桑普拉能源 (SRE) 2014 Q4 法說會逐字稿

Good day, everyone, and welcome to the Sempra Energy fourth-quarter earnings results conference call. Today's call is being recorded and at this time I would like to turn the conference over to Rick Vaccari. Please go ahead, sir.

Good morning and thank you for joining us. Today we will be discussing Sempra Energy's fourth-quarter and full-year 2014 financial and operational results.

A live webcast of this teleconference and slide presentation is available on our website under the investors section. With us today in San Diego are several members of our management team: Debbie Reed, Chairman and Chief Executive Officer; Mark Snell, President; Joe Householder, Executive Vice President and Chief Financial Officer; Martha Wyrsch, Executive Vice President and General Counsel; and Trevor Mihalik Senior Vice President, Controller and Chief Accounting Officer.

We also have the heads of our two California utilities, Dennis Arriola, Chief Executive of Southern California Gas and Jeff Martin, Chief Executive Officer of San Diego Gas & Electric.

Before starting I would like to remind everyone that we will be discussing forward-looking statements on this call within the meaning of the Private Securities Litigation 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 discussed in the Company's most recent 10-K and 10-Q filed with the SEC.

It's important to note that all of the earnings per share amounts in our presentation are shown on a diluted basis and that we will be discussing certain non-GAAP financial measures. Please refer to the presentation slides that accompany this call and to table A in our fourth-quarter and full-year 2014 earnings press release for a reconciliation to GAAP measures.

I'd also like to note that the forward-looking statements contained in this presentation speak only as of today, February 26, 2015 and the Company does not assume any obligation to update or revise any of these forward-looking statements in the future. With that please turn to slide 3 and let me hand the call over to Debbie.

Thanks, Rick, and thanks to all of you who are joining us. 2014 lays a strong foundation for our future growth. We had solid financial performance, achieved double-digit annual EPS growth and posted earnings exceeding our guidance.

We also achieved important milestones on development projects and delivered strong operating results across all of our businesses. With the great progress made over the year we are on track to be at the upper end of our expected 9% to 11% earnings per share growth rate for 2014 to 2019.

As a reminder, we have our upcoming Analyst Conference on March 26 and we hope to see all of you in New York. At that time we will update our five-year earnings projections and discuss our plans to continue to deliver strong returns for our shareholders.

For today's call I am going to focus on a summary of our 2014 financial results and recent operational accomplishments that will help us to achieve our long-term growth plans. I will then hand the call over to Joe to explain the fourth-quarter earnings, our 2015 adjusted earnings guidance range and our 2015 dividend increase.

Please turn to slide 4. This morning we reported 2014 earnings of $4.63 per share. On an adjusted basis 2014 earnings were $4.71 per share, representing 13% annual growth over 2013.

We had strong operating performance across the Company that contributed to this result. Several fourth-quarter factors also drove earnings above our expectation from the last call where we stated that we expected to be near the upper end of our 2014 guidance range.

The major factor was tax reform in Peru that was implemented on December 31. Peru lowered its corporate income tax rate which reduced our deferred income tax liability and resulted in an $18 million benefit recorded in the fourth quarter.

Additionally, the CPUC approved our energy efficiency awards for both utilities earlier than we had anticipated. Looking to 2015 we expect Sempra's adjusted earnings to be within the range of $4.60 per share to $5 per share excluding two items Joe will discuss later. We also received Sempra Board approval to increase our annualized dividend to $2.80 per share, a 6% increase.

If you look back over the last few years our dividend has increased nearly 80% since 2010. And we continue to be committed to returning capital to our shareholders.

Now, let's turn to slide 5 for an overview of key accomplishments at SoCalGas and SDG&E. Our California utilities are spending capital consistent with approved programs. The utilities have also received important regulatory decisions in 2014 that establish the framework to guide investments in programs like the pipeline safety enhancement plan or PSEP.

In November the CPUC approved the SONGS multi-party settlement agreement that resolves the cost recovery issues on the plant closure. Also both SDG&E and SoCalGas filed their 2016 general rate case applications with a proposed decision expected by the end of this year.

In December, the CPUC approved a one-year extension of the utility's cost of capital raise. The extension keeps the authorized returns on equity of 10.1% for SoCalGas and 10.3% for SDG&E intact through 2016. It also keeps in place an automatic adjustment mechanism should interest rates move beyond a predetermined band.

Operationally, SoCalGas installed nearly 1.8 million advanced meters last year and is ahead of schedule on their program to install nearly 6 million advanced meters by the end of 2017. Both utilities are ahead of schedule in implementing their pipeline safety enhancement plans as well having already tested or replaced over 30 miles of pipeline last year.

Now let's move to US Gas & Power on slide 6. Key milestones reached last year on the Cameron liquefaction project include reaching the final investment decision or FID, forming a joint venture and getting the project fully into construction. With permits, financing and a lump sum turnkey contract in place we remain on track to complete all three trains in 2018.

In December the JV also filed with the Department of Energy for FTA authorization to export an additional 2.95 million tons of LNG per annum on trains 1 through 3. We expect to file for the non-FTA export permit this quarter.

These higher volumes match the maximum design capacity of the plant approved by FERC and permits would allow us to export additional LNG during periods when production levels exceed the 12 million tons per annum already approved. However, just to be clear, while this can provide upside we do not expect the plant to produce at the maximum capacity on a routine basis and additional production is unlikely during startup and the first few years of operation.

If higher volumes can be produced that Cameron's customers use for export, we could see earnings upside in the future of approximately $30 million for each 1 million ton produced. Work on our three major LNG development projects also continues to move forward. This week the JV partner submitted the FERC prefiling and DOE FTA export application for Cameron train 4 and 5.

The filing would add a combined LNG capacity of approximately 9 million to 10 million tons per annum. We expect to submit the full FERC filing later this year which will initiate the detailed environmental review process that should take approximately 12 to 18 months to complete.

At Port Arthur and ECA design, regulatory and commercial activities are ongoing. For Port Arthur we are working to prepare our FERC prefiling. For ECA we announced the signing of an MOU with PEMEX last week.

The agreement signifies our intention to cooperate on the development of the export project and explore the possibility for PEMEX to participate as a customer, supplier and/or investor. For all three development projects we have been meeting with a large number of potential customers and continue to see demand for LNG supplies in the 2020 to 2023 time frame. We have also been on the road speaking with many of you about our competitive advantages in providing low-cost reliable LNG to the market.

Our US and Mexican LNG projects are very compelling even in today's lower oil price environment. And Sempra is one of the few developers who have successfully contracted, permitted and financed a liquefaction facility in North America. We plan to provide an in-depth discussion on our development projects at our March Analyst Conference and will have the President of our LNG business, Octavia Simoes, there to answer your questions.

Let's now go to slide 7. For our natural gas segment converting REX into a bidirectional pipeline was a positive long-term development last year. As you know 1.8 Bcf per day of east to west capacity on REX is now under long-term contracts. A third of this capacity is in service and the remaining capacity should be online mid-2015.

In addition the REX joint venture has made progress on finalizing precedent agreements with interested shippers for expansion of east to west capacity. The expansion would likely occur through additional compression and would be subject to regulatory approval. We are expecting any day to receive our FERC approval of the 1.2 Bcf per day of east to west capacity that is already contracted.

Once that approval is received we hope to provide additional details on the expansion project.

Shifting to our renewables business, in the fourth quarter we added our 75 megawatt Broken Bow 2 wind project to a joint venture with ConEd. With this transaction we have successfully partnered with ConEd on over 700 megawatts of renewable power projects including seven different solar plants and the Broken Bow 2 windfarm.

Please turn to slide 8. In Mexico IEnova has progressed on construction and is now generating earnings on sections of both the Sonora and Los Ramones pipelines placed in service in 2014. Together these two pipelines will provide nearly 3 Bcf per day of import capacity to Mexico.

IEnova was also awarded the first natural gas pipeline tendered by CFE as part of Mexico's five-year national infrastructure plan. The associated CapEx is $300 million and the pipeline should be in service in the first half of 2017 under a 25 year, dollar-denominated take-or-pay contract.

Since our last call, the CFE has put out tenders for an additional four pipelines in Mexico representing an estimated $1.8 billion in investment. One of the bids is due next month and the other three bids are due in May. For your reference we provide updated information on CFE bids in the appendix to this presentation.

With that, let's move to a discussion of the quarterly earnings in more detail. Before I hand the call over to Joe, however, I want to comment on the status of our total return vehicle or TRV analysis. We have indicated that we expect to complete our analysis on a preferred TRV structure by the end of first quarter.

We are continuing several different work streams in this respect. As you know, nearly all of our midstream and renewable assets are owned in partnerships and there are numerous accounting and legal aspects we must deal with for those assets. We will provide you with more information on our TRV preferred structure at the Analyst Conference.

Joe?

Thanks, Debbie. Turning to slide 9 our fourth-quarter and full-year 2014 results were very strong. This morning we reported fourth-quarter earnings of $297 million, or $1.18 per share.

We recorded an additional $12 million after-tax loss in the fourth quarter for the early closure of SONGS making the total SONGS-related loss in 2014 equal to $21 million. Excluding this loss, fourth-quarter adjusted earnings were $309 million, or $1.23 per share.

Full-year 2014 earnings totaled $1.161 billion, or $4.63 per share. This compares to 2013 earnings of $1.1 billion, or $4.01 per share.

On an adjusted basis, 2014 earnings per share were $4.71. Year over year adjusted earnings per share grew 13%.

Similar to last quarter's call we provide individual financial results for each of our businesses in the section of our presentation entitled business unit earnings. Today I'm going to focus on the key drivers of our consolidated fourth-quarter earnings beginning on slide 10. Fourth-quarter adjusted earnings increased over the same period last year due in part to $33 million of benefits in 2014 coming largely from three items.

First, in December the Peruvian Congress approved gradually lowering the corporate income tax rate from 30% in 2014 to 26% in 2019 and that was signed by the President on December 31. We recorded an $18 million income tax benefit in the fourth quarter as a result of the remeasurement of our deferred tax liabilities.

Second, US Gas & Power recorded an $8 million after-tax gain from the sale of a 50% equity interest in the Broken Bow 2 wind project. Third SDG&E had $7 million of increased earnings from higher CPUC-based margin and FERC regulatory operations.

Partially offsetting these items were $7 million of net benefits in 2013. SoCalGas had $20 million of lower income tax expense in 2013 primarily related to resolution of prior year's income tax items and higher flow-through deductions recorded in that year.

Netted against this amount is $13 million of deferred income tax expense for Sempra Mexico in the fourth quarter of 2013 that related to Mexican tax reform. With regard to foreign currency-related FX we did see a $16 million reduction in South American earnings over the course of 2014 due to the depreciation of local currencies against the dollar. However, this impact was almost entirely offset by foreign currency-related FX and inflation in Mexico where depreciation of the local currency decreased our deferred tax-related balances and increased our earnings.

Now please go to slide 11. Turning to our guidance for 2015, we are setting our adjusted earnings guidance range at $4.60 to $5 per share. This range reflects a number of factors including higher utility earnings, new revenue on the REX pipeline, a year-end forecast for South American currencies and the fall of natural gas futures prices that may reduce our gas storage and marketing revenues.

Our adjusted guidance range excludes two items. First, as we indicated last quarter, we are not including the expected gain on the sale of the second block of our Mesquite Power plant. The estimated earnings impact for this sale ranges from $0.12 per diluted share to $0.15 per diluted share.

Second, we expect to incur some development costs related to our three LNG projects: Cameron trains 4 and 5, ECA and Port Arthur. Advancing development projects to the full FERC filing could cost up to $25 million per project. However, at this point we do not know the timing or the amount we will spend, the total cost we will share with our partners or the breakdown between the amount we may capitalize and the amount we may expense.

We believe that excluding the development cost for these three projects gives us better clarity into the ongoing results of our business since earnings from these efforts will likely only be realized in 2020 and beyond. We will be disciplined in our approach regarding development spending and will periodically update you on our progress.

Amounts expensed will be reflected in our GAAP numbers. We expect to have more updates on LNG projects at our Analyst Conference in New York on March 26. At that time we will also provide updated 2015 guidance on a business unit level as well as our long-term projected growth rate.

With regard to the dividend, the Sempra Board voted to increase our annualized dividend by 6% to $2.80 per share. Given our target payout ratio of 45% to 50% this increase allows for a smoother path toward payout in 2019 when a full year of Cameron liquefaction earnings is expected to begin. The increase in the dividend reflects the confidence we have in our long-term growth and it's consistent with our commitment to grow the dividend.

To reiterate Debbie's message at the beginning of this call our underlying businesses are performing well. We are executing on our development projects and we are on track to achieve results in the upper end of our expected 9% to 11% earnings per share growth rate for the period 2014 to 2019.

With that we will conclude our prepared remarks and stop to take any questions you may have.

(Operator Instructions) Greg Gordon, Evercore ISI.

Thanks, good morning, good afternoon to us, good morning to you. A couple of questions. First one is when you look at the impact of FX for fiscal-year 2015 versus fiscal-year 2014 using the assumptions that you're making year over year how much of a headwind is that?

I'm going to have Joe address the FX issue. As you know we have FX going one way in South America and FX going the opposite way and Mexico because the Mexico FX is related to Mexican tax code. And since we have dollar-denominated contracts in Mexico but we pay the tax in the peso it creates a natural hedge but I will have Joe talk about the 2014 to 2015.

Hi, Greg. Thanks. It creates some modest reduction in our South America utility earnings because we are using the year-end forward curve for the year and that creates some downward pressure. But we've seen in the last several years that the Mexican tax pretty much offsets it but we're not providing any details at that level.

(multiple speakers) it was $1 million this year.

Okay. So all things equal you're not building in a big headwind from FX net-net?

No.

No.

Okay, I just wanted to be sure.

And let me just be clear when we do that we look at the forward curves and we look at what the market curves are and that's what we put in our plan. So we don't do numbers that are not consistent with what the market curves are.

And the natural hedge from this as I said before works really well when all three currencies move in tandem at the same time and that doesn't always happen. But that's what we've witnessed the last several years.

Hello.

(technical difficulty) did you lose me?

Yes, we did. We lost you for a second. I'm sorry. Could you repeat the question?

No, that was my only major question. I will let someone else ask something. Thanks.

Okay, thanks Greg.

Steven Fleishman, Wolfe Research.

Yes, hi, good afternoon, good morning. Just a question with regard to the growth rate and going to the upper end of the 9% to 11%. Is that on the basis that you gave at the Analyst Day last year where you are only including Cameron for 2019 or is that on a more normal basis where you're including all the businesses for 2019?

Okay, when we gave you the 9% to 11% last year it was looking at the composite growth rate for Sempra as a whole. And it includes Cameron trains 1 to 3. And we're going to go through this in detail with an update at the Analyst Meeting.

But as I said in my prepared remarks with where we are now and some of the additional project opportunities we have already contracted like pipelines in Mexico, the REX uplift and all we feel that in the 2014 through 2019 period we would be towards the upper end of that range. We will go through how we get there and I think you'll see at the Analyst Meeting that we have quite high visibility to the achievability of the upper end of that range.

Then we also have quite high visibility of some additional upside that could either make that range higher or could extend that beyond 2019. And we'll talk about all of that in detail at the Analyst Meeting.

Okay. Then my other question is just I'm sure at the Analyst Day you'll talk more about the LNG export environment for new contracts but maybe if you could give us a little sense of the likelihood that when should we expect that you might have some kind of commitments, MOU for additional LNG export growth for Cameron 4 and 5 or others?

I think you should maybe use the process of 1 through 3 as an example of how it's most likely to roll out for 4 and 5. And you have to basically come up with the conceptual design of the facility to be able to price out the facility. That's where we are right now with our FERC prefiling that we just made on trains 4 and 5 at Cameron and our DOE FTA filing.

Then that's when you can really start your commercial activity because you have a project you can talk about that has some conceptual framework around it. So the active marketing really begins right around now and we have had numerous contacts with customers about all three of our projects. There remains a lot of interest as I said in my remarks.

We'll talk about the groups of customers and their interest in each of the projects and what drives their interest in each of the projects in more detail at the Analyst Conference. Mark, did you want to add anything to that?

Yes, the only thing I would say is that we are talking actively with customers but we need to do some of this preliminary work in engineering so that we can get a better ballpark on what the pricing and cost will be. It's very hard for them obviously to commit to something if they don't know what it is going to cost. We're highly confident that especially with trains 4 and 5 that we'll be a low-cost provider and we think that will position us well for additional volumes.

Then also with at ECA, too, as well we believe we can be a relatively low-cost provider given both the existing facility and the transportation advantages that being on the West Coast has. So I think we're coming into the market with two projects at least that should be at the low end of the cost scale of what people are looking at and then we have a big opportunity at Port Arthur to build a big facility and it could even be a multiuse facility.

So I think we're pretty excited about the opportunities that we have in front of us. And we think as we progress during this year with the studies and the engineering work of the things that we need to do to get permitted that we'll be in a good position to sign up people.

Great, thank you.

Chris Turnure, JPMorgan.

Hi guys. Just a follow-up on the last question. If we look back to the 2012 process for trains 1 through 3 could you just walk us through the ultimate offtake agreements there?

I know they were just commercial development agreements at that time but my understanding was the three counterparties were each signed up for a third of the ultimate capacity and that they did not at that time know what they would do to sell that gas in any kind of firm way. So does that differ at all from this time around and where you are in the process now?

No, I think the process would be quite similar. We filed our FERC prefiling and our FTA at DOE and then that helped to fund the project and then a few months after that we had the MOU, I think it was actually about six months after that, five months after that we had the MOU with those parties.

We have the structure that [sprained] up for Cameron's trains 4 and 5 because it's very much like the structure of Cameron's trains 1 through 3. So Mark, do you want to go into more detail?

Yes to shed a little more light on that, so when we did the first three trains we started the FERC process and went through this and we had agreements with partners that subject to certain conditions they would sign up for firm capacity. So as we move through that process and as we got various permits including our non-FTA, we got our fixed-price construction contract and we got a handle on ultimate delivery, those we met some of the conditions precedent and then those commitments that take that capacity became legally binding at a point in time.

It will be similar to that here. The difference here is that we already have all the operating agreements in place.

We know how the facility is going to operate. We know how we are going to share cost. We have all of those kinds of agreements done.

So a lot of the heavy lifting has been done and it's really a matter of our partners marketing the extra capacity, the extra LNG that they would produce and ourselves. Because on the expansion we have the right to take 50% of the capacity subject to the same operating and arrangements that are in trains 1 through 3. And so our plan is to do that and for us to sell that capacity or LNG in the market.

We're working to commercialize that option. So it's very similar to the first one but it is slightly different.

The other thing that I would say that's different this time is the first one was Sempra doing this and now it's the joint venture that is doing this. So the decision that was just made to make these filings was the joint venture partners in addition to Sempra making the decision to move forward.

Okay, great. That's very helpful.

And then just to be clear that point of legal no return for the counterparties to commit after the different domestic logistical hurdles were reached was the MOU not the commercial development agreement?

Yes, actually, the point of no return is typically the what we call FID, the firm investment decision. So when we sign the contract to extend the construction to trains 4 and 5 when we commit the contracting dollars at that time we will be making a firm investment decision and we'll have all those commitments in place. And that's usually quickly after that MOU opportunity.

Okay. And then just to transition back to the expansion of trains 1 through 3 I guess you mentioned that with the FERC process you had known how potentially big it could be in terms of capacity but then when you filed the DOE applications you did not know that or you filed for a smaller amount. Was there a political ramification to that where you wanted to be more conservative and not raise a red flag or did something change on the engineering and design or end market side that made you want to expand that?

No, this is something that you're seeing with most of the LNG facilities. When most of us filed that DOE we filed based upon what you thought the actual average annual production was going to be.

So at that point we filed at 12 Mtpa and then at FERC they really wanted the nameplate capacity of the facility which for us for those three trains was 14.95. So we got the approval at FERC for the 14.95.

We went back and now are reconciling the DOE permit to that. You've seen that from several other of the parties that have already gotten their permit.

In fact I think Freeport just got theirs the other day for a reconciliation of the two. So it's fully expected, others have gotten it. It's not anything other than how the numbers were calculated.

Great, got you. Thanks.

Michael Weinstein, UBS.

Hi, good morning. Given the recent outcome in the CFE awards and considering that along with the growing solar portfolio, I was wondering how those two things impact your decision on TRV versus MLP and how it might be coloring the decision one way or another?

Will we're going to talk about our structural decision at our Analyst Conference and we're going to go into all of those details at that time. I would just say that we're very much aware of our assets, we're very much aware of how those assets might fit into the structure and what we're looking for as we're looking at structures and the possibility of whether we go forward with this or not as to what ads the greatest value to the Sempra shareholder and what structures would align best with our strategy. So we'll go through that at the Analyst Meeting so that you can have an understanding of how we're thinking about it and I'd prefer not to say anything further today.

Okay, thank you so much.

Matt Tucker, KeyBanc Capital Markets.

Hi, thanks for taking my question and congrats on a nice year. Just to follow-up on the expansion and the capacity of Cameron trains 1 to 3 just wanted to clarify that you had not included that capacity in the earnings guidance you've given previously.

Then secondly how does that capacity work with respect to your existing contracts? Does that fall under those contracts or would these be like spot cargoes if you could just comment on that.

Yes. First let me say that as I mentioned in my remarks that these trains 1 through 3, the incremental capacity from those trains happens after the facility is up and operational and producing where you don't have as much shutdown, you don't have as much opportunity for maintenance and things like that and that you have greater production.

That would go beyond the five years in our plan. And so the numbers that we've given you where we gave you $300 million to $350 million a year on average, that's what we would still anticipate in the early years of our plan.

Then over time we would be able to have some uplift potential providing that we can manufacture from the plant more than the 12 Mtpa and that our customers are willing to take that and export that. The terms of that have all been part of our original contract how that gets calculated and as I said we just gave you a rough number.

If you added 1 Mtpa per year of export, that would be about $30 million upside to us when it would occur. It's not in our plan numbers, it's not part of the $300 million to $350 million. It's upside to that.

But it would not be in our five-year plan period. So that's why I tried to make clear because we made these filings, they're public. We wanted to be a fully transparent and ensure you understood exactly what we were doing.

Understood. Thank you. Then could you comment on how your discussions with potential customers for your LNG expansion plans as well as your confidence in the viability of these projects has changed in light of this recent drop in oil prices versus the discussions you were having when oil was in the $90s?

Yes, the thing that I would say is first off the buyers of these facilities are looking at 20- to 25-year contracts. So spot oil prices are not a determining factor for them in terms of looking at a long-term investment in these facilities. If that was the case gas prices have gone down a lot, too.

So but how our customers look at that is they look at having a portfolio of LNG assets to meet some of their needs. The world demand in LNG is expected to increase considerably over the next 10 years and they are looking at having LNG that can provide that need that gives them some optionality.

The things that have been really good about the US projects are that they allow freedom of destination for export which has not been true with some of the other contracts. Probably even more importantly than that they have a liquid hub with upstream development that's already been there with a robust pipeline infrastructure, with E&P work that someone else is paying for.

Then they have Henry Hub tradable point. So from the standpoint of our customers they are very interested in having the opportunity to acquire LNG that has that kind of flexibility to it. That's what we hear back.

Then what we also hear back is that some of the customers like Port Arthur because they could take equity there and that they could do a multipurpose facility. Some of the customers like Cameron trains 4 and 5 because they feel that it would be it's one of the lowest cost projects that's been done and that for Cameron's trains 1 through 3, 4 and 5 should be somewhere similar and that they see this optionality that I talk about.

And some of them like ECA because they like the idea of a West Coast facility that could be built and access markets without going through the Panama Canal. So you have customers with different interests and different needs for the facility.

And there's been a great deal of customer interest in the facilities. LNG and oil are not fungible fully so that Tokyo Gas is going to need gas. They can't use oil.

So it doesn't really matter what the cost of oil is in that regard. So I think there's too much connection to that because of the way pricing was done.

The other thing I would say is that many facilities if you looked at the price of oil today and you looked at tariffing it on that basis they could never get built because they're just costs to build that facility would not be justified on on oil-linked price today. So if anything we think it improves the competitiveness of some of the projects that are in the US. Mark, do you want to add anything to that?

I would just summarize by saying you've got two parts to this, the consumption side and on the consumption side the natural gas once you've made the commitment to natural gas as a fuel for generation or industrial usage you're not switching back-and-forth between oil and natural gas. So the price of oil other than the old crude-linked formulas is really the only connection. It doesn't have that.

Then on the supply side there is a big advantage to the US LNG because the biggest advantage is the commitment that you need to make to buy LNG from the US is less than it is in most other places because all of the upstream development is already in place and you don't have to commit to pay for that over 20 years. It's already there.

So you're really only committing to the facility. That's a big advantage for customers on the supply side. I think if you just think of it that way you'll see that the US LNG will remain competitive for a long time.

Thanks Mark and Debbie. I just wanted to ask one more on the Mexico pipe and opportunities, you talked about the roughly $1.8 billion in CapEx on these upcoming four bids this year.

I know you've said in the past you're not baking any of that into your long-term earnings guidance so from that perspective anything you get would be upside. But I suspect you'd be fairly disappointed if you don't win anything.

And if that's fair what would you be happy with? How can we gauge success on those bids?

Well, what I would be happy with is to get them all for the kind of returns that we would like to have. It's not how many we get, it's how profitable they are. We run our business to provide shareholder value.

When we lose a bid we look at it and we say would we have wanted to have it for that. And most times I will tell you we say no, that's not something we would have done because we have other ways we can invest our capital that will give us higher return.

So for us it's about the discipline in the bidding and about we would be obviously disappointed if we don't get some of these but as you correctly stated we don't have these in our plan. So it would be upside.

Thanks, Debbie. That makes sense. I will give it up to (multiple speakers)

Faisel Khan, Citi.

Thanks. Good morning. On the just a couple of questions on the operating results and then some broader questions.

First question on SoCal, SoCalGas I understand the movements around taxes there, the tax benefits last your versus this year. But if I go above the line to operating income or even for that matter operating margin it looks like year over year in the quarter it looks like basically operating profit was flat year over year. So just trying to see how the growth is coming through on SoCal with all the capital you guys are spending in the business.

Yes, I'm going to have Joe talk about that. But I will say that 2014 was a transition year.

We were waiting for the PSEP decision to come out and it's starting up on a lot of the CapEx that you're going to start seeing flowing through the plant. So let me have Joe talk in particular about the year over year. And then Dennis is here and he can talk about what he's looking at and some of the changes in 2015 over 2014.

Yes, when you look at the tables I guess that's what you were looking at is the tables.

Yes, the supplementary data.

Yes, one thing that they don't show is that last year we had still some of the retro income from the rate case delay. So these throw you off. When you look at it it looks like 124 million, 124 million but last year there was income in the numbers from the retroactive piece.

So they actually do have nice growth from year to year and the taxes between the two utilities we had $20 million of tax benefits last year and $21 million this year. It just happened to be between the two utilities, if you look at the two utilities in total there's nice growth.

But I will let Dennis respond if there's anything else in there. You had at least $25 million in revenue impact last year from the retro and some depreciation impact.

So actually their numbers look better than they do on the sheet. Dennis?

Yes, what I would say is with the capital that we're spending and as Debbie mentioned in 2014 we're really well-positioned for the growth that we're going to see in 2015. With PSEP now fully charging forward you're going to see a full year of earnings related to that. And with the acceleration in advanced meter that's continuing to go well.

The other thing is by accelerating the advanced meter program in 2014 we did incur some additional operating expenses there that we won't necessarily have in 2015 as well. So when we look at those two programs plus the continuing growth in AFUDC related to projects like our Aliso storage replacement we're really confident that the range that we gave out in 2015 at the Analyst Conference we're on track for that for earnings.

This is Joe. It just dawned on me I was actually really thinking about the annual numbers because the retro piece was in the first quarter.

It wasn't in the fourth but I think the point that Dennis just made address the fourth quarter. But if you look at the annual piece I still think if you back out the retro it looks okay, looks good.

Okay, got you. Then if I look at the EPS guidance you guys laid out today for 2015, what's the assumed tax rate in that number?

I think you may have mentioned it but I may have missed it in your prepared remarks.

Yes, this is Joe. The tax rate for 2015 is about 29%.

Okay. And then going back to Debbie your comments on the extra 2.9 million tons of potential balance sheet capacity at the plant, so the 12 million tons is what you have contracted. So I just want to make sure I understood this so you'd actually have to contract for the extra 3 million tons to your existing customers is that what you were saying in your remarks?

I'll have Mark go through how that works.

So if you're talking you're talking about the extra tonnage because of the debottlenecking, the extra nameplate capacity, okay. We actually -- that extra tonnage was contemplated when we did the agreement so we get paid for making that available. If we make it available and it's used, we get paid a specific fee for that and that's the calculation that we gave you that said it's about $30 million per ton per annum.

So we won't get that all the time. It will be intermittent because you do have to maintain these facilities so there sometimes we'll be taking a facility down and it will earn less than its nameplate capacity. But we will have opportunities to really exceed it and when we do that we have a formula for getting paid.

Okay, understood. And then last question for me just as you guys are thinking about the performance in the stock which has been great over the last 12 to 18 months and the everything you guys have lined up for the next several years, how are you guys thinking about acquisitions at this point? You've seen some volatility at least in the midstream sector.

What's your philosophy right now on acquisitions? Is the table set and you don't need to you're not interested in anything or does it make sense to go out and look for things?

Well we always look for things. And I think that with the markets having a little bit of instability right now and watching what's happening with some companies who really need to raise capital and they are looking at getting rid of certain assets that this is a good time for us to be shopping if there are some good assets on the market and we look all the time.

But what we look at is assets that will add value to the shareholder or give us a strategic advantage where one plus one equals more than two and that we really are very particular. As you said, we have a great growth rate that is just based from the organic growth that we have in our business. We're in a wonderful position where we don't have to make acquisitions in order to grow.

So the way we look at it is is this going to be a benefit to our shareholders, is it going to add to our portfolio, is it going to give us greater long-term growth or is it going to give us the opportunity to extend our growth beyond our five-year period significantly above our peers? That's the way we look at acquisitions.

So if we find some things we're always interested. If they fit that.

I guess one reason why I am asking is a lot of the growth that you have you've got set up right now for the Company over the next few years or several years for that matter are acquisitions or investments you made many years ago that are driving a lot of that growth. So how do you guys think about trying to set up for the next decade with the portfolio you have?

That's a great question and we actually have a team that's working on beyond five and what are the things that we should be doing to create the foundations for future growth. That is part of our strategic review process that we're going through.

I guess not too many companies are fortunate enough to have the visibility five years out to the growth and what we want to do is set it up so that we have visibility not just 5 years but 10 and 15 years out and we are already working on that. It's a great question.

Okay, thank you.

Mark Barnett, Morningstar.

Hey everybody. Can you hear me?

Yes.

Speakerphone issue. So you've talked a lot about the Cameron project and thanks for all the detail on that for sure. I did want to pivot a little bit back to some of your comments about the opportunity in Mexico.

You kind of address this a little bit but when you're looking at the bid process you've obviously been successful, you have a recent success and you're looking back on some of the bids you didn't want and why you didn't get them talking about the returns process. But just wondering how final does this bidding process feel to you at this point? Feedback from the CFE, improvements that you'd like to see, is there anything I guess in the process itself that would make it easier for you to evaluate these projects?

I'm going to ask Mark to answer that. We've gone through the full analysis of the bids and I would say that the bidding process is a pretty solid process from what we see. And it's pretty clear and I would say the US pipeline bids were not as clear at the beginning but they became clear towards the end.

The one thing that I think and it was said on our IEnova call today that we're all having to look out a little differently is when they bid these pipelines they bid them to a certain capacity. And what many of the bidders are doing is looking at beyond that capacity that's going to be contracted and what is the market potential to add compression or to broaden the opportunities on the pipeline.

So I think that's one thing that we're seeing from bidders now is that they are looking not just at the first contract but what could you do to grow that. Mark, do you want to --

Yes, I'll just elaborate a little bit on that. I would say one of the things that we're seeing from the bid process as a whole it's actually quite good. It seems to be relatively -- it seems to be fair.

They are looking at the right things and they break it into two parts. There is a capital part and then the net present value of the future payments that the customer would take whether that's CFE or PEMEX. So they've done this in I think a logical way.

But to Debbie's point one of the things that I think that will necessitate winning bidders to do in the future is to anticipate some additional revenue and capacity that would be used by the market because all of these will be open access pipelines. They will eventually attract other customers and you've got to figure that into your net present value of your cash flow stream.

So I think it's going to keep a competitive process for Mexico. I guess the thing that I would add to this so we're looking at that and I think we can make adjustments for that but I do think the thing that's most important is we've got these other group of bids that are coming out here shortly but we have a whole list of other projects that are going to come out during the year. And the most encouraging thing we've seen in spite of and maybe because of the drop in oil prices the need for outside investment in Mexican infrastructure continues to grow.

There seems to be no reluctance on the part of CFE or PEMEX to get moving on some of these projects because they are critically needed to deliver gas into the bowels of Mexico and we really want to make sure that those projects that they are developing down there that are going to use this gas are all moving forward and they are. So I think all of this speaks very well for the additional investment. We are even though we watch our returns and we want to make sure that we get a good return on our investment, we're still in one of the best competitive advantage -- we're in one of the best competitive places to be from having an advantage to just being the incumbent and the largest incumbent.

And our relationship with the contractors and the pipe producers and the things that we've been using in Mexico, really I think we can be very quite competitive. And I think we will do well.

So one other thing that we didn't mention is that in addition to the four pipelines they are also putting a bid out for gas supply at Baja Sur. And in that they are allowing you to construct how you would get the gas there whether it's by pipeline or it's by LNG.

And I think we're starting to see a little more breadth in the type of bids that are coming out. And that pays to our sweet spot place where we can be creative and how we use the assets that we already have in Mexico and we take those and work them together in a way that puts a really attractive package on the table. And I think we feel very good about this but we also are going to be very disciplined.

Great. That's some really nice commentary. I appreciate that.

Maybe to kind of pick up where you mentioned on competitive advantage side given how successful you've already been and seemed to be so far does that change the appetite for maybe partnering with other large multinationals and pursuing some of the larger projects? Is that still an option that you are considering when you look at particular the larger bids perhaps?

We always look at partners but what we want to be sure is both partners bring something to the table. In terms of just bringing capital to the table, we feel that we have great opportunities in Mexico to raise capital but if there's something strategic that they bring to the table that combined with us would make us more competitive we would certainly look at that.

Okay, thanks a lot. I appreciate it.

Winfried Fruehauf, W. Fruehauf Consulting.

Thank you. Assuming the market price for LNG produced at Cameron is petroleum-based or petroleum-related and assuming current petroleum prices would remain at or below current levels for five years, would this in your opinion affect the ability and willingness of the off-takers to proceed under the terms of the contract?

If you're talking about the trains 1 through 3, no. I would not expect that. We have a very tight contract.

The other thing and the way we structure trains 1 through 3 is our customers are our partners. And so we had envisioned that if there was upturns or downturns in the LNG market the fact that they are paying themselves is an advantage under this.

So what you have with this is you have some as you're pointing out some credit risk. I certainly think GDF, Mitsui and Mitsubishi are very strong credits and that they look at this as a long-term investment for them. So I wouldn't see that, Winfried.

Okay, thanks very much.

Paul Patterson, Glenrock Associates.

Hi, how are you doing. Can you hear me?

Yes.

Just on the -- almost all my questions have been answered, and I apologize if I missed this but the non-capitalized development cost for the additional LNG projects, what was the amount that you guys are seeing that you guys are expecting for that in 2015? How should we think about what that might look like going forward in the future?

Okay, I will ask Joe to answer that one.

Hi, Paul. The reason that we are excluding it from guidance as Debbie mentioned are severalfold but we actually are not able to estimate it right now and that's why we didn't give a number and we didn't put a range for it.

Because we expect to be spending this money but as Debbie said we're going to be disciplined. We also have partners in these projects.

So we are not sure at this point in time how much we're going to spend versus how much we're going to collect from partners. Then as we work through getting customers signed up for MOUs at some point we will be able to capitalize the cost.

So we cannot right now estimate the amount that we may ultimately spend. Mark, I don't know if you have anything to add that you'd like to --

No. I think that's right. We really just can't estimate it now and because of the difference in capitalization or expense we just thought it would be best to exclude it.

Okay. So you are just calling it out --

The one thing also I just think from a transparency standpoint you'll be able to see this because we'll be reporting earnings and you'll be able to see as we're reporting how much we're spending. And then so it makes it more transparent to you and I think that's a positive way to handle it, when you can't really estimate something and it's something that's really leading up to your FERC filing and then you guys will be able to see.

Okay, I understand that. I don't want to make too much of it. I just was wondering, though, how long do you think this will be a separate issue that you guys will be calling out just --

What we're looking at is we're looking at getting the filings done this year on all of these. So this is the expenditures that would occur before the filing and a lot depends on as was said when you get partners, when you get MOUs and what the capitalization policy is versus the expense policy.

The fact that we have three going at one time this year is quite unusual. I wouldn't see this as being an ongoing thing and it's really expenditures for projects that really will be beyond our five-year plan.

Because, Paul, one thing is if we develop these projects beyond this year likely all these costs will continue to get capitalized.

Great. Thanks for the clarity.

All the other questions were answered. Thanks a lot.

Ashar Khan, Visium.

Good morning and congratulations on great results. Debbie, one thing as you go out and we look forward to the Analyst Day but we had one in the beginning of the year of a company, but I hope one thing which would come out as you're doing your strategy is on this total return vehicle me being a Sempra holder how does this enhance my valuation when you select whatever that is?

I'm hoping it is through a better growth rate in earnings or something like that which you can quantify that this vehicle would provide valuation uplift to the parent company which has been somewhat missing in what you saw earlier this year. I hope that comes out very clearly as you pursue this path that we as Sempra shareholders what are we going to get by having this TRV vehicle?

Well, if we decide to do a TRV then how we explain that we have heard this from a number of our investors and it is one of the most important things on our mind and consideration about this. And if you go forward on it is where's the value creation to the Sempra shareholders, where does that come from? I know obviously that there are all sorts of rules regarding communication and what you can do and what you can do when and if we decide to go forward with this we have to comply with those rules. But we hear you and if we decide to go forward that I hear what you're saying and that we will make every effort to address it.

I appreciate it. Thank you so much.

Michael Weinstein, UBS.

Hi, just a quick follow-up. I think you were alluding before to a possible decoupling of LNG pricing from oil pricing given the drop in oil on the spot market. I'm just wondering if that is indeed what you're trying to say and what you're seeing out there that we might be seeing an actual decoupling.

Yes, to some degree. I'll have Mark talk.

Yes, look, there are numerous LNG contracts around the world that are linked to oil prices and they call it the crude cocktail price or you've heard those terms. But the change that's coming that's happening is really not one of a decoupling but it's a diversification which is going that's entering another mix into this and that is a Henry Hub-based LNG price.

So most of -- in fact all of the LNG so far I think that's been sold out of the United States has had some kind of index back to Henry Hub. So it's giving the purchasers a mix in their portfolio of a different pricing and that was very popular obviously when crude was very, very high but the popularity hasn't diminished because crude has gone down in price.

I think there is a big desire by especially the Japanese and the Koreans to diversify their pricing mix and to have some different points different pricing points. So I think that is purely what it is. It's a very small percentage now of their overall mix.

It's growing but we're not anywhere near where they are full up with Henry Hub-based price. I think there is still a lot of room to go.

Right, okay, thanks.

That will conclude our question-and-answer session for today. I'd like to turn it back to Debbie Reed for any additional or closing remarks.

Well thanks again for joining us today. I hope to see you all at our Analyst Conference in New York on March 26. As you heard today we have a lot of interesting things to be covering at that conference and in the meantime please feel free to contact our IR team and have a great day.

That does conclude our conference for today. I'd like to thank everyone for your participation and have a great day.