology that 80% of the facilities around the world use.
Our intent with this is to sell tolling capacity contracts. Unlike some of the other players in the market, we are not planning right now to sell the LNG or sell the commodity. This is a tolling facility. We're going to be tolling the capacity. We have a lot of interest in that. We don't think we need to go to the -- to take that commodity risk, although that risk isn't huge, but it's still a risk, and you still have to manage it.
And then the other thing, to the last point, too, and we're going to get into this. I'll show you the structure later, but we plan on leveraging the existing infrastructure we have. And we really don't think we have a lot of capital that we'll have to put into this, but we'll get into that in a minute.
Now some of you have asked me questions about why Cameron? Why do you think that facility has any advantages over others? And a lot of it is while we weren't as quick in the queue as Shaner, we're sort of right behind them and there are other facilities with us. But I think compared to those other facilities, we do have some real advantages.
First is location. We are located next to some of the bigger shale plays in the country. And there's significant pipeline and infrastructure already in place, so there's really not a lot of additional development that needs to take place. And secondly, we, Sempra, we control a lot of the access capability into our pipeline. We control -- into our facility. We control the pipelines, and we also have storage opportunities nearby that both us and -- Shaner is looking at as well. But we have some very good storage opportunities, which become increasingly important when you're running a liquefaction facility.
And then I guess the last thing and this would be true out of all the export facilities. You have a big leg up by already having this existing infrastructure in place. The things with this facility that really, if you were building a greenfield from scratch, that really could have cost overruns or have issues, effectively the marine facilities would be the -- is the one that's always sort of hard to gauge from a construction respective. And obviously the -- ours are already built. They're in place. We can handle the big tankers, and we can handle multiple ships at one time. So we have a lot of the infrastructure already in place. And then I guess our ownership structure does play a part, too. Some of the facilities out there have a lot of complicated depth structures, where you need to get a lot of consent to do something and move a project forward. Obviously, we at Sempra, we don't have that issue with our facilities. We own them. We control them, and we can pretty much do as we please with them.
Now I will stress that we don't have an agreement in place just yet, but this is the -- this structure that we're looking at is what we're currently negotiating. And we do believe that this -- something very, very similar to this is what we will see when we come out the other end of this process. Our contribution to liquefaction will primarily be our existing facilities. We have a basis -- the cost in those facilities are roughly $1 billion, and we will be contributing that into a joint venture. We expect a joint venture to at least be 50-50. And we expect our partners to be our customers. This is important for a couple of different reasons. Most important of which, this is a 20-year commitment that we're asking for from customers. 20 years committed to paying a tolling fee at a fairly good return to liquefy natural gas. I think we all are aware that there will probably be times during that 20 years when that contract will be very, very valuable. And there will be times when it may be out of the money. And we really believe that having our customer and the person holding that tolling agreement also being a partner in the facility makes the sanctity of those contracts much more solid.
We've learned that from experience. We've been down this road before, and we really believe that this is the optimal structure for this kind of a facility. Now we would -- the example here is -- would be for 12 million metric tons. That's a free train facility. It's a $5 billion to $6 billion incremental investment, but you can do the math relatively quickly. Let's say it's $6 billion. You put another billion dollars of our facility into it, you have a $7 billion facility, you finance that $730 million, we would have a little bit of incremental cash in that case that we would have to put in to match the equity contribution of our partner. But we think that it's relatively nominal, and the cash flows from that kind of a facility, a 3-train facility should be something a little bit north of about $300 million a year of net income, $300 million a year of net income. If we did a 2-train facility, we would actually be over capitalized. There would be an opportunity we can take a little bit of capital out. The net income from a 2-train facility, given the returns that we're looking at are roughly around $200 million a year. Makes sense? This is a fantastic opportunity. As Debbie said, we have an opportunity here to build a company the size of SoCalGas almost overnight.
So where are we on this? Okay, what we have done, we have received our -- what we call, FTA. Even on our side of the business, we have kind of at least some acronyms. We can't keep up with the utilities without at least some things. So our free-trade agreement. That free trade agreement permit we've already received. And, we, like other facilities, we filed for that and received that because we knew we would get it quickly, and it was a requirement before we could file our DOE permit. We really had to have an export permit before the DOE would really evaluate our permit. So we do have that. We've selected our owner’s engineers, and they were in the middle of the process of the design of the preliminary design of the facility. We should have that shortly, you'll see here. And we picked up financial advisor because we've gone into this with the idea that we're going to project finance it right from the beginning to minimize any kind of Sempra capital in the project. We've done that and that's underway. And we've also filed for our permit for the non-FTA export license.
Now what we would expect is some time in about the second quarter of '12, maybe sooner, we would expect to have commercial development agreements with our customers. And let's talk a little bit about what that means. These commercial development agreements will effectively tell us who our customers, who our end customers are going to be. They will commit to the facility. They will commit to not enter into any negotiations or into any contracts with any other facility. They will fund our prefiling cost or engineering -- they will fund our engineering studies. They will fund our permitting fees and those kinds of things on an equal basis with us. And our commercial development agreements contained language that tell them what the tolling agreement that they're expected to sign at the end of -- once we know the final design cost and once we know the final cost of the facility. We've got our EPC contract. They'll sign tolling arrangement that will commit them to a tariff for 20 years. But this commercial development agreement, while it doesn't bind them to have to sign the tolling arrangement, it compels them to sign one that's substantially in the form that we attach to the agreement. So we really have worked out all of the sort of details around the plan. So these are very important agreements, and they very much tell you that this facility is moving forward. So again, we expect those in the second half of this year or second quarter of this year, excuse me, not second half.
The preliminary engineering design, the tolling agreements with customers, that'll probably be all executed towards the second half of this year. The EPC contract, we expect to finalize that around the first part of 2013. And then we would expect deferred permit and make final investment decisions around the second half of next year. And then all this, if it goes according to plan, comes together, and we start operations in late 2016, early 2017. Some of you have asked how much liquefaction earnings are in the plan. There is a very small amount, about 1 month's worth in 2016. So if you want to know what that is, I told you what the earnings are, you can divided by 12 and figure that out.
Now one of the reasons we're so excited about this liquefaction opportunity is for a long time, you have been talking to me and I've talked to you about an MLP. We always get the questions, why don't you take your midstream assets? Why don't you make an MLP? It could be a great thing to do. And we agree. It will be a great MLP. One of the things that we've always struggled with is that we have built our midstream business kind of from a greenfield perspective. We've built it up from the ground up. And we've been in construction on some of these things for so long that we didn't always have the cash flows that we felt that would really support an MLP going out of the box.
Now we actually believe that we're really on the verge of being able to do that, especially if we can sign these agreements. And we know that liquefaction is a certainty. Then we really do have the underpinnings for a terrific Sempra MLP. With that -- it would, of course, include Cameron liquefaction, but it would also include all of our natural gas pipelines, which now would all be pretty much fully utilized with the LNG facility with the exception of REX, which I can talk about a little bit if you want to. But REX actually has terrific early cash flows. So this would be a great bridge. We could put that in right away. It's cash flowing about $80 million to $90 million a year, so it would be a great MLP asset to start with. And within -- by the time contracts at REX start to roll off, and that cash flow, to the extent it diminishes, would be replaced by the liquefaction assets.
So anyway, we really think we're on the right track here. We expect to be able to do this within the next year to 18 months. So this is something that we really think is the right capital structure for our assets. We also look at the capital structures for some of our other assets. And I will say that with respect to, for instance, our Mexican assets, much like we did in Peru, we're going to look to have local investors in those assets as well, and we're analyzing the structure that best achieves that, but you could probably expect to see some of that coming out of us later this year as well.
Okay, so look, to just kind of wrap up. We've created these new operating units. We told you how we're going to provide guidance in the reporting segments. Joe can kind of go into the details of that later, and he will talk to you about that. But I think the most important things that we've done is we have done an extensive review of our assets. We put them in categories where we think is going to happen to all of them. We try to tell you what those stories are and where we're going with each of them. And then we've got this really terrific opportunity with LNG that really is transformative on a non-utility side of the business to create a really great business that has great MLP potential going forward. So with that, I'll take any questions.
Winfried Fruehauf, W. Fruehauf Consulting Ltd. Regarding LNG exports, can you please explain to me why the suppliers of LNG, current suppliers of LNG to Cameron and other North American LNG terminals like for example the one in Canada, why would they want to partner with you when they have the choice of exporting the LNG simply to a different market, having regard to the widening of the Panama Canal, which will allow much larger vessels to transit that canal?
Mark A. Snell
I guess I'm not sure I understand your question. Why would who want to partner with us?
Whoever supplies Cameron. And I know who supplies the Canadian LNG terminal. Why would these suppliers come out of Trinidad, essentially? Why would they not simply redirect the LNG production without joint venturing with you?
Mark A. Snell
They may want to redirect, but it's not those suppliers that really would be our customers. I think the suppliers that would be likely to be customers to the Cameron LNG liquefaction facility are people like the Japanese that are end users. There are also people that have global LNG markets, who recognize this as being one of the cheaper forms of LNG currently available in the world. That could include BP and Shell and all the majors. Most of the national oil companies are looking at this. The success of this facility is not going to be -- right now, it's certainly not the case, but it's looking -- the facility looking for customers, we have lots of customers that are interested in the facility. It's probably the more challenging part. It's probably more the regulatory process and how big of a facility we'll ultimately be able to build.
Faisel Khan - Citigroup Inc, Research Division
Faisel Khan with Citigroup. If you can talk a little bit about kind of where you guys are in the process versus everybody else. If you feel like you're ahead -- I'm talking about the project timeline in Page 14. How do you feel you are versus the rest of the guys out there Freeport, Cove Point, Lake Charles? And then I've got a follow-up after that.
Mark A. Snell
I would say -- Shaner is clearly in front of us, in front of everybody. They've captured this opportunity early and kudos to them for doing a wonderful job with that. And I think we all kind of wished we would have started a little sooner. I think we're a little more skeptical in the beginning, and we had to see the market really -- the market pushed us into this as opposed to us pulling the market into it. I mean, we really got so much interest in developing this facility that it prompted us to action. So I think from that perspective, we're -- I do believe we're #2, but I think it's a crowded #2. We've got a lot of people kind of right around with us.
Faisel Khan - Citigroup Inc, Research Division
Okay. And then where are we with the political friction? Export, is it -- is this -- we hear banter about it in the news all the time and you see it in the Journal, but what's the reality? And I think we're also recently heard that the DoE's doing some sort of study. So can you kind of explain to us kind of where things are then?
Mark A. Snell
Well, let me tell you what I know. And some of it, I'll try to keep the opinion and just kind of stick with what the facts are. The DoE is doing a study. They're expected to come out with it. There's rumor in the market that it's going to imply, sort of, an 8% to 12% upward price pressure on natural gas, if we were to export something in the neighborhood of 8 or --excuse me, I think it's 12 million to 15 million metric tons a year, something like that. But that said, there is a couple of interesting things at play here. One is there's kind of 3 outcomes for this as we see it. There's full sort of export capability, full non-FTA country licenses and probably granted on a fairly large scale basis. That could happen. That would be great for the natural gas industry. It would be great for employees that work in that industry. It's a huge uplift for the natural gas business. After that, you could have something that's something reduced, maybe that's kind of -- sort of 1A. You get full export capability, but it's capped at some number of metric tons per year. We think we're far enough in the queue that we would get some of that. We really believe that we would. But that's a possibility. The other possibility is that we only are allowed to export to free trade countries with the special exception for Japan. Somehow Japan gets -- because of their problems with their nuclear fleet and the fact that the world would like them to be nuclear free, they need to export -- they need to import a whole bunch more natural gas. And I think the U.S. special relationship with Japan will come into play. Also, we very much would like Japan not to use Iranian oil. And so if they're going to give up that source of energy, they're going to need a substitute. So all these things are going to come into play. So we think that there is a possibility and there probably should be some kind of exception made for Japan. We don't know how that -- what form it will take, how it will happen. We know that there's negotiations going on. We don't really know the outcome.
The third thing is that -- no exception for Japan. we only have non-FTA countries. That's still -- or excuse me, only FTA countries. That's still a pretty good-sized market. There's about 6 million metric tons a year right now that they're actually in the market actively looking for. We would be a low-cost provider to that. The other part of that is that it's still a pretty big market. Korea being the largest FTA country end user, they use about 65 million metric tons a year. They would very much like to kind of reduce their cost, so we do think there's opportunities for that. They would probably limit the size of the facility. But even if we were only to build one train, 4 million metric tons a year, even if we were only to build one train, that would take this Cameron facility from being a breakeven kind of earnings facility to something that looks like sort of a 9%, 10% return on overall investment.
So even just one train would be a good business. So we really see our downside in this as relatively limited, because we do think there will be some exports from the U.S. even if it's only to the free trade countries. But we actually think something bigger is probably much more likely.
Faisel Khan - Citigroup Inc, Research Division
To follow up on that. Are you in exclusive negotiations with counterparties right now, only you and the other counterparty? And then just one question on the self [ph] cavern storage, does that mean you guys are injecting base gas, but leaving compression kind of to a future investment later on?
Mark A. Snell
Let me handle the first one first. I'll take them in order. We're not in exclusive negotiations with everybody. Once we sign CDAs, these commercial development agreements, then we will have binding -- we will be bound together and only in negotiations with them. But most of the negotiations will have been completed. But we're talking to lots of parties right now about these, and we expect to sign CDAs, as you said, like I showed you on the timetable.
With respect to storage, what we're not doing is, we're not paying for a lot of compression, which actually increases the number of turns in the facility. So we're -- but we still have base gas cost, that's still part of the development cost. It's just that we don't have the extra money for compression. Does that answer your question?
Just a couple of questions. One, is the $300 million your portion of the net income or is that the overall facility?
Mark A. Snell
Okay. And then the second thing is, can you talk about what kind of JV partners you're looking for?
Mark A. Snell
We want our partners to be our customers. So we train same people.
And any kind of sense on...
Mark A. Snell
On who they are?
Big producers. You have that...
Mark A. Snell
No, we're not going to tell you, but you can guess. It's small universe.
And then the cash flow from this facility, would that be significantly more than the earnings?
Mark A. Snell
Well, it's a $6 billion facility with -- plus our $1 billion to $7 billion, call it a 40-year life. Depreciation is a big difference and the interest on the debt. If you add those 2 back, you can come up with EBITDA. I would do it for you, but I can't do it quick in my head.
Greg Reiss [ph]with Catapult. It seems like -- I guess your view on low natural gas price environment is driving this LNG export facility. Just wanted to see how you guys reconcile that with the kind of a robust outlook you guys have on the renewable business. So it seemed kind of counterintuitive with low gas prices usually being a headwind for renewables.
Mark A. Snell
Look, I think -- we believe that the renewable program, and Jeff will get into this more after lunch, but the renewable program right now, especially in the West, is driven more by mandates than it is by economics. It's not to say they're the best economics -- renewables compete on economics against other renewables. Clearly, they're not competing on economics against natural gas. Now that's primarily a California phenomenon, which has had a higher target. But even all the states have some minimal targets in the West, or at least most of them do, that are driving renewable development. And I think one of the reasons that we've been more successful, especially on the solar side than others, is because we have really -- we've been able to be the kind of the low-cost renewable provider because we have existing land positions. We're not dealing with the BLM [ph] or a bunch of government programs that delays and had a lot of issues with trying to get things done. So we had our own land. We've been adjacent to our current generation facilities. That's where our land is. So we have all of the energy infrastructure, the transmission infrastructure in place, so that we felt we had a cost advantage. And I think we've been taking advantage of that and then kind of a low-cost renewable provider. We're not trying to compete with the natural gas-fired generation.
Larry Alberts with Columbia Management. This goes back to one of Debbie's charts and has to do with the goals and initiatives for 2016. So I make sure we get this answered a little bit. It says larger U.S. facility footprint with adjacent energy infrastructure growth opportunities. Could you expand upon that a little bit?
Mark A. Snell
Sure. I think one of the things that we realized as we did kind of our strategic review and looked at where we've been successful and where we haven't been successful, one of the things that did kind of come to our attention and it was fairly clear and obvious was where we have a utility footprint, we tended to do very well around that area. We had a very good understanding of the infrastructure. We had a very good understanding of customer needs. We had a very good understanding of the regulatory model. And we tended to be very successful even on the non-utility side, if we kind of focused in that footprint. One of the things -- we have Mobile Gas in Alabama. We've been doing some things down their trying to -- we did a little acquisition recently to expand the footprint. I'm just using that as an example. It's not necessarily the only example. But we did this small acquisition, and people may have said, well, gee, that's just a little tiny LDC. Why would you do that? Why would you add that to Mobile Gas? But we started looking at that and we looked at what the needs were in that area and there's a lot of munis in that area that need power, and they're looking at natural gas. And if we have one power plant located in that little LDC, one power plant doubles its throughput. So we look at opportunities like that and say, hey, this is something that we can really grow and expand upon. And we're trying to do that. We're trying to do that all over the place. And one of the things we'd like to do is continue to expand our utility footprint because we think that gives us a lot of insight into how market works and how we can really be successful. That's the way we've been successful in the past.
Mark, I seem to recall that when you originally financed Cameron, it was with Sempra debt.
Mark A. Snell
So should I think of that asset now as being basically un-levered? Or like how should I -- if you're contributing $1 billion of the assets, you're not contributing the debt because you plan to finance it with nonrecourse project financing?
Mark A. Snell
Yes, you should think of it that way. Because, yes, we would finance it with nonrecourse project financing and whatever debt we originally incurred. We really financed that facility out of cash flow and current borrowings. It is really -- but if you look at our debt position now, it's actually -- our credit metrics over the five-year planning period really improve.
Follow-up question. Suppose there was a significant impact on U.S. natural gas prices as a result of LNG exports, would you and others clamoring for these exports have to overcome the hurdle of just and reasonable rates?
Mark A. Snell
Well I don't know that we have to overcome the hurdle of just and reasonable rates. I mean the natural gas market has been relatively unregulated pricing market for a long time. But I do think if there was -- could the government -- I will put it this way, could the government revoke export permits that they've given if natural gas prices were to spike to an unusually high level and create problems? I think they probably have that authority. I will tell you though that all of the customers that we're dealing with, all of the customers that we're signing commercial development agreements with, they all will take that risk. They will all pay the tolling fee even if they have revocation of their export permits. So what we're -- I think what most people believe and what most commercial interest believe is that once the permit is granted, if it were to be revoked, it would only be temporary due to some kind of unusual nature. But generally speaking, I think most people are confident that they would ultimately be able to continue to export.
What's the interest per liquefaction at the Costa Azul facility?
Mark A. Snell
Great question. It's actually pretty high. That facility is a little more land constrained, so it's not going to be -- we probably couldn't build as big a facility as we can in Louisiana, but there is some real interest. Even though the extra cost of transporting the gas from, say, Permian or the Rockies into Southern California then down into Mexico would have to be factored in, the closer shipping avenue to Asia is attractive. And so I think if, long-term, these gas prices persist, we will see probably some kind of liquefaction, at least kind of 1 train sort of thing, coming out of Mexico too. It has an interesting group of issues because we do already actually have our U.S. export permit, to export gas to Mexico. So that's not a hurdle. We have to get a permit now from the Mexican government to export gas to other countries. We think that's a doable proposition. But we haven't started on those projects, yet, because our main focus has been to get this underperforming assets, Cameron, up and running and make that work and then we'll turn our attention to Costa Azul.
There's enough for a small metal liquefaction . If you really want to do something bigger you have to increase the pipeline capacity and that would require FERC permits.
Chris Shelton from Millennium Partners. Just one follow-up. Do you expect one customer for each train, kind of the way [indiscernible] has one off taker [ph] for each train or is there a customer big enough size to take 3 trains on their own?
Mark A. Snell
Well, I don't think anybody will -- we're not talking to anybody that will take 3 trains. There are customers that want more than 1. Some of them want to have 1.5. I do think, ultimately, the easiest is to have 1 train per customer. But it's possible that we could have 2 trains with a single customer or we might have 2 trains, 1 customer taking a greater share of the second train than the other. All of those permeations are sort of in discussion.
Got it. And does that also mean the JV could be with multiple parties or is it probably just the one...
Mark A. Snell
I think if probably the JV could have multiple parties that have percentage interest equal to what their -- how much of the train is they're each taking. It's a little bit open for discussion. Some parties, especially ones that want a really small amount of capacity might not want to make a JV investment, others would have to pick up the slack, I think that's left open right now.
Got it. And then just one quick one on generation. Do we know what the tax basis for the generation assets are?
Mark A. Snell
Of course, we do.
Is there somewhere I can look that up?
Mark A. Snell
I don't know. Well, we can get it to you.
We could follow up.
Mark A. Snell
Yes. We'll follow up. I don't know what it is off the top of my head.
Steven D. Davis
Thanks, Mark. We're now going to break for lunch. We will reconvene at 1:00 p.m. Pacific Time. So this ends the webcast. And for those of you in the room, we're going to be in the same room that we're in last night for lunch.
Steven D. Davis
All right, let's begin. I was searching for Hail to the Chief music to introduce our next presenter, I couldn't find it though. So he'll just have to have my welcome. Please welcome, Jeff Martin, President and CEO of Sempra U.S. Gas & Power.
Jeffrey W. Martin
Thank you, Steve. You can obviously tell that a lot of people are having fun with me over the last couple of days. In fact, over the break, there were a couple of investors that said, Jeff, how can [indiscernible] a little bit concerned about it. I said, look, I have a thick skin. No problem. It's all in good fun. So a little bit more of a lighter note, I had several canned jokes regarding Michael Lapides, which I used to roll out every year. And Michael ducks the conference and someone said why don't you just use it on Greg Gordon and Faisel. I said, this won't be the same, right? So I'll hold this.
One thing I'll just say before I start my presentation is we were talking with both Rick and Steve Davis last night. If there's a magic ingredient to running a successful Investor Relations program, it's typically having a management team behind you that enjoys spending time with investors. If you think about the tradition at Sempra, going back to Steve Baum, I think Don Felsinger certainly took that mantle of making sure that we are accessible and engaged with investors. Certainly Debbie and Joe and Mark and the balance of the team have done that.
So when we meet with you in events like this, we have a lot of collective preparation. We look forward to these events. We do road shows throughout the year. We spend time at other conferences. And the fact of the matter is, it makes us better as a management team. So we're very grateful to have all of you here today. And hopefully the conference will live up to your expectations.
The outline for my presentation is very similar to what you've seen from other presentations today. I'm going to be focused on kind of covering all for what we accomplished last year, some of our objectives in 2012 and then just dive right into what the key growth platforms are for the domestic platform.
I like this slide because it really kind of levels out to everyone about notwithstanding how Sempra was organized before this put all of our assets on one sheet of paper allows you to look at it. Well, I think the most important takeaway here is that when I met with this group as a business unit leader 2 years ago, I've set kind of a hallmark in my approach to business will be, having intense focus, and I really focused over the last 2 years in Sempra Generation around a 3-state strategy to have organic growth in renewables, particularly on the solar side. You likewise won't see that type of intensive focus around a 3-state area in the Gulf. So national footprint, 2 growth platforms around renewables, namely wind and solar. And secondly, trying to make sure, as we look at that field of opportunities in the Southeastern part of the United States I'm not really interested in every opportunity. I'm really only interested in those opportunities that can somehow help me unlock the values from our prior investments in the Gulf.
Now let's talk about what happened in 2011. Most of these largely relate to our Power business, but the big deal was when we met last year, I said if we're going to be successful in the Power Markets, it's going to be because we created a differential advantage on the marketing side. So over the last 12 months, we built out a more dynamic marketing team, better collateral materials. We moved closer to customers. Throughout the year, you saw press releases about PPAs being signed. That will continue to be a priority going forward into 2012. But a big part of that success was around our marketing effort to contract our renewables.
On the power side, what's unique is you can't get 15-, 20-, 25-year contracts generally on the gas fossil side. But on the renewable side, you can very rarely get 20 and 25 year contracts. That's certainly is in the wheelhouse of how we think about allocating capital, quality counter parties, long tenured contracts. Our renewable fleets today has an average tenure of close to 22 years.
Secondly, on the natural gas side. Mark and Debbie have touched on this. We've been going through a 3 year process of reducing our exposure to the Western power markets on a merchant basis that included transacting in the last 15 months, selling 2 of our 4 plants, and most importantly, last year contracting 25 years with a team of co-ops and Munis in Arizona on a very good contract for us, which we referred to here as a spurred contract. We have likewise, as Jessie Knight indicated, transferred our El Dorado facility at about $450 of kW to our affiliate utility.
2012 objectives. Moving forward, this is a big construction year for us. So, last year the word was marketing, this year the word is about execution, construction safety and compliance. We're going to double our solar portfolio this year. We're going to double our wind portfolio this year. So you don't move from an average nameplate in wind and solar of about 325 megawatts in December of 2011 to something closer to 750 megawatts by the time that December rolls around. And a big part of that will be the success we've had with our BP relationship. We're building the biggest wind farm in the history of Kansas this year. And we're building the biggest wind farm in the history of Pennsylvania this year. So we've had some notable successes. What I like about the BP relationship is we're more than willing to spend a lot of development capital and make sure that we can monetize our subcost around our solar development. But on the BP side, we're really going outside of our sweet spot in the American Southwest because we have a customer or a partner that thinks about their balance sheet the same way, that thinks about their engineering processes the same way. And I think it's been a great relationship and one that we're very protective of, because we think it will continue to yield a fruitful relationship for us in the future.
On the natural gas side. Mark talked about this as well. But in '12 and '13, we're going to go from about 23 Bcf to 43 Bcf that sits on the Mississippi hub. You'll see more of that with Bay Gas in 2013.
We're also going to continue to add contracts. So, going back to the marketing concept. We'll talk about it later in my presentation. We have a blue chip customer base in the Gulf. Our goal is to upsell that customer base. And we have a growing customer base in the American Southwest. We have 2 PPAs with UniSource Energy. We've got a long term PPA with a spur [ph] group. We will be participating in RFPs, both in Arizona and California, and we're looking to find ways to try to get out on the far curb a little bit with some mid tenure, longer term contracts to add value to our gas fleet.
Let's talk about renewable marketplace. I have a similar slide that talks about what I think is taking place from a structural standpoint in natural gas. The next few slides will focus specifically on renewables. This tend to be a little bit demonstrative, but we're pulling here some data from Wood Mackenzie on the far left hand side. There's no question as you think about that [indiscernible] quilt of state compliance for renewables. 36 states today have laws on their books mandating that a certain percentage of electricity production comes from renewables. Jessie and I talked about, how far along they are in SDG&E. But really, this has been a phenomenon that's been led by the West. So you think about California is a very, very large marketplace of about 65 gigawatts in total county munis. All the munis have to comply. All industrial and utilities have to comply, as well as retail providers. So big opportunity and what you can see here is if you think about this western marketplace, this shows you how much states have moved toward hitting their goals. So remember, I have a relatively small development team, a relatively small marketing team, my goal is not to focus on the 50 states. Going back to my mantra, we want to focus on a very narrow area where we think we have a competitive advantage. And we have a competitive advantage in markets understand. We understand the regulatory framework. All of these customers in Arizona, Nevada and California. We have CEO level relationships. Our goal is to participate in this RFPs, secure contracts and monetize affirmed [ph] development positions.
This is the project that some of you saw last night in the video, this is our Copper Mountain Solar project in the photograph. What you can see here is that we have roughly 100 megawatts of solar in operation end of 2011. As we go through the construction process, you can see this year we have additional construction underway. We will turnkey an additional 100 megawatts of solar at Mesquite this year and a 92 megawatts of solar at our Copper Mountain 2 facility. So just a mere half-mile away from where we hosted the President last week. And we're going to build another 92 megawatts of solar.
So think about this, in 2008, we built 10 megawatts of solar. And then at the end of 2009 going into 2010, we did another 48 megawatts of solar in 1 year, then we did 42 megawatts last year. This year we're going to do 192. So you're going to have over 500 workers in the field at both those sites concurrently. So this is going to preoccupy a lot of my time. A lot of people that worked with me, we are very, very focused in the construction opportunity and delivering these projects.
Last thing, I will I'll try to talk about to Debbie's presentation, as you think about this bottom's up strategic review, which we've talked about a lot is, our goal is to inspire a lot more discipline in terms of how we allocate capital and where we focus our time and attention. And one of the things that came out of that strategic review was, we have the opportunity now where there's a lot of interest in solar. And as PTCs expire at the end of the year, the ITC for solar is extended through 2016. There's even more interest moving towards solar. Our goal now is move our capital decision-making process around solar to a 50-50 structure just like we have for wind. So very capital intensive business. But as you bring in project financing, as you bring in partners, the goal is to make sure that we approach solar on a prospective basis just like we've approached wind in the past.
People ask sometimes about our land position. We get a lot of questions about how many megawatts can you do per acre and so forth? Typically, 1 megawatt will take up between 5 and 7 acres. You can see here that we've got existing land positions. We're not really trying to extend our land position. Our goal is to take what we think is a competitive advantage in the marketplace, where we have some cost in land. We have access to a substation and transmission to key markets and try to monetize that. And as you think about market entry strategies, which Mike Allman was talking about just 3 years ago, we are in a relatively elegant entry into the solar business because most our natural gas fleet had a lot of adjacent land which we needed for water rights. So a lot of these land positions had really been -- some costs have been paid for as part of the natural gas fleet. This has been a competitive advantage for us. And you can see what the future opportunity is. You've got about 5,000 acres of land available for future investment. And you can see in the data table here what that opportunity represents, both in terms of total capacity as you move towards selling down equity and what it means in terms of net capacity.
Talk about Wind briefly. This is a shot of our Cedar Creek facility. In Northeast Colorado, great site, great Wind regime there. Again, this is a 50-50 model. We'll be adding roughly 290 to 300 megawatts of Wind this year into our portfolio. I think that Debbie talked about to, this desire for us to be part of a bigger pie and bring some diversification to our counterparty risk, our technology risk and moving to different markets. This has been a perfect vehicle to do this. The goal is to try to find a way to replicate the success of this model on the Solar side.
There was some reticence on my part to show you this slide. You recall, last year, I took you through an accounting table or pro forma about how you expect to see returns on a hypothetical Solar project. Again, I'll give you the normal caveat. Treat this as a demonstrative-only case. But I did talk about last year why I was personally attracted to the Solar model. I wasn't always a believer in renewables. I think I was one of the original skeptics at Sempra. So I think I'm kind of converted on this. But let me talk about why this is exciting to me. If you start on the far left-hand side, you really spend a very nominal amount of capital to put yourself at risk on the development side. So if you think about land, where there's a ground lease or fee, that's usually a tangible resource that you can resell. But really in terms of joining the permitting and interconnection work, you're really talking about $1 million, $2 million, $3 million at most. Even for something close to in $0.75 billion project. You but you can't build a bridge, a highway, a re-gas terminal, a powerplant and put that few dollars at risk. And as you think about the construction process, you really don't spend those large dollars until you have your long-term hedge in place. So the whole game is making sure that you don't take market risk. You get the PPA of a good counterparty and only at that point, once you have the PPA plus your regulatory approval, then you start spending capital. The capital comes back relatively quickly. We've had projects that comeback in less than 2 years. This one shows a 4-year simple payback. I think this is more than reasonable to expect. But you can see the cliff to what takes place. You see projects, finance the project, bring back your ITC or grant, we've used both in different instances. And then look at our 50% equity sell, you can see that you're payback is relatively short. So you think about a capital intensive business with good returns, we've talked about it on the other slide, this is about north of 20% ROE type of business. And you can look at the type of risk you're taking, we found this very attractive. We will not be the biggest player in American renewables. We will not have the biggest portfolio. My challenge to our team inside of Sempra has always been, let's make sure we have the best financially performing portfolio. So every time you see us launch a project, you need to know that we're very, very focused. Not just on overall nameplate or getting bigger, but making sure we do it in a way we're getting the highest possible return on our capital investment.
Renewable growth, as you think about what happens going forward, you can see how we've stepped into this space since 2008 on a going forward basis. It depends what your starting point is in terms of calculating your CAGR. There's a very high growth rate here in our renewable portfolio. Quality returns, de-risk through partners and project financing. You can see here my reference to a 10-year average ROE of roughly 20%. We feel very, very good about that. I think that's something -- the inside our company that we're very proud of. Again, contract tenders are roughly 22%. What might be a little bit more interesting though is to talk about the pie chart on the right-hand side of this slide. I stood before you last year and said we're going to have 1,000 megawatt, a goal of over a 5-year period of time. We're pleased to be in front of you today, now 12 months later and we're 60% contracted for a new target of 1,400 megawatts. And what's interesting about this is, I'm not just has the target gone up, but instead of last year, we were talking about owning all the solar. That target talks about perspective solar project going to be 50% on the equity side. And secondly, this Wind project we've talked about in Baja over the last 2 years, that's -- we moved in to George's business. So inside of the U.S. Gas and Power plan, there is no incremental wind projects after 2012. I remain optimistic that we might be able to add some, but for planning purposes, we don't have any wind in our portfolio. The wind inside of the greater Sempra businesses, will be captured inside of George's business. So we're pleased that the target has gone up. But it's also gone up with the thought process that we're changing our approach to the capital structure for solar. And we have moved our one large wind project organically over the George Liparidis' unit.
Natural gas market. I'm sure there's lots of questions here. And we can spend time on that during the Q&A process. But I think we are very, very bullish on this large structural trendline that's taking place in America where we expect to see coal displaced by gas. I don't like to think about it in terms of coal-to-gas switching. That's not really the phenomenon. Let me just give you one quick metaphor, again, it's an imperfect one. But if you think back to 2008, we've done some regression analysis. In 2008, the most efficient gas plants in America with gas prices at $13 or $14 and coal prices incrementally lower than they are today, cannot displace the highest heat rate coal plants. Today, the most efficient gas plant at today's gas prices was coal having run up somewhat incrementally since 2008 can displace up to 40% of America's aging coal fleet. Now what does that really mean? It doesn't been that the coal fleet is going away. It just means that their operating at increasing lower capacity factors. And why is that important? Because it's a double whammy. With increased EPA activism, even the decisions announced this year, I mean this week, which we can talk about, what's taking place is, with expectations of higher environmental CapEx, you can't burden those plants at lower capacity factors and expect to be economic. So we expect to see anywhere from 40 to 60 gigawatts of coal displaced in America. And one of the things we find most exciting is the highest growth rate for natural gas in our analysis will be in the American Southeast. And we're going to talk about that more in a couple slides.
Here you'll see the disposition of our assets in the Southeast. You recall me saying that we have a relatively focused effort. We have a small distribution business at roughly 100,000 customers at [indiscernible] gas. We've got a growing storage position. You can also see that we're calling on the Slide LA Storage. For those of you who have come [ph] historically been in Sempra, you can remember that we have a Liberty Gas Storage facility down there that have a northern field and a southern field. This is in reference to the southern field. So you've got roughly 19 Bcf of pre-existing caverns there that only need to be dewatered. And why this is important is, Mark talked a little bit about the large opportunity of cash flows associated with launch in the liquefaction business. And Mark also talked about that our model was somewhat different than the marketplace. We didn't want to take commodity risk if we go down that path. What we would like to do is set it up as a tolling arrangement, much like you think about for a power plant. So if people are going to participate at that plant and process gas, they've got to do 2 things. They've got to bring pipeline quality gas and they've got to bring it pro rata daily. So you have to feed it just like a refinery. So having storage and proximity, either to [indiscernible] facility or our facility or other facilities is absolutely a competitive advantage. Some of those signed up for a 20-year tolling agreement, they want to be 1 pipe away or 2 pipes away of their gas. Or they will make sure that they have an uninterruptible source in geographic proximity with no basis, right? The LA Storage is certainly part of the picture. So as you think about the potential uplift for free cash flow associated with liquefaction, there is a second order effect of the benefit of liquefaction to LA Storage as well as our Cameron Pipeline. And the ability to actually contract other storage facilities.
By clicking this, it reminds me to make a comment that I mentioned earlier that we have blue-chip customer base. When you think about just our storage facilities, you can take every American Electric Power Company from Virginia to Florida to Mississippi, and even some contracts into Texas. So you can go right down the list. 15 blue chip companies: Virginia Power, Carolina Light and Power, Duke Power, Georgia Power, Mississippi Power, Alabama Power, Florida Power and Light, Tampa Electric, the Orlando municipal, they're all customers in our storage facility. So remember, the original pieces of the investment when we bought energy South-wise, we want to get closer to the Eastern seaboard market because we saw that's where the long-term natural gas growth opportunity is. So what you see taking place here is our natural gas investments are really located around Louisiana, Mississippi and Alabama. But the power opportunities are on the Eastern seaboard and those are the customers that are contracting for storage. If they want to be able to balance loads, make sure they can accommodate growth. So I think, over time, the goal here is up sell those customers. They're going to have bigger needs for natural gas and ratable supplies from storage in the future than they have in the past
Natural gas storage. We've been through these numbers once before but it shows you the 23 Bcf that we have in operation today. It shows you across a 24-month period of time. We're going to migrate that up to roughly 43 Bcf. At the bottom here, you can, again, see the reference to LA Storage. The reason we have kind of the spaghetti bowl of lines here is to show that the most important thing is that all of these locations, most importantly, Bay Gas, is, on the right-hand side of Transco 85, this has been a traditional bottleneck in the Southeast. Bay Gas, there's no question about it. A locationally advantaged facility. And even though that we're not expecting to have the same robust financial performance in 2012 from storage, the original thesis remains the same. These are high-quality assets in locationally-advantaged areas where structural changes to the core is taking place. More petrochemical plants, potential for liquefaction, more renewables, particularly on the Texas side, and most importantly, the prospect of natural gas plants being built along the eastern states as coal is displaced.
So as we start winding down the presentation, quick summary view. The West, we have our head down. Small team focused on margin and getting contracts and a very strong construction operation, where we're working with our EPC contractors on the field to bring the projects on time and under budget. Ironically, when you are in the flow through method of accounting, which we all talked about over the last couple of years, making 92 Bcf versus 88 -- 92 megawatts versus 88 megawatts is a big deal, right? So you're less exposed to whether you're at 100 versus 90 in terms of your construction program. But I think what's important is we're going to basically double the solar and wind portfolio that requires construction. BP's engaged. We're engaged. This is a big year for us.
Southeast, again, our goal is to grow and up sell the customer base, integrate that with Power opportunities in the Southeast. It's not beyond uphill [ph] , that we can participate in building plants. Our focus, if we were to get involved in natural gas generation in Southeast, is not selling to the large industrial and utilities. There are a lot of municipals and co-ops in the Southeast. Mark talked about the Hattiesburg opportunity. The reason that was important to us, in terms of buying a small utility there, and that will continue to be something that we'll look at. Again, would we do that with a 5-year contract, absolutely not. We're not going to participate in anything inside the U.S. gas and power business in terms of new capital deployment without 20-year contracts. People that had our system to Cameron Pipeline to support liquefaction, check the box, 20-year contract. If you launch LA Storage, check the box. That customers want to match up that storage facility with their liquefaction commitment. So this is really about a long-term contract in business. We're not in the business of taking market risk. We're in the business of making sure that we have long-term certainty of cash flows.
Now, we opted this year to show you more information, this goes to the issue of how you value both the natural gas side as well as the renewable side. Here you see an adjusted EBITDA slide that shows opportunity to roughly double our EBITDA over the 5-year period to 2016. There's been a lot of discussion about tax credits. Joe is more than prepared to go into great detail with you during his presentation about how we think about it. But our goal here really was to say, as you think about this tax credit, that's cash -- that's part of the cash flow equation, these are the years that those tax credits are allocated to us. The timing of when those tax credits are actually consumed will depend on a number of factors.
From an earnings standpoint, you can see that once we made this accounting adjustment from flow-through deferral, had had a big impact on overall generation contributions, likewise, the dropoff of the California Department Water Resources contract which ended in Q3 of last year, that had a huge impact on our earnings profile. What I'm most excited about, however, is, look at the growth between 2012 and 2013. That's number one function of what we're doing on our renewable build-out this year. Number two, you've heard us talk about, on prior calls, the small boil-off gas re-liquefaction capability at Cameron. So instead of having boil-off gas and having to buy maintenance cargoes, it's going to be a big uplift for us between 2012 and 2013 to bring that online. So we feel very good about the visibility of our growth from '12 to '13. And you can see in the 2016 timeframe, we have solid growth as well. When you got out to 2016, you're probably looking at a mix of our investments of roughly 55% renewables, 45% contribution from natural gas side.
This is my wrap up slide and I'll open up for questions. To keep the conversation moving along.
2012, this shows you who we are in '12 versus who we are in 2016. It's worth going through this. Obviously, we have solid earnings growth rate around our expectation of long-term contracts. You can see that in 2012, we're somewhat geographically dispersed. There's an intense focus around what we can do with a competitive advantage in the Southwest and the Southeast. As there's been discussions around MLP, that is also kind of a unifying transaction, because the less focus to where that asset sits, it's more focused on the quality of the cash flows that tends to, again, centrifuge our investments around that vehicle.
You can see that we've got 325 megawatts of operating wind and solar. We think 2016 is very achievable. So by the end of this year, I'll be sitting at about 750 megawatts of wind and solar. You've got 60% of that 1400 megawatts contracted today. Again, head down, get close to the customers, credit competitive advantage in a compelling value proposition of why we're best positioned to deliver high-quality renewable project.
We talked about the strategic review where we moved have from a 50-50 approach to our capital structure in wind, but also taken a like approach to solar. We've talked about underperforming assets. By 2016, we're going to top rate this. We're not in the business of fire selling something into a depressed market environment, but there's a lot of intention, even painful attention of making sure that we're doing the right things everyday in the marketplace to add contracts both to our natural gas storage facilities and to the 2 plants we have remaining on natural gas fleet.
Link it between assets. Again, I'll talk about the field of opportunities in the Southeast. What we're really looking at is not all those opportunities. There's opportunities like where you can either participate in a distribution business or a power opportunity or something that actually touches our storage, our prior investments. And lastly, just to put a nail in the coffin, we are not going to be in the merchant power business in the west. We've shown you our track record in the last 15 months where we've transacted on the 2 plants. The plants that in our view have the highest option value in the marketplace, one at Palo and one in the ST marketplace. As the carbon market unfolds, there's a lot of option value around that. Those are 2 remaining plants and our goal is to add value there and make sure that we manage an excess -- an excess that all of our shareholders can be proud of. Again, as a final comment before question and answers, we've assembled a fantastic team in the U.S. gas and power business. There's a lot of excitement about what we're doing. I think we're on the right side of the policy arguments and I think that we have a lot of confidence that we can deliver the numbers we've put forth today. With that, I'll stop and open it up to questions and answers.
Jeff, question on the tax credits, the BTCs, ITCs. That slide, does that show the cash received in each of the years? Or the amount that flows through on the income statement?
Jeffrey W. Martin
That shows what's allocated to us that year. It doesn't show the timing of when that is actually converted to cash.
So is that the amount that increases net income by?
Jeffrey W. Martin
So when you say allocated, what do you mean?
Jeffrey W. Martin
So when you put a project into operation, you've earned that tax credit. If you don't have tax liabilities to match it off with, you can't use it in the year in which you allocated the tax credit. You can only use it when you have a tax capacity to utilize it, right?
Okay, I understand. But it is a cash number that you may not necessarily receive from IRS but that's a cash book -- cash bank number?
Michael, let me help him out. For the wind credits, production tax credits, that's going in earnings. For Solar, as you know, we just changed our accounting methods, it's not going in earnings. So that's why -- but some of those are investment tax credits, not production tax credits.
Jeffrey W. Martin
Investment tax credits, we're generating them. That's the year we're generating them in. You can discount them to when you think we're going to use them. In my presentation of when that might be. I'll be gentle on the discounts coming from treasury, and it's only a few years away.
Greg Gordon - ISI Group Inc., Research Division
Greg Gordon. Just to be clear, some of these tax benefits are coming in the form of cash in that year and some are being booked as deferred tax assets in that year and then will be consumed.
Jeffrey W. Martin
Greg Gordon - ISI Group Inc., Research Division
When you have, like, the appetite to...
Jeffrey W. Martin
Greg Gordon - ISI Group Inc., Research Division
Okay. Great. So follow-up question on the gas business. It seems -- to summarize what you're saying around sort of the potential future improvement in returns around some of the assets, mainly storage which it looks to me if I look at the stat supplement, lost money in 2011. It really hinges on 2 things. One, coal-to-gas switching in the Southeast over time driving more demand and getting an LNG export hub in the Gulf. Those 2 things happen, those assets increase demonstrably in value and bottom line is you don't want to sell them here at the bottom when those 2 sort of potentials exist, is that fair?
Jeffrey W. Martin
That's correct. And with the cash flow that you are producing now, Greg, remember you're going from 20 Bcf in 2011, right? To 43 Bcf, right? You've got more capacity. Even though the market prices are depressed, you're going to benefit from having more capacity to move in the marketplace. But your summary is correct. Winfried?
Jeff, are the utilized renewables tax credits included in the adjusted EBITDA?
Jeffrey W. Martin
Okay. Other question I have is on your model solar project. Have you a similar model wind project that you could show us?
Jeffrey W. Martin
Not readily available. But the goal is really to show you that as you think about renewables, and you think about project financing, and you think about whether using the grant or the ITC, for example, you're using the grant on the Auwahi Wind project. I was really just trying to show you that in terms of a capital-intensive business, you're not putting a lot of capital at risk until you have a hedge. And that your cash comes back to you relatively quickly. So you're not sitting out there for 8 or 9 or 10 years which you potentially could even in a regulated investment.
For your operating solar plants, are you expecting to receive payback under 4 years, 4 years or more than 4 years?
Jeffrey W. Martin
Yes. I'm not going to give a generalization. I think we've seen them shorter and we've seen them longer. So I'm not thinking -- it is reasonable to believe that we're going to have simple paybacks across our renewable portfolio between 3 and 5 years, wind and solar, yes.
No, I was just confirming my question to Copper Mountain 1 and Mesquite 1, whether you expect to achieve 4 years of better or 4 years of worse.
Jeffrey W. Martin
And I'm going to confine my answer to the, in general, in wind and solar projects, you expect to have your money return in 3 to 5 years. That's inclusive of all of them, right?
Leslie Rich - J.P. Morgan Asset Management, Inc.
Can you elaborate on what you said about boil-off gas at Cameron? So I think previously because of low utilization, you had to buy cargoes, basically, just to run them through. And what you said you made some sort of technological upgrades so that you no longer have to do that?
Jeffrey W. Martin
Right. Over the last 15 months, we've started a capital investment and a relook [ph] capability. So you really have a very small plant that can really just take your boil-off gas, Leslie, and basically use it, put it back in the tank. That really relieves you from having to go in the marketplace and replace it. Because if you don't, with that boil-off gas moving, the gas inside the tank gets hotter. So it really is something that had a great short, again, similar to his question, very short return of capital for the overall simple payback. And it's something that will be in place before the end of this year. The benefit of which is really enjoyed at 2013.
If there are any other questions, there's one more here. And then we'll move to George.
Andy Stone from Tufton Oceanic Energy found in London. Could you expand on the developments that you've seen, the evolution in the solar market and the technologies? Which technologies you expect to use going forward, the cost reduction that's been achieved? And also on the wind side, levelized cost of energy? And how you see that sort of evolving in the future?
Jeffrey W. Martin
Well, there's a lot of question there and I'll try to answer as many as I can. I'll harken back to Debbie's point, which is really kind of our mantra on the renewable side it is, we want to participate in a wider basket of projects with multiple technologies, multiple counterparties. We think that's the right way to go. So it's fundamentally, as a company, not just in our renewables business but including in our utilities. We have traditionally held ourselves out to be technology agnostic. So we're looking for the best fit, lowest-cost opportunities that we think will fit into our portfolio. But I will talk a little bit about the cost side of wind and solar. Over the last 3 to 4 years, we've seen tremendous gains in the cost advantage around solar. And at first they can't take credit for it, Mike Allman was at the Helm [ph] at that time, but they made 2 very [indiscernible] decisions: One was to avoid solar thermal and focus on photovoltaics, because they believe it will come down the cost curve the fastest. The great clarion call. Secondly, they want to avoid really public lands because there's a lot of complexity associated with permitting there and focused on private land utilization. Both of those 2 decisions gave us competitive advantage in solar. In terms of the cost side, you've seen price reductions in panels over the last 2 to 3 years between 30% and 40%. The most interesting thing, too, is you're also seeing 10% to 15% cost reduction on the balance of system. So as panels become more efficient, you're using less land and you're also using less balance of system plant. So the solar side has been absolutely fascinating. What actually takes -- causes a little bit of pause however is, there's been 2 things occur with increased manufacturing and increased efficiency, we've also had increased inventory build. So what's going to be interesting to see, as we work through historic inventory builds globally, what does that do to prices? So people think that prices will decline in a straight line. It may not decline in a straight line. You may have a lot of dead soldiers out there on the O&M side, but the smaller number of better balance sheet players surviving, that gives them a little bit more pricing power. So over time, I think there's no question that solar prices will continue to decline. But it probably will not be a straight line. I think what's important for us is we're not going to try to be out there, competing with people that are taking overly aggressive positions, unhedged on their hard cost in 16, 17 and 18. Our goal is to make sure that we're having agreements with our utility counterparties. They're agreements that we can stand behind and deliver. On the wind side, we've seen some aggressive movement and you've seen kind of the rise and fall of turbine prices over the last 5 or 10 years. We've seen, on a subsidized basis, PPAs in the marketplace for wind in places of good wind regime like the Midwest, anywhere from $25 to $35 a megawatt hour. And that's roughly half the price of a new combined cycle plant that runs in a 60% capacity factor. So wind, subsidized, is highly competitive to natural gas in good wind regime environments. Now, those prices change dramatically. California doesn't have that type of wind. You're looking at 30% or 36% capacity factor wind here. But in general, once you remove the PTC, if it were to go away, then you'll see, even in the best wind regimes, still some competition from wind and natural gas. The most important phenomenon I'll leave you with is, that if the PTC does expire on day one, solar becomes a very big adversary for wind because solar is subsidized -- its generally in the same ballpark. Based on some of the feedback we've been getting from regulators. One last question, [indiscernible].
[indiscernible] In 2016, you mentioned that natural gas will be about 45% of your earnings. Could you give us a sense as to how much of that is related to natural gas plants versus the storage and [indiscernible] asset?
Jeffrey W. Martin
I'll let you back into that. I mean, Mark did what we don't normally do, which is he gave us some subsegment guidance in terms of what the gas fleet would do. Mark put out $150 million EBITDA number for the gas fleet. You can kind of partially what that might be in terms of our pipelines. Remember we've got one distribution business today. We're looking to close on our second distribution business in the second quarter as well as our storage businesses. But there's no question, I think, that the big opportunity in the Southeast is that we are participating in different assets with different customers on top of a place where there's going to be a lot of structural change, which I think Greg Gordon summarized correctly.
Next, I have the pleasure of introducing someone I had a chance to work with for a long period of time. George has been with the company for close to 30 years. He has worked both at SDG&E as well as a variety of our unregulated businesses. I'm the beneficiary of a lot of his investments here in the United States. And I think George has certainly performed well on the international side. And he'll take you through how he plan to grow our international footprint.
George S. Liparidis
Thank you, Jeff. Good afternoon. It's a pleasure to be here. I'm going to discuss Sempra International business, which is, as this presentation is concerned, is assets in Mexico, Peru and Chile.
The outline of the presentation is to talk about the accomplishments from last year. I'll give you a good understanding of our assets in South America and in Mexico. And I'd like to spend a fair amount of time in doing that, because it's always something that's evolving and something that has grown over the past few years. I want to make sure you have an appreciation of what we manage and what we own in these countries. Of course I'll talk about the opportunities for growth that we have, and after, give you the forecast that we have for the outlook of earnings. And after my presentation, Eduardo Pawluszek is going to do a presentation on the regulatory process in Chile and Peru, which of course, is a key component to the success that we've had with these investments in the past 12 or 13 years. And after Eduardo's presentation, we are going to bring up Mile Cacic, who is the CEO of our Peruvian business and Francisco Mualim, who is the CEO of our Chilean business, and they're going to participate in the Q&A, give you a chance if you want to have some questions with them directly about their businesses and about those countries, so you can have a better appreciation of what we're doing in Chile and Peru.
2011 accomplishments. Of course, you know we closed the acquisition of the -- of a controlling interest of what we had in Chile and Peru. This was $775 million that we paid to buy out our partner. This was net of the $100 million that was already in the business that we acquired. The operations have been fully integrated this past year. And things are running very smoothly. We also started construction of a 98-megawatt hydro plant in Peru, the $155 million investment. This is going to start operations in 2014. It's important that it's not only a very valuable investment for us, but it also establishes our Peruvian company as a generator under the regulatory rules in Peru to participate in future capacity additions in that country. And you'll see later with some of the other slides that I have, Peru is a country that requires a lot of new generation capacity to keep up with low reserve margins and a high growth rate to the economy. Also we consolidated our Mexican assets into a single company. We had in the past, different business units operating in Mexico. Now all the Mexican assets are going to be part of one organization and that includes the LNG, the power plants, the wind project that you heard Jeff mention. And that organization is going to establish a model that's very much towards -- you heard earlier, we want to replicate the model that we have in Peru where we have strong local management, responsibility for getting things done on the ground, have local investors and the appropriate oversight and tie-ins with Sempra in San Diego.
This is kind of a busy slide, so I like to start by the -- with the very top there that we want to continue to build on our past success. I think by any measure, these investments have been very valuable to our shareholders. All -- you look at the financial results that we have achieved in all 3 of these countries since we've been in these countries, which has been a long time. And you look at what the earnings and the cash that we have generated, it's very impressive. On top of that, if you look at all the assets that we have, they are tangible data points in the market that tell you what we own has a market value that is higher than what we've put into business. I think that's a very positive outcome, and it's something that we can build on because now, we have a lot of momentum in all 3 of these countries.
The other part is to say that what we're doing in International is complementary to Sempra's portfolio strategy. There has been some objections in the past about how International, how utilities and pipeline companies in Mexico and Chile tie in to what Sempra is doing being a San Diego company. Well, one other way is to say it is operationally, we think there's a lot of tie-ins, for example, we have 5 interconnections in Mexico that tie into the U.S. gas system. But also now, with the new cash strategy that we have and the new dividend policy that we have, these assets very well tie in to what Sempra is trying to do in the U.S., and you've heard the comments that Debbie made, and I think Joe is going to expand on that a little bit more. But we have assets that are fully built generating earnings and cash that we can now repatriate on a very efficient basis back in the U.S. to support what our portfolio strategy is. And then, the third part of the slide is, I'd like to summarize that we're in the right place -- we're in the business of providing electricity and natural gas, and what we look for is economies that are growing and require a lot of infrastructure. And in all of these 3 countries, we're in the right place. We have a high GDP growth, and I'll show you more of this information. We have low reserve margins. We have, just like in the U.S., a need to upgrade existing infrastructure. In the case of Chile and Mexico, there's a lot of momentum to do fuel switching from oil to natural gas. And we have these countries that we're invested in, export-heavy economies that are tied into free trade agreements that include South America and the U.S. So I think we're at the right place at the right time, obviously.
We -- and now we have a proven track record. We've been in Mexico for over 20 years. We've been in Chile and Peru for 13 years. We have experience with multiple regulatory cycles. We've gone through several elections and our businesses continued to flourish. And you've got to remember, what we do is to provide basic services. So as long as we do it right and we do it in an efficient manner, the government, the regulator is our ally. And these countries have regulations because of all the needs that they have that attract -- they want to attract more capital. It's -- what Mike Allman was saying later, they have regulations that want to entice investors to put more money into these countries and grow their economy.
And then at the very right-hand side, we're going to do everything. We're going to execute on a lot of these opportunities by using existing resources. We have top-notch companies, and I'll provide more information in Chile and Peru. In Mexico, we're one of the largest private investors, #1 in the energy market. We have a privileged JV with Pemex, which is the largest energy provider in Mexico. And most importantly, in all 3 of these areas, we have under-leveraged balance sheets, very little debt as I'll show you -- or no debt, which would allow us to continue to grow these companies and support the dividend policy that Sempra is going to implement. So a lot of room to use the resources that we have to achieve the growth that we're forecasting.
Compared to the macroeconomic, I think the first thing I want is say about this slide, we took a great care in putting a lot of footnotes because I want to make sure that we don't overstate the 2 points that I want to make here. And I think they're well supported by any data that you look at. There's always been a concern about political risks in these countries because most of us that are my age remember what happened in the 80s or in the past with these economies. And I think that has totally changed. The economies are very stable. As you can see by the sovereign debt ratings, if you see their fiscal balances, I mean they're like the envy of what's going on in the world right now in terms of running deficits, about how debt -- how much debt they have outstanding. So they're very sound economies and that has allowed things to stabilize, and the overall standard of living in these countries to improve.
The other thing that I want to point out in this slide is we've done this statistics about how many people in the -- reside in these countries and how much installed megawatt capacity they have. And we try to compare it with the United States because that's something that we're very familiar with. And what you see with that ratio, we used this ratio of megawatt capacity installed for 1,000 people in that country, and you can see these ratios are so much lower than where the United States is right now. In the case of Peru, 0.24, it's less than 10% of what it is in the United States. So it's a picture that's very positive from the standpoint as these economies grow, and there's more wealth in these countries. We're in the right business. We're in the business of providing electricity and natural gas, and it will naturally drive growth in these businesses. And on top of that, and you'll see this in Eduardo's presentation, there's a regulatory model that rewards you for being an efficient operator and capturing the value of growth. It's not about how much investment you're putting into business. It's how much growth you're getting and how efficiently you serve that growth.
A little bit more detail about Sempra Mexico operations. One of the things that you see by looking at this chart is we've done a lot of things in Mexico. We have an LNG re-gas facility. We have a combined cycle power plant, used to be part of Jeff's business. We have natural gas pipelines that we built mostly for our LNG business and our Power Plant business. We're into the Propane business through the joint venture that we have with Pemex. And we have a Natural Gas Distribution business in 3 locations in the northern part of Mexico.
I mentioned the privileged position that we have in having a lot of assets concentrated in the border region and the interconnectivity we have with U.S. gas market, and we have the Pemex joint venture. That's important to us because it allows us to work with the biggest energy player in Mexico and have a view, and have a privileged position of identifying and investing in projects that wouldn't necessarily be available to other competitors that we have in Mexico.
This is a map of the Mexican assets. Just to amplify the point that I made, initially, you saw we made a lot of investments along the U.S./Mexico border. That worked out very well for us as we have increased our scale, as we've gotten into these JV with Pemex. You can see we're moving to other parts of Mexico. And one of the things I want to point out about this map, and I'll talk about it a little bit later on in the presentation. This part of Mexico has no natural gas -- they're very little here. But all this area is being fueled for generations, heating, et cetera, by oil still. All the gas that Pemex has comes from here and it's interconnected into Texas this year here. So this incredible opportunity in Mexico right now, given the spreads that you saw between oil and gas, to gasify this part of Mexico and convert a lot of generation that's burning oil to natural gas. CFE, which is the national power provider in Mexico is, over the next 12 months, is going to run 12 -- 5 different bids for about 1,200 miles of new pipeline capacity in order to do those conversions, we think we're very well positioned to work with CFE. They're already a customer of ours right now in Baja California and in Chihuahua. So we think we're in very good position to capture some of those new opportunities.
Luz del Sur is our Peruvian company. I have a couple of pictures there, one is the financial district of Lima where the Luz del Sur headquarters are at, the other is the location of the service territory in Peru that we have. Luz del Sur serves most of central and southern Lima, which includes the financial and commercial districts, the primo territory in the Peruvian distribution market. It has over 930,000 customers, meters. It's a brand name company, was named one of the top 20 Peruvian companies by S&P. It has 20% of its stock traded in the local stock exchange. The current market cap of Luz del Sur is slightly over $1.3 billion. And you heard earlier, this is something that's very attractive to us, and not only we have local investors involved with us in doing this project, but it also gives us a marker for -- to objectively measure what we have done in each one of these countries. $230 million of local debt rated AAA in the local market, you can see it's a very under-leveraged company. We have started this new hydro plant that's in construction. You can see where it's located over there to the right, it's run-of-river plant, very low risk, very well received by the government and the community. And then, the other thing that we have achieved if you look at the last 5 years, our company has tracked what the Peruvian economy has done, 15% compound growth in earnings over the last 5 years.
So in summary, Luz del Sur is a great company in a great service territory. One of the great statistics that I heard about Lima, you saw those earlier numbers about GDP per capita in Peru, and they tend to be lower than the other countries that we do businesses, but if you look at the GDP per capita in the city of Lima, it's 3x the national average. So it tells you that kind of service territory that we have and the kind of economic activity that Luz del Sur is involved in.
So Chilquinta Energía is also an electric distribution company. It serves the fifth region in Chile, which includes our operations in Viña del Mar. It's -- it has over 610,000 meters. It has received very high ratings on customer satisfaction for a distribution company in Chile. It's among one of the most efficient operators in the region as recognized through the regulatory process, and you'll hear more about the regulatory process later. Again, $300 million of debt rated AA in the local market, 12% compounded growth in earnings the last 5 years.
Again, I think a very nice picture of Valparaiso that kind of gives you a flavor of the service territory in a very, I would say, productive environment. The fifth region is one of the areas that has a lot of agricultural lands in Chile and is also home to a lot of winegrowers in Chile. And for those of you that are familiar with Chilean wines, a lot of wine production in our service territory. And other feature that our service territory has that we like is like the fifth region tends to be the second most dense population outside the capital city of Santiago. So even though Chile is a very long and dispersed geography, the region that we are at is in the center of the hub activity other than the city of what goes on in Chile. It's also home of the -- where the re-gas facility is in Chile, so there is a -- some tie to the other business that we do.
Growth opportunities. Let me start out with Mexico and reiterate the drivers. We have natural gas and electricity demand in the country. We have fuel switching, and we have system upgrades and infrastructure modernization in Pemex and CFE, the opportunities for us that we're going to act on in the next 5 years. The Greenfield gas pipelines that I've talked about, are going to be big in Northwest Mexico. The other one is continued development of our Energía Juárez wind facility, that right now, we're going to do the first 150-megawatt, but there's an opportunity to do another 1,000 megawatts in that side, and we think we cannot only sell to the U.S., but there's a strong interest in Mexico to have some renewables come from power producers. The projects to the Pemex joint venture, the best thing about that is our privileged position in having to have negotiations with a customer. These are projects where we, on a 50-50 basis, we co-invest with Pemex. And Pemex is the sole off-taker for 20 years, dollar-based contracts indexed inflation, doesn't get more in line with what Sempra's model is and how they want to do infrastructure.
And then, it was mentioned the Costa Azul gas exports for Asian markets is a possibility. There's strong market interest of course from the Asian market to do something in Mexico. Again, Cameron is our priority, and we will deal with our market interest in due time.
In Peru, the drivers: High economic growth, low reserve margins, 6% to 8%, that's very low for those of us that have grown up other than when we went through a crisis. I mean, typically you want to see those numbers around 25%, maybe more. There's opportunities in addition to the hydro plant that we're building now to do more hydro plant in the same location that our existing facility is going to be. And the opportunity there is not only that we have great resources. And I don't know -- you can do the calculation $155 million for 98, probably a little bit more than 98 megawatts of hydro. That's $1,500 of kW for hydro. I don't know that in my career, that I've seen numbers like that for a generation project. And there's opportunities like that in -- that we have identified in Peru and our challenge is to permit them and to sell them forward to customers so we're fully hedged when we do this stuff. But the resources are there, they just want the capital and the know-how. And now that we have developed this expertise, we developed the project managers, the commercial people to do these hydro projects, we're in a position where we can be very competitive relative to the competition.
Chile. Chile requires incremental generation. It has high energy prices because they're pricing their generation of LNG in oil and diesel, so very high prices on the margin. So there's opportunities to do even renewable projects because the prices are so high. There's also a lot of reliability projects in the transmission system. If you see the way the country shapes, you can see that it's a transmission planner's nightmare to try to provide reliability on a country that looks like a long cigar. There are going to be several transmission bids that are run by the government. We're going to participate in those transmission bids. We're looking to acquire some smaller distribution companies. There's a lot of, what I would call, the equivalent of municipal or locally owned distribution companies around Chile that have 40,000 to 50,000 meters that we have an opportunity to acquire.
It's very competitive in Chile right now. People are willing to enter and do some aggressive acquisitions. But we think we can provide some synergies to these operations, so we're in a good position to execute, I think, Greenfield generation projects. Primarily we've looked at renewables because it's a good way to leverage the knowledge and the capabilities we have in the U.S. in Chile.
Sempra outlook. I guess I'll have to quote Yogi Berra here, "It's hard to make predictions, especially about the future." So this is our 5-year forecast. It's a -- you can see very strong earnings in 2012, $305 million to $330 million. There's a natural growth to this earnings profile that's going to come from organic growth that we're seeing in the electric distribution companies. There's some distinct projects that are in the plan, I mentioned them earlier: The hydro plant in Peru, the first phase of the wind project in Mexico, and we're building this propane terminal in Mexico through the Pemex JV and most projects that are in there. And we're looking to identify more opportunities that are going to go from the previous page to being real numbers in this forecast. You can see the capital investment that's required for this. It's primarily driven by the ongoing operations that we have. The big distinct projects again are the 3 that I've mentioned, so that's the amount of capital, a very good earnings profile and I'll summarize the expectations here.
We have a strong presence in all the 3 of these countries in a stable regulatory framework and robust economic growth. I think that is the cornerstone of our story, and this is what we really believe and we've lived in now for several years. The investments are complementary to Sempra's investment portfolio. The growth opportunities will be funded by local capital, by the local balance sheet. So Sempra, after we executed in our dividend policy, still has the ability to execute on growth through the existing resources on the ground. And we've had predictable financial results through reliable operations and expect this profile that I showed earlier, 8% to 9% growth over the 5-year period.
I would like to hold off on the questions because I'm going to introduce Eduardo Pawluszek, and he is going to discuss the regulatory model in Chile and Peru. Eduardo has been with the company just under a year. He was part of the team of our partner, AEI, when we acquired the Chilean and Peruvian operations. So he was a very easy person to bring in and enhance our capability to manage these assets in South America. And Eduardo, go ahead.
Thank you, George. Thank you, and good afternoon, everyone. The objective of my presentation will be to provide a brief presentation on the description of the regulatory framework existing in Peru and Chile for our utilities as the system is different from what you are used to see in the California utility of Sempra. And I have to say that the improvement in these credit risk profiles of countries where we are jointly with efficient operations that we are running to grow, that George has described. And stable and very predictable regulatory framework has been the key for Sempra's long-term successful in South America.
The regulatory rules have been in Chile and Peru for a long time, 31 years in Chile, 18 years in Peru. Chile has been the pioneer in the region and after that, a similar system has been adopted by Columbia, by Peru, obviously. But to a certain extent, by Brazil and other Central American countries. So that's been very, very, very successful. And really in 31 years, we have seen central-left government, central-right, very, very many, many changes. And this regulatory system hasn't changed, has not been touched. Why? Because it works. Because it works and the system creates a foundation for the -- for attract foreign investment and supports the growth and the GDP evolution of these countries for a long time. So I mean, this has been one of the keys and one of the answers on why this system has been so successful. The system itself clearly is divided between Generation, Transmission and Distribution. And Generation is open to competition, while Transmission and Distribution are regulated as they are natural and monopoly.
In spite of this division, in fact, the system allows, to a certain extent, to vertical integration. And George has mentioned our power project in Peru, and we are working on other business segments in Chile, looking for business opportunities. And we are -- we know these countries very, very well. We have people and geographical presence in the country, and we have a balance sheet to support new business opportunities. So we are looking for growth in the region in this to a certain extent, vertical integration using the synergies that we can get with our existing business.
Finally, the distribution tariff are being regulated or discussed with the regulator every 4 years in a very interactive relationship between the distribution companies and the CNE in Chile or [indiscernible] in Peru. In fact, the current cycle for Chilquinta is viable until November this year, and the current system cycle -- regulatory cycle will be for Luz del Sur until the end of next year.
The tariff that most of our -- that our customers we serve is spread between the energy cost, the transmission fee and the Distribution Value Added. The -- in terms of energy, there is a full pass-through of the energy cost to the final consumer, so our utilities are not taking any risk on the fluctuation of energy costs in Chile and Peru. How the tariff we set in process works? I mean, as of mentioned, it's a very interactive process between distribution companies under regulator, that of an initial step, provide all the technical information through the regulator, and based on that technical information, the regulator creates different typical areas, which try to group the different distribution companies with similar characteristics in terms of density, how many customers there is per kilometer of geography and other additional parameters. Based on this -- or for each one of these typical areas, the regulator builds a model company, which is a theoretical company, which will be the most efficient provider for that demand exist in year before the analysis is done. So based on that and after the construction of this model company, all the assets required to provide that service in a very efficient way are being valued at New Replacement Value. And after this process is done and the assets required for this efficient model company are being valued, clearly, the old typical and efficient administrative and O&M expenses have been included. They are factored into the model as well as the reasonable level of energy losses that you can expect for that typical area.
Once this process is completed, the amount of revenue required in order to provide to all these costs is being tax-related and supply to the year, for the previous year for real demand of each of the distribution companies were in the typical area. So this is how the process worked and clearly has very significant difference from what you have seen in the U.S. But we provide -- we really are convinced that for a growing economy, for a framework, where the country and the energy demand is growing year after year, this is a regular system that provides more benefits.
After all this calculation of the new tariff to be applicable for the next 4 years is being done, the regulator runs a test in order to confirm that the new tariff is providing a reasonable return to the whole industry in the case of Chile and for each one of the typical areas in the case of Peru. So the global return for the industry or the typical area should be in a certain range of 6%, 14% (sic) [6% to 14%] in the Chilean case and 8%, 16% (sic) [8% to 16%] in the Peruvian case.
Honestly, this calculation has been work in each one of the tariff setting and the reason for that is because it's done at the same time that the tariff for each one of the typical area of companies is defined. So at the end of the day, the process is adjusted to be sure that the global result is within the defined range for that group of companies.
In addition to this, every full year tariff were set in process, the tariff of our Distribution business is being adjusted on a monthly basis in the case of Chile and when a change more than 1.5% in the case of Peru. You can see there on the screen, which are the different components of this adjustment that at the end of the date, is mainly focused on local inflation. If we believe that in the medium term, local inflation is translated into devaluation or any devaluation is translated into a local inflation in each one of the countries, this monthly adjustment provides for a full protection for our revenue for any FX fluctuation within the countries.
The last point that I want to make into this slide is the composition of the residential tariff. You can see that the main components are guaranteed cost of Transmission and the Distribution, where there's more ways in the case of Generation, in the case of Chile. You have -- have been mentioned before that Chile has no local natural gas reserves and have no crude oil reserves. So most of the components are based on liquids and other more expensive fuels for the generation industry, and on the other hand, in the Peruvian case, with a significant hydro resources plus the access to the Camisea gas field, the cost of generation is lower than in the Chilean case. And the cost of electricity as a whole is much lower in the Peruvian case than in the Chilean one.
As mentioned before, we believe that this regulatory framework provides to significant benefits in a growing economy. Why? Because you can keep the efficiencies that you can get in the provision of the services at least for the next 4 years. And you can keep with the growth of your customer base, both in terms of number of customers and average demand until the next tariff-setting process. I have mentioned before, there is a full pass-through of energy costs, so we are not taking the energy risk and the regulatory defined by the energy law, both in Chile and Peru, provides for a more than reasonable rate of return on New Replacement Values for our assets. So at the end of the day, all these factors joined with inflation devaluation protection mentioned before, provide a very good positive framework for the economies where we're doing business.
And this is how it's reflect. You can see in the chart the number of customers' evolution in both cases, for Chile and Peru that have been growing at a 3% -- between 3% of 4% CAGR for the last 5 years. And honestly, instead of looking at 5 years, we look at 10 years to reflect the results are very, very similar to this one. And in the case of energy sales, the CAGR for these 5-year period has been 6% in the case of Luz del Sur, and over 5% in the case of Chilquinta. What this means is every year, not only new customers are incorporated into our network, but the existing customers of these companies began to improve and their standard of living is improving, I mean, they are buying a second TV, they're incorporating air conditioner to their homes, they are growing in their standard of living with higher consumption of energy. Even very far from the levels in the U.S. and described, as were previously described, so even if they are not going to be there in a short period of time, you can imagine what it means in terms of growth for the next few years.
And this performance in terms of customers and energy, is reflective in the profitability of our business. I mean, looking at Chilquinta and Luz del Sur together, earnings has been growing for the last 5 years at a 14% CAGR, while the returns for each one of the 5 years have been between the 14% and 16%. So we really can show that investments in this country has been -- in these countries has provide a very, very good track record. Clearly, it's very challenged to keep this growth and this profitability going forward. But we are really convinced that with efficient operations and with the strength of the currencies of this countries where we are, we are -- we'd able to continue in this good path.
That's the end of my presentation. So I will going to ask George to come back for the Q&A. And in addition to that, Mile Cacic, the CEO for our Luz del Sur operation, and Francisco, if you can join us in case of specific questions of your companies could be coming. Thank you.
George S. Liparidis
That's Mile, that's Francisco.
I understand that the regulations are a little different from the United States and tariffs are set a little differently. But can you give us a sense of the rate base for each one of the entities and what that ultimately is in return on assets? I understand there's a gap of 6% to 14% as long as it's for everybody, but maybe if there's some specific numbers you can provide?
Depending on the efficiency of your operation, you can -- your return could be over the range or under the range, okay? The key for our success and the range are for returns as what I described before with a medium point and 10% in the case of Chile and 12% in the case of Peru. So it doesn't mean that your particular -- that our particular distribution company cannot really get a good return under that point. As for us, we are efficient and the growth in our geographic area allows for that. 10% and 12% are the levels approved by law as return on the New Replacement Values on the global industry as a whole.
George S. Liparidis
Yes. Because the rate basis is not a critical factor to what we're doing, like we can get back to you on what the numbers are. I don't have it at the tip of my tongue. I will say this though, when we have monthly meetings in Chile and Peru, we start out every meeting what the customer growth was last month and what the gigawatt-hour growth was last month because that's what's driving our financials. So I will get back to you with that information, and again, it's like a different model on the types of things that we focus on in managing that business.
Ted Hine [ph] with Point State. Just a quick question on the -- you mentioned the re-gas or gasification of the western part of Mexico. Could you give us some color on how many Bcfs a day that would be, and how much, I guess, the CFE is -- how the RFP process works, how many -- how much dollars that could be? Do you expect to win any of those or is it in your CapEx, et cetera?
George S. Liparidis
Okay. The market is approximately 1,400 megawatts of steam-fired generation of vintage that goes back in the '60s and '70s. In addition to that, there are specific combined cycle plants that CFE plans to build to enhance what the system can deliver or substitute some of that gas. The bid that they have put out, the 1,200 miles that I mentioned, will be a competitive bid. There will be international bids done, we've participated in these in the past. Typically, there's 2 or 3 bidders involved. The magnitude of the dollars depends on what section of the project you add. There are some sections that are over a mountain in Syria that will be in the range of $3 million to $4 million a mile. There are some areas -- there are more desert areas that are easier to build on that's much less than that. But the overall volume of investment is over $1 billion that -- what the CFE is doing. The other thing that CFE is doing, they're making sure that they're only going to do this once. So they're not bidding an 18-inch pipeline because that's what they have in their plan for gas use right now. They're bidding 30 [indiscernible], I want more capacity than the market is because they don't want to go back in 10, 20, 30 years and redo this again. So the 5 projects, sizable investments, not in our plan.
George S. Liparidis
I'm sorry? Say that...
How much [indiscernible]
George S. Liparidis
No, they haven't specifically stated the capacity that they're going to buy. Again, they're going to buy capacity on a 20-year basis, they will buy 100% of the capacity. All they stated, so far, is that they wanted to make sure that it -- they do it once. So the specifics of the bid have not come out. All they've laid out is a schedule on the sequence of these bids. And you can imagine -- what's going to happen is the pipes closer to the border are going to be built first, and they're going to move their way south.
The generation build that you're doing in Peru, the hydro, that's unregulated generation. So is it fully contracted? And if so, what kind of counterparty risk, like who are the counterparties that you would sell the power for? I mean, would you do a 20-year PPA or it's more annual?
George S. Liparidis
Yes, let me give you some points. It's not merchant generation. Because it's run-of-river hydro, there's a certain amount of capacity that is firm, and it's roughly 2/3 of that capacity. And under the law, we can sell that as firm capacity. The off-takers are primarily or solely free customers, these are customers that are buying only transportation service from Luz del Sur but they're buying the generation in the marketplace from other generators because they're big customers -- 5, 10 type of megawatts load. And those free customers that Luz is serving right now, generation and distribution. But Luz is going out and buying that generation from generation companies. So what we've done is, we've come up with a transition plan, where we're transitioning the supply for these customers that we have from market generation to our own generation. And typically, the contracts that these generate -- these large free customers sign go from 7 to 10 years. Mile, do you want to add anything?
Maybe just to add that we didn't consider to have a conventional PPA because that kind of contracts go to satisfy the regulated market where the prices are related. Instead of that, when you go to the free market, you can negotiate the price, the price is free. And obviously, in the free market, the possibilities to get much higher prices are much better. So the plan in short is to place everything that is considered firm capacity and firm energy in the free market. And the strategy is to contract -- and we have started already that capacity and that energy with other generators with contracts that would end in the summer of 2014, dating which the project of Santa Teresa will start delivering capacity and energy. And at the moment, we will just replace the provider from the other generators to our generator.
Raymond M. Leung - Goldman Sachs Group Inc., Research Division
Raymond Leung, Goldman Sachs. Couple of questions about the utilities being underlevered. Can you talk about what is your target for the right leverage and what that may translate into how much incremental debt would come out of it -- those units? And also maybe just about on the regulatory regime, what's the maximum leverage you could actually put on those utilities?
George S. Liparidis
Okay. In terms of the regulatory regime, you saw the way the rules work. They just provide you on an unlevered return and it's up to you to structure your balance sheet as you want. So there's no restrictions there. I think the second part, obviously, there's an ideal capital structure that we can achieve, but it -- the practical aspect is, it's going to be driven by how much growth that we have. So for example, the higher $155 million for the Santa Teresa Hydro plant is being funded 100% with a local debt on the Luz balance sheet. Because we only have $230 millions of debt. So if local currency, 100% funded, so we're levering up. And we have great earnings from that project, and we're utilizing that balance sheet. So it's going to be driven, the pace of it and how much we do, by the projects that we identify and look forward to. Like same thing in Mexico, right? We have the capability to borrow money and do a lot these pipeline projects that we're thinking of, and because we have no debt in Mexico right now. It's all -- we have some intercompany loans between Sempra, but in reality, no external debt.
Faisel Khan - Citigroup Inc, Research Division
Faisel with Citigroup. Just on Slide 11 on your earnings outlook. I just want to make sure that this exclusive is not -- does not include the LNG facilities.
George S. Liparidis
Faisel Khan - Citigroup Inc, Research Division
Did it include the LNG facilities or does it...
George S. Liparidis
Faisel Khan - Citigroup Inc, Research Division
The 2016 number is -- for $425 million...
George S. Liparidis
Yes, what you see in my 2016 number is Mexico, Chile and Peru. The Cameron impact to our earnings is in Jeff's forecast.
Faisel Khan - Citigroup Inc, Research Division
And it's not in here?
George S. Liparidis
Faisel Khan - Citigroup Inc, Research Division
What of Costa Azul? Costa Azul?
George S. Liparidis
No there is nothing for Costa Azul in this because we were thinking it would follow what we're doing in Cameron.
Faisel Khan - Citigroup Inc, Research Division
Okay. So this is...
[indiscernible] the current, current, the current.
George S. Liparidis
Yes -- No, no, no. The current re-gas contracts in Mexico, in Mexico, just Mexico, is in my forecast, right?
Faisel Khan - Citigroup Inc, Research Division
Okay. Right. So then...
George S. Liparidis
I'm sorry. I misunderstood the question.
Faisel Khan - Citigroup Inc, Research Division
[indiscernible] This is a fully taxed version, the way you guys have described the repatriation of these earnings, right? So this is -- okay. So this is the -- if I take this number, minus your CapEx, that's the distributable cash flow back to shareholders?
George S. Liparidis
I'm going to ask Joe to step in here.
Joseph A. Householder
Sorry. Faisel, I was going to address this in my presentation but I don't want to be confusing. The tax that we're going to incur -- that we're going to book actually, on bringing the dividends back from our international operations will actually be in the Parent line, within the Parent line in your numbers. His numbers are international earnings at each of the 2 South American utilities and in New Mexico. It doesn't have the repatriation tax in it, that's in Parent.
Larry Albridge [ph], Columbia Management. Just going back to the hydroelectric plant in Peru. You've mentioned that about 2/3 of the capacity energy, the intent is to contract that out. Is that a function of just primarily expectations in terms of the resource itself, the run-of-river? And the reason why I'm asking this is it used to be a fine dam back in the '90s and its investments in Peruvian -- excuse me, Chilean generators, and they'd come in and they talk about the adequate resource. And then at CM Next Gen [ph] and said we're negatively impacted by the 500-year drought. It happens once every 500 years and they come in next year and say another 500-year drought. And I ask them, it sounds like a biannual drought or whatever. But the reason being, I guess, is when you go out and contract this out, does that take into consideration potential changes in the run-of-the-river? And also what happens if the resource is just not there, what happens in terms of what you have to do in terms of providing power or weather with respect to these customers? You have to go Let's go to market for it and obviously with that impact returns in markets that you have on that business.
George S. Liparidis
Yes. Let me start and Mile can augment what I say. The facility that we're building is taking now the exit watering essence from a power plant that has been there since the 1960s, so it's the same water. The hydrology data, I forgot the exact years, but Mile can say, so there's long-term hydrology data. But -- and we're being very careful about how much we call firm and how much we -- because we're selling it to free customers. But they exist that, I guess this 500-year event that we haven't seen that you need to go out and replace that power. Part of that is -- part of what we're doing now is looking at projects upstream that would create new generation opportunities but would also enhance the hydrology of the plant that we have. But Mile, you might want to say -- talk more a little bit about the history of the data and our confidence with regards to the firm capacity.
Okay. We have a long story of the flowing that river, it is about 52 years of history. So with those numbers, we have ran different kind of models in order to calculate if the design flow of this plant is within a reasonable range. And just to give you an idea, in that river, this year during the rainy season, it was flowing about 700 cubic meters per second, and our design flow is 61. Besides that, as George have said, we have some reservoirs in the Highlands that are going to increase the flow of water in the dry season. Regarding the calculation of the firm energy and capacity, there is a formula to calculate according to the law, and it considers the worst flow in the last 20 years of the worst day in the worst month in the dry season, and you calculate your firm capacity using that particular flow, which is very drastic. And the result of that calculation is about 62% of the nominal capacity that qualifies as a firm capacity. Therefore, that is the only amount of energy and capacity that you are able to contract through bilateral contracts. The difference will go to the spot market which is very hard to predict what is going to happen in that market because it depends on how much water are you going to have. So I think it's very reasonable, we are reasonably covered.
Steven D. Davis
We have one more question.
If I look at Slide 11 and you guys show that the growth in earnings relative to the capital will be spent over the 5-year planning process, it looks like there's a 17% return on assets from a net income perspective which is a very pretty high return on a fully consolidated basis. Is there anything capital-wise that's going in service that's helping that number? Or any given projects that generates such a high rate of return?
George S. Liparidis
Well, I think the investments that we're making have targeted returns that are in the low teens on a levered basis. So I think that what you're seeing is consistent with that.
Steven D. Davis
All right. We're going to take our afternoon break. It's now about 2:40, we're going to -- we'll be back on the webcast, and in the room at 3:00. Joe Householder will be giving the financial wrap up, and then our final Q&A.
Steven D. Davis
Everyone could grab a seat, we can get underway. All right, next, let's begin the webcast. Great, thank you. Now we have up Joe Householder, our CFO, and he's going to give a financial wrap up. And then following that, he will be joined by Mark and Debbie for the final Q&A. Joe?
Joseph A. Householder
Good afternoon, everybody, and welcome back from the break, and good afternoon, to those of you on the webcast. Before I get started, I would like to thank Steve and Victor, Scott, Lisa, Rachel for putting this conference together. I think they did a great job, it's a nice facility. I did hear one concern about the weather from the golfers, and I heard from good sources that it's going to be sunny tomorrow. So we'll hope so.
Throughout the day, you've heard from all of our business unit leaders, all the CEOs from each of our business units how they're going to grow their businesses and all the great projects each of them have to grow their earnings at top quartile rates. And my job now is to tell you how it all comes together on a consolidated Sempra basis.
Our financial goals are driven clearly by our strategy. As Debbie mentioned to you this morning, we have an EPS growth CAGR of 6% to 8%. Our strategic review has led us to maximize and optimize our global tax position. This allows us to bring back cash distributions from Peru and Mexico and bring dividends from those international operations to the United States and help us pay a higher dividend.
As we've discussed throughout the day, we intend to grow our renewables business and build the liquefaction opportunity with partners and with project financing. And we've also talked about how we're going to explore an MLP structure for our natural gas business in the United States. We're going to do all of this with an eye toward maintaining our strong balance sheet, at a competitive dividend and healthy credit ratings.
For those of you who've been with us for many years in the past, this chart is going to look -- or these slides are going to look a little bit odd to you if you haven't seen one like this before. The shaded bars here represent the business unit earnings for each of the years, net of a proportion of amount of the corporate cost, and we're showing you this for all 5 years. The reason we're doing that was during our fourth quarter earnings call, when we talked about the repatriation strategy and the tax expense that we were going to incur and our growth rate, it was little bit hard to do on the telephone call without these slides and without being in person. So we want to show you how we see the trajectory of our earnings, you saw this on Debbie's slide this morning. To reiterate, over this 5-year period and over the long term, we expect our CAGR to be 6% to 8%. Near-term growth, however, will be hit by the $0.30 tax expense to repatriate the foreign earnings starting in 2013. Again, that $0.30 per share happens each and every year that we bring back these dividends. So in our plan, it's 2013, '14, '15 and '16. If not for this tax expense, our near-term growth would be over 8%. You can see that the growth is pretty linear beginning in 2013 to 2016, it would be completely linear but for this tax expense. Again, I'd like to also note, and I'll talk about this again later, but the tax expense is mostly a book expense, very little of it will paid out during this time period.
As you heard earlier today, the drivers of our growth include the Sunrise Powerlink project that Jessie spoke about, our organic growth in South America that George spoke about, and our renewable projects development that Jeff spoke about. One thing that's really important is to think back about the Cameron liquefaction project that Mark talked about, it's our important development project and all of the growth is primarily after this plan period. There is a very small sliver, about a month's worth in 2016, as Mark mentioned earlier.
Finally, as we move forward and look forward to next year, you probably won't see this slide again, we intend to revert to the 1, 2 and 5-year growth projections that we've shown in the past.
This slide depicts, as we typically have, the 1, 2 and 5-year business growth and guidance, 5 business units. You'll recognize this as in the new business unit format, so we have: SDG&E, SoCal, International and U.S. Gas & Power. As Mark mentioned, and I'll repeat here, we're going to have separate segments under international when we actually report earnings. We're going to have a Mexican operation segment and a South American utility segment. And under U.S. Gas & Power, Jeff will report a renewable segment and U.S. natural gas segment. Together with Parent, SDG&E and SoCal, we'll have 7 reporting segments, but we only intend to give guidance, as Mark said, to these 4 business units.
At the California utilities, we have great growth of 5% to 6% with a bit higher growth, as Mike mentioned, for his SoCal business due to the Pipeline Safety Enhancement Program. In international, our growth is from the Peruvian hydro project that George spoke about, and our base utility operations and some additional opportunities in Mexico and through the PEMEX JV. And at U.S. Gas & Power, our growth comes from a number of different areas: from a renewable build out, which is quite important; from contracts at our gas-fired generation plants, and completion of our storage projects; and a small contribution, as I mentioned, from the liquefaction project. One note here about Parent & Other, as I was mentioning a moment ago, the Parent & Other column increases in 2013 and 2016 from the 2012 number due to the tax expense we're going to record for the repatriation of the foreign dividends.
Also, please note on this slide that there is a very small change in diluted shares outstanding, only from employee plans. We do not expect to have any share issuances during this 5-year plan period and no share buybacks.
We feel really confident about this plan. On about a Yogi Berra comment, I feel very confident about this plan. In fact, 80% of our earnings in 2016 are either from our regulated utilities in South America or California, or they're already contracted. So there isn't much left to worry about from Yogi Berra.
In the U.S. Gas & Power business, you can see on the chart renewables makes up a little more than half of that growth. There's an increase in the storage earnings. There's an increase in our contracts for gas plants, some of that's already contracted, as Jeff spoke about. And again, this little sliver of Cameron liquefaction.
In summary, our growth does not result from anybody hitting a home run, but rather each of the business unit leaders executing well on their strategies.
You can see here that our growth in earnings is really driven by operations. On this slide, you can see the EBITDA leads our earnings growth and improves steadily over the 5-year period and while I don't show it here on the slide, EBITDA is $1.5 billion higher than our CapEx in 2016. The shaded bars here represent a rough proportion of the EBITDA by business unit.
In capital expenditures, our plan is slightly lower than it was a year ago, this is primarily due to the fact that we decided to use project financing and the partners in our renewable business. So all of the capital expenditure numbers you see and you saw on Jeff's slides are net of the financing plan.
Over the next 5 years, over 80% of our capital is going to be spent right here in Southern California at our 2 utilities, Mike and Jessie. And as they said, all of those projects are aligned with PUC, governor goals, et cetera. So they're very aligned and that's where the money is going to get spent. In addition, Jeff will be spending about 12% of our capital in the renewable development.
This slide presents additional details by business unit for the capital expenditure plan. I'd like to repeat what Mark said earlier, we only intend to contribute the current Cameron facilities into the liquefaction project unless we do the 3 trains and even then, it'll only be a small amount of additional cash. All the figures, as I mentioned, they're net of project financing for renewables, and importantly, and we didn't talk about this earlier, but if we do projects in the PEMEX JV, we wouldn't be putting additional capital. And there's no capital here for that because the PENEX JV has cash on-hand and it also has the ability to finance with the JV. So there's nothing here but that is something we would expect to occur as well.
A few other points I'd like to note. In the later years, you can see that SoCalGas' CapEx is about equal to that of SDG&E's. That, again, is primarily a result of the pipeline safety project. In U.S. Gas & Power, you can see that capital expenditures change quite a bit from year-to-year here. I'll tell you some reasons why that is. In 2012, as Jeff mentioned, we're building 2 large wind projects with BP, they're in construction, they'll be done by the end of the year. We're also building out the 150-megawatt Mesquite project in Arizona. That's 100% owned by us right now. So that's in construction, it's going to be finished in 2013, but there's a lot of capital in 2012.
Post 2012, as Jeff mentioned, there is no U.S. wind project in his plan. If Congress changes their mind or we find some wind projects even without PTC, that meet a hurdle rate, we'll look at that but there's nothing in the plan. As he mentioned, George has the ESJ wind project that was recently approved by the commission for SDG&E to buy the power from. That will go forward and that's in George's plan.
We've already discussed our capital allocation strategy, our renewables and liquefaction. But I want to reiterate something that Debbie and Mark talked about, about divesting assets that aren't meeting our hurdle rate. If we think we can divest assets and get a reinvestment, and those returns will be better than what we earn today, we'll do that. But we're going to keep the assets if we think that they're going to improve and we think that our ability to reinvest the net proceeds won't earn us what we're earning today.
I want to talk for a few minutes about cash flow from our international operations. During our fourth quarter call, we announced that beginning next year, we're going to start to bring cash back from our international operations. Coming from Peru and it's coming from Mexico. We currently don't expect to bring it from Chile because in Chile, we would have to incur a cash tax to actually get it out of the country. So we'll continue to look for opportunities there, and George spoke about some of those.
One thing I want to talk about, because I think there's been a slight bit of confusion about this, we're intending to distribute current earnings and current excess cash flow beyond the needs that we have in the plan. We have $0.75 billion of actual CapEx in those utilities and in Mexico that's in the plan. We're distributing money from current cash flow, we're not borrowing, we are not levering to pay these distributions. We're expecting to be about $300 million a year, through 2018, you can see on the chart about $1.8 billion. [Audio Gap] current expectation. Because I believe we mentioned on the call, we could change that if tax laws change, if something else was more favorable. But this is our current plan. And the reason we can do this efficiently, you can see on the chart, we have U.S. tax losses created by bonus depreciation in the first several years of our plan. And then we have renewable tax credits. One thing we spoke about when Jeff was up here, is when do you use those tax credits. So we have wind credits and we have our investment tax credits from his business. You can see that they're not going to be used for the next few years but then they begin to be used. And you can think about, if he is doing a project in 2016, that might get used by about 2018, if he's doing it in 2013, it might get used by say, 2016. There's a very short delay. This is why we can be in this business with a short delay, it's coming from the Treasury Department. We think the discount rate on something like that is very, very low. It's cheap money, it comes in very fast.
We are required, as we mentioned, to record a tax expense when we bring these distributions back to the U.S. There eventually will be a cost to bringing these funds back, about 20% of the total, that we're going to bring, but it won't be paid for a number of years. In fact, I mentioned, most of the money won't be paid until after this plan period.
A couple of points I'd like to really note here. First, we think this really shows the strength of our international operations. It shows strong earnings and strong cash flows and the ability to bring that fund -- those funds back here to the U.S. and increase our dividend. Second, we think it illustrates a real synergy among our businesses. We have a bonus depreciation coming from our California utilities. We have our renewables business throwing off bonus depreciation and tax credits, and we have strong international operations. You blend those all together and there's a very nice synergy that allows us to increase the dividend and have great returns.
The second item we talked about on our earnings call was the change in solar -- change in accounting for solar tax credits. As our portfolio began to grow, an immediate recognition of investment tax credits became larger and larger, and a bit less connected to our ability to actually get the cash back from the IRS on the return due to bonus depreciation. It really made sense for us to change our accounting method now rather than to stay on the method we'd been on for many, many years.
I'm going to reiterate, there's no change in the economics, whatsoever. And there's no change in the earnings over time. We've put an example in your appendix, we used the same numbers that we used in this slide a year ago, so if you compare those 2 slides, you can see the differences in earnings over time. If you have any questions, you can ask Scott or Victor or ask one of us later.
I'd like to make a few points regarding our capital structure. First, our leverage ratio remains constant and consistent from 2011 to 2016 at about 51%. Also, you can see on here that our operating cash flow, exceeds our capital expenditures so we're free cash flow over the 5-year plan period. We expect to maintain a strong balance sheet, and we have a great and stronger financial supporting us with a $4 billion credit line.
In summary, we have great top quartile growth from every one of our business units, we have strong EBITDA growth of 7% to 9%, which supports our strong balance sheet and our capital program, and we have a nice dividend increase of 25% to $2.40 a share, that's supported in part by our international operations. Our capital allocation is clearly aligned with our strategy.
With that, I'm going to ask Debbie and Mark to come back to the stage, and we'll answer your questions. My new boss and my old boss. We have fun every day.
Debra L. Reed
No questions? That's unusual.
Mark, when you flex the numbers for the sort of the optionality of dropping the gas business into an MLP, so if we look at year-end 2013, everything is going -- sort of best-case scenario in getting, moving forward on doing the 3 trains, and you decide to move ahead, how does that -- what are the sort of the big puts and takes on how that might change the sort of the financing plan and the cash flow profile off this base case?
Mark A. Snell
Well, I think, ultimately, what you would think of is, we would drop the -- we would put our existing midstream assets in and probably fund the MLP at that point if we did it in -- say, late 2013 and early 2014. We'd fund the MLP distributions primarily out of REX, the $85 million or so cash flow a year that we get out of REX and the other cash flow from the other units. And then over time, liquefaction goes forward, the REX contracts taper off at the -- for the end of -- starting in '15 and '16 down the road. And we drop in the liquefaction amount sometimes earlier than that -- probably do it in chunks, mainly because of the ideal size of the market, it's just not big enough to drop in something that makes $300 million a year right away. I think it makes more sense to probably get at optimum price, but it would change our financials a little bit in the sense that we have more cash earlier, the 20% units that we sold. If we sold some of our own units, so we could generate some cash earlier if we need it, had a need anywhere else in the company. But primarily, we'd be doing it to create a vehicle to grow the midstream space. And then I think what we really -- we'd look and try to do is try to continue to have the corporate GP, the general partner, and create value there because as you drop these things in, we would get into the high splits and that's how the Sempra shareholder really gets the juice out of this and it makes sense for the Sempra shareholder.
Two questions. First, no one has really talked about today, and I don't know if this is something that Debbie can talk about or maybe it's for Jessie, but give us an update on what the implications are for an extended outage at SONGS or what's the current thinking there. And then secondarily, with respect to -- something that you brought up, Mark, about the development or the movement towards more gas in the Southeast, you didn't say anything with respect to generation and your aspirations there, if there are any, will be through acquisition or future greenfield development or whatever.
Debra L. Reed
Hey, Bob. Yes, I'll take the SONGS question. As all of you know, we're 20% owner of SONGS, we're not the operators. So Edison is very much involved in doing all of the assessment for this -- and I know they had a meeting yesterday. So I think what they told you yesterday is pretty much what we know relative to the situation at SONGS. The Nuclear Regulatory Commission is very much involved and looking up what the issues are, and Edison is extremely focused, as they should be, on ensuring that this plant is safe before they restore it to service. I think their plans are such, that when they are convinced and the NRC is convinced that the plant is safe, it's when it will all be restored. So they are not doing any kind of projection at all on when that is going to happen. They really got to diagnose the issue and be sure that they're corrected.
Mark A. Snell
I think, 2 things, just tailing on SONGS. Jeff's group, on the generation side, we're obviously looking to make sure -- we're looking at our maintenance schedules on our plants. We definitely want to make sure that we're running in July, in August and September because we could see some higher power prices. But beyond the other issues, too is we want to make sure that we've done everything we can to make our facilities available for customers when we could be short and I think the utilities are doing the same thing. You're seeing that at SDG&E. So everything is -- we're anticipating and working as if we might have a large unit out this summer and so we're taking that into consideration.
Debra L. Reed
I would just say that I don't want to be taken as the best speculation that is going to happen. We go through this kind of process every year in summer planning for resources, and we've had periods of time where we have resources out for periods of time. And we have to plan ahead for that occurring. But I wouldn't want anyone taking away that anything that we said indicated that SONGS is going to be out for the summer because quite honestly, we don't know.
Mark A. Snell
And then with respect in the Southeast, we do think there's going to be opportunities there. There's been other people that have tried to develop power plants in Southern's backyard, and Duke's backyard and hasn't always proved to be all that profitable. So I think, our focus is really helping those munis and co-ops in things that maybe there's a role for us that make sense where we could provide some capital or provide something in exchange for a long-term PPA or something where they can buy the plant back over time. I mean, those are the kinds of things that we'd like to do. But our primary focus, as Jeff said, in that area is growing our midstream business that would feed our MLP. So while a gas plant really helps us grow our midstream business, it needs storage, it needs pipeline capacity and we would really want to try to accommodate those things, our main focus is really on the midstream stuff.
Given the headwinds that Rockies Gas is facing in the Northeast, is there a worst case scenario that would cost cash flow from REX to taper off before 2015?
Mark A. Snell
I don't think there's a -- there's not a worst case scenario. I mean, there's no indication that the fully contracted pipeline that people aren't going to honor their contracts. And I don't think the basis for it is you can get a heck a lot lower for what little is given to this is not contracted. I don't see anything between now and sort of contract expiration that changes things a lot with one exception, we do have -- there is some debt on that pipeline that will have to be rolled over prior to the expiration of the contract. And I don't know what's the -- we haven't had those negotiations yet, so I don't know if -- what will happen or what might have to be paid down or whatever to do that. But for the most part, we don't see a significant impact until well beyond the contract period.
A follow-up. Is there a possible scenario that you might backflow or flow shale gas from the Northeast partway west on REX and reduce the transmission distances from the Rockies, say, to Chicago -- that you can get a better proposition?
Mark A. Snell
There are certain people that are looking -- a lot of people that are looking at that. We think it's a real possibility to flow really from Ohio down to the trunk line up to Detroit and the other pipeline is going up into Chicago. It's a possibility, there's a negotiation that needs to be had with the current capacity holders, because they have some rights. If a different service is being offered and we have to take all of that into consideration, but there's -- I think there's a likelihood that, that happens down the road and it's probably pretty likely really.
Just a follow-up. How much debt is on REX and when is it due?
Mark A. Snell
I don't know the total off the top of my head. Is anybody...
Joseph A. Householder
I think $3 billion, yes.
Mark A. Snell
Yes, $3 billion.
All of that is due...
Mark A. Snell
It's -- most of it is -- a lot -- most -- the majority of it is due beyond the contract period, but there is 2 pieces that roll off, one in late 2013 and I think the other one is in 2015.
Debra L. Reed
I just want to clarify that the $3 billion is not our share.
Mark A. Snell
Yes, that's total debt. Yes, that's total REX debt.
Faisel Khan - Citigroup Inc, Research Division
Faisel with Citi. On the earnings outlook for '13 and -- for '13 what's the tax rate that we should assume for that number?
Joseph A. Householder
For 2012, it's about 30%. And for the later years, it's in the low part of the mid-30s. You can actually -- if you look at my EBITDA reconciliation in the back, in the appendix, you can back into it, the low part of the mid-30s.
Faisel Khan - Citigroup Inc, Research Division
Okay. Got you. And then in terms of the timing for a potential filing for an MLP, when do you think it -- you're going to market for that?
Mark A. Snell
I think it kind of depends on where we end up with liquefaction that'll kind of control our timing on it. But I mean, I think the earliest is probably -- I mean, what would you say? Next year, sometime late next year.
Faisel Khan - Citigroup Inc, Research Division
Okay, got you. And then just going back to some of your comments on potential acquisitions in the utility space or on your footprint, would those type of acquisitions be company-transforming transactions are more like small bolt-on transactions or how would you -- how are you thinking about those set of opportunities?
Debra L. Reed
Well, I think we're open to either that. I mean, I wouldn't say that our plan is to acquire a whole bunch of work. That's not our strategy as a whole bunch of small, but what we really want to focus on is when there's greater benefit than just synergies. And so if there were some opportunities with our midstream assets and another utility that also have midstream assets, then we could bring those 2 together. And it works for everyone, that might be great, that can also be done in other means besides mergers or acquisitions and we would look at all of that. And I think some of the combinations that I've been announced when there's value creation, other than through synergies, is what we're really looking for. And that was really truly the way Sempra was formed. We have these 2 utilities but the merger of those entities the formed Sempra was largely about not just synergies, but the opportunities to create growth in our other businesses. And so, that's the way we kind of look at it. I think, Dan, we are done with question. I'm amazed because every time I go to the ladies room, I get questions. I just want to thank you all so very much for joining us today, either on the webcast or in person. And I thank you for our -- your interest in our company. I think you can see that we are very enthusiastic about our future and the high growth and the opportunity to return capital to our owners. And so thank you very much, Steve is going to give you the details of this evening.
Steven D. Davis
Thank you very much. This concludes our webcast.
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