桑普拉能源 (SRE) 2015 Q4 法說會逐字稿

Good day, everyone, and welcome to today's Sempra Energy fourth quarter earnings conference. Just as a reminder, today's call is being recorded.

At this time, I'd like to turn the conference over to your host for today, Mr. Rick Vaccari. Please go ahead, sir.

Good morning, and welcome to Sempra Energy's fourth- quarter and full-year 2015 financial presentation. The live webcast of this teleconference and slide presentation is available on our website under the Investors section.

Here in San Diego, are several members of our management team. Debbie Reed, Chairman and CEO; Mark Snell, President; Joe Householder, Chief Financial Officer; Martha Wyrsch, General Counsel; Trevor Mihalik, Chief Accounting Officer; Dennis Arriola, Chief Executive Officer of SoCalGas; Jeff Martin, Chief Executive Officer of SDG&E; and Octavio Simoes, and President of Sempra LNG.

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 filed with the is SEC.

It's important to note that all of the earnings-per-share amounts in our presentation are shown on the 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 2015 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, 2016, 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 4, and let me hand the call over to Debbie.

Thanks, Rick. Before discussing the quarter, I would like to say a few words about the natural gas leak at our Aliso Canyon storage facility.

On February 18, the Division of Oil, Gas and Geothermal Resources, or DOGR, confirmed that the leaking well was permanently sealed. Our focus since the beginning has been on safely stopping the leak, reducing the odor from the well, reducing the amount of natural gas being emitted into the environment. Working cooperatively with agencies and elected officials, and supporting local residents, including providing temporary housing and air filtration systems.

Now that we have stopped the leak, an independent investigation of the root cause will be conducted. I want to emphasize that providing safe and reliable service to our customers is the highest priority for SoCalGas.

We will continue to work with our regulators and customers to ensure our path ahead reflects these values. Later, I will provide more information on Aliso Canyon, and Dennis and Martha are also here to address your questions.

Turning to our financial performance, in 2015, we had very strong results and exceeded our adjusted earnings guidance. This morning, we reported full-year earnings of $5.37 per share or $5.21 per share on an adjusted basis. Our 2015 results were driven largely by growth in operating earnings at our California utilities and Sempra International.

In addition, our Board approved an increase in the 2016 dividend to $3.02 per share. This payout represents an 8% annual increase, and provides dividend growth that more closely aligns with the 11% annual increase in our 2015 adjusted earnings.

Moreover, we are targeting annual dividend increases of 8% to 9% over the next several years to better align our dividend growth with our projected EPS growth. Our dividend strategy is underpinned by confidence in our future cash flows, and supports our commitment to return capital to our shareholders.

Regarding 2016 earnings, we have updated our assumptions and are providing an adjusted EPS guidance range of $4.80 per share to $5.20 per share. When compared with the 2015 results, we forecast a higher effective tax rate for 2016. In part, this is due to a large number of benefits recorded last year that related to the resolution of tax matters.

Also, as we move into the new GRC cycle at our California utilities, we will now be providing an estimated $60 million of repair allowance tax benefits to rate payers as part of the standard rate case trueup. In our 2016 adjusted guidance, we assumed that we retain all repair allowance benefits for tax years proceeding our new GRC.

Key updates in comparison to the 2016 guidance we provided at last years analyst conference, reflects several other factors. Notably, we include our best estimate of the GRC decision for the California utilities based on our settlement agreement, as well as new market assumptions for commodities and foreign exchange rates that have changed considerably since last year. Additionally, our adjusted guidance range now includes approximately $20 million to $25 million of estimated LNG development expense.

Regarding transactions we announced last year that were additive to our base plan, such as the potential Pemex acquisition and new renewable contracts, we expect the earnings impacts to largely occur in 2017 and beyond. Please note that our proposed GRC settlement agreement is subject to CPUC approval, and we do not anticipate receiving a final decision until the second quarter. We have moved our Analyst conference to May in order to incorporate an expected final GRC decision, and will provide you with our business unit guidance and longer-term projections at that time.

Overall, we are well positioned to achieve our long-term strategy of providing earnings growth that is twice that of the average utility, but with a moderate risk profile. Combined with strong anticipated growth in the dividend, we are focused on providing top tier shareholder returns.

Now please turn to slide 5. This slide summarizes the key assumptions included in our 2016 adjusted EPS guidance. I will briefly discuss each item, and you can find additional detail in the appendix.

First, as I mentioned earlier, this year, we include development costs for our LNG liquefaction and related infrastructure opportunities. In 2015, we had about $10 million of similar expense that was excluded from adjusted guidance due to uncertainty about the nature and timing of these costs. Given progress on the projects and our estimates of the spend rate and amounts capitalized and shared with Partners, we now include a 2016 after-tax expense of roughly $0.08 to $0.10 per share.

Please note, however, that the vast majority of planned expenses targeted for Port Arthur and the related infrastructure as we have already incurred most of the up front costs for Cameron expansion. Going forward, we will be sharing costs for Port Arthur with our Partner Woodside.

We will nevertheless monitor our progress in securing market commitments and other needed approvals to advance the project. To the extent our progress is slower than expected, we will adjust our spending accordingly.

Next, we have seen a significant decline in natural gas price forecast over the past year. Specifically, the Cal border 2016 forward curve has fallen from $3.60 in our prior guidance to $2.60 in our new adjusted guidance. The impact from this assumption is a reduction in earnings of approximately $0.05 to $0.07 per share that is associated with the LNG marketing contract from our ECA import facility in Mexico.

Third, we reduced projected earnings from the TDM Power Plant due to lower power prices and lower expected capacity revenue. This month, IEnova decided to hold the asset for sale.

The sale would complete our exit from merchant generation, and allow IEnova to deploy capital and projects that provide more stable earnings. While we project approximately $0.04 to $0.06 per share of reduced earnings associated with TDM, we do not consider any potential gain or loss from the sale in our adjusted guidance.

Moving to parent. We assume that we will use dividends from Mexico to participate in a potential IEnova equity offering. We forecast a 2016 earnings benefit from lower repatriation tax expense of between $0.08 and $0.10 per share. Offsetting this impact is an estimated $0.04 per share after tax of higher interest expense to fund projects in our base plan.

Next, like natural gas prices, we have seen exchange rate forecasts move significantly over the past year. Relative to our previous guidance, our current forecast is for the dollar to strengthen in 2016 by an additional 20% against the Chilean currency, and by an additional 13% again the Peruvian currency. Projected earnings are reduced by roughly $0.09 to $0.11 per share as the result of translating South American earnings into dollars.

In Mexico, we have not previously forecast the impact of foreign currency effects. We now include in our adjusted guidance a reduction in tax expense associated with peso depreciation during 2016. Based upon the forward curve at year end, we estimate this benefit to be approximately $0.05 to $0.07 per share.

With regard to IEnova's acquisition of Pemex, this ownership, and their shared joint venture, Mexico's Competition Commission has required Pemex to competitively auction two assets included in the original transaction. IEnova is negotiating changes to the original agreement with Pemex that will reflect the auction outcome among other things.

Our adjusted guidance assumes that the transaction moves forward with the same assets, and closes in the third quarter of 2016. Based on this timing, we assume an estimated $0.02 of accretion this year. Our adjusted guidance excludes, however, any potential gain associated with the remeasurement of our investment in the joint venture.

In our renewables business, we incorporate new forecasts for wind resource and availability that reduced earnings by approximately $0.02 per share. However, our base plan now includes 328 megawatts of additional projects announced last year that are under construction. Given that these projects are expected to be in operation by the end of 2016, we expect to see the full earnings impact beginning in 2017.

Finally, for the California utilities, our prior guidance was based on a very conservative assumption that revenues would be based on our current attrition mechanism with no further adjustment. Our new adjusted guidance range includes projected earnings that more closely align with the GRC settlement agreement, and our best estimate of the outcome given the record in the proceeding.

Now let's go to slide 6 for a business update beginning with the California utilities. In our general rate case, we are currently expecting to see a proposed decision in March, and to receive the final decision in the second quarter.

As you recall, we reached a multi-party settlement agreement with the major parties in the case. Until we get a final GRC decision, we will record revenues based upon the authorized revenue requirement in 2015. When we receive the final decision, we will make an adjustment to reflect the retroactive earnings back to January 1, 2016.

Turning to Aliso Canyon. We have received confirmation from DOGR, the California agency responsible for regulating gas storage, that the leaking well has been permanently sealed. We have approximately 15 Bcf of natural gas in the storage field, and the field is stable.

Moving forward, an independent engineering firm has been selected by DOGR and the CPUC to investigate the root cause of the leak. While we do not know how long this process will take, we will cooperate on the investigation and share publicly available data.

Consistent with new rules under development, we are implementing enhanced leak detection and well inspection activities. We are also working cooperatively with all of the agencies involved to determine a path forward for the facility, which is regarded as integral to the reliability of the electric grid in California.

Reflecting the most up-to-date information which primarily includes revised temporary relocation and well drilling expenses, we now estimate the total costs for amounts paid and those forecasted to be paid to be approximately $330 million. Of this amount, approximately 90% is for the temporary relocation program, costs to address the leak and attempts to stop or reduce the emission. The remaining amount includes, among other items, the value of lost gas and estimated costs to mitigate the GHG emissions.

For the estimate, we assume the relocation period for the majority of residents ended on February 25, as agreed upon with the City of Los Angeles. We have concluded it is probable that we will receive insurance recovery for the total amount less retention of $325 million. Beyond this estimate, we cannot predict all of the potential categories or total amount of future costs that we may incur as a result of the leak.

We have at least four types of insurance policies that provide in excess of $1 billion in insurance coverage. Based upon what we know today, and subject to various policy limits, exclusions and conditions, we believe that our insurance should also cover the following categories not included in our estimate. Costs associated with litigation and claims by nearby residents and businesses, and in some circumstances, depending upon their nature and manner of assessment, fines and penalties. I'll refer you to our 10-K for further detail.

Please turn to Slide 7. In Mexico, CFE is tendering several more gas pipelines. IEnova submitted a bid for one pipeline earlier this month, is in process of submitting a bid for second, and is preparing to submit a third bid in March. According to CFE estimates, the three pipelines represent an investment opportunity of almost $2 billion and we expect award dates to occur in March and April.

This Spring, IEnova is also preparing to participate in Mexico's first auction, a renewable energy certificate. IEnova is looking at potential solar opportunities, and may submit a bid to expand the ESJ wind facility with its joint venture partner Intergen. The CFE will be the initial off taker under 15 to 20 year contracts, and total awards could amount to 2500 megawatts of new power generation.

In our LNG business, there have been two noteworthy developments. Our Cameron expansion project received its FERC environmental assessment on February 12, and we expect to receive the FERC permit in the second quarter. Though current market conditions are not ideal, Cameron Train 4 is a very competitive market offering for long-term buyers.

Based on recent meetings with potential customers, we are bypassing the memorandum of understanding stage and are in negotiations for definitive 20-year sales and purchase agreements. While a sales and purchase agreement will take longer to execute than an MOU, we are targeting the second half of 2016 for announcing customer agreements needed to launch the project. This approach provides us greater certainty on project commitments prior to incurring large capital expenditures.

For Port Arthur, yesterday, we signed a joint development agreement with Woodside Petroleum that outlines development roles in the potential project. In addition to how we will share costs and market capacity, the agreement provides a framework for how we will work together technically to design a cost competitive plant. Last month, I was in Australia meeting with the CEO and senior management of Woodside, and we share the view that Port Arthur has good market prospects post 2020.

Before moving on, remember that we have not incorporated additional LNG or other growth projects in our guidance. We are actively working on development opportunities across our businesses that could provide upside to both our near-term and long-term projections.

With that, please turn to Slide 8 and Joe will discuss our financial results. Joe?

Thanks, Debbie.

Earlier this morning, we reported fourth-quarter earnings of $369 million. On an adjusted basis, we reported fourth-quarter earnings of $370 million or $1.47 per share. Adjusted earnings in the fourth quarter exclude $3 million of expenses related to the development of our proposed LNG liquefaction projects.

In addition, in October 2015, an agreement was reached with the SONGS insurance provider for a $400 million payment associated with the failure of the replacement themed generators. Of this amount, SDG&E's share was $80 million. After reimbursement of legal fees and an allocation of $75 million of net proceeds to the rate payers, our fourth-quarter adjusted earnings exclude a $2 million after-tax adjustment to the loss on the SONGS plant closure.

Full year 2015 earnings totaled $1.349 billion or $5.37 per share. This compares to 2014 earnings of $1.161 billion or $4.63 per share.

On an adjusted basis, 2015 earnings were $5.21 per share. Year over year, adjusted earnings grew 11%. Individual financial results for each of our businesses can be found in the section of our presentation entitled Business Unit Earnings.

I will address the key drivers for our consolidated quarterly results now on slide 9. Compared to the prior year, fourth-quarter earnings include a $48 million seasonality impact that increased earnings at SoCalGas.

Recall that applying seasonality to earnings at SoCalGas does not affect full-year results. Instead, this fourth-quarter variance offsets seasonality impacts during the first three quarters of the year.

At Parent we recorded $21 million of lower tax expense, primarily related to favorable resolution of prior-year's income tax matters and reduced repatriation of dividends from Mexico. The lower tax expense at Parent along with lower effective tax rates at the California Utilities were primary reasons why we exceeded our revised 2015 adjusted guidance that we gave on our third quarter call.

Third, SoCalGas recorded $16 million of higher earnings due to higher CPUC base margin net of operating expenses. And offsetting these factors was $18 million of lower tax expense in South America in 2014, as a result of Peruvian tax reform.

Now let's conclude, so please turn to slide 10. Overall, we delivered strong financial results in 2015 and exceeded our adjusted guidance. Solid growth in operating earnings and confidence in our long-term cash flows supported our decision to raise the 2016 dividend. In order to better align our future dividend growth with projected EPS growth, we are now targeting annual dividend increases of 8% to 9% over the next several years.

Looking ahead over the next five years, we continue to anticipate earnings growth around twice the level of our utility sector average. Combined with the strong dividend growth, we aim to provide top tier total shareholder returns. With that, we will conclude our prepared remarks and stop to take any questions you may have.

Thank you

(Operator Instructions)

We'll go first to Greg Gordon of Evercore ISI.

Thanks, good morning.

Morning, Greg.

Debbie, I know that it's not -- that you're in the normal course, you usually don't update your five-year earnings growth forecast until the analyst day. But can I take from your comments early in your presentation that you still feel like the fundamental building blocks in the prior five-year plan that drove the earnings growth you articulated last February are still substantively in place?

Greg, I think that's an excellent way to put it actually. If I look at the fundamental building blocks, as you know, our business is based upon long term contracted and utility assets. And when we lay out our growth rates, the key things that are driving our growth longer term are Cameron 1 through 3, which is progressing on schedule, on budget, and we expect that to come on line in 2018 as we've outlined before.

Our Mexican pipelines, and now all except for three of them are actually in operation that are contracted, and so that is going quite well And then our utility businesses, and the fundamentals of our utility businesses, as you can see from last year's earnings, are very strong. And we would anticipate getting a rate case decision soon. And one reason we want to hold off providing any numeric guidance is that we want that rate case decision and then be able go through as we always do with you at the analysts meeting the details.

The other thing I'd common on, our Board felt that there's great visibility to our growth. And since it's long-term contracted in utility, they were very comfortable setting an 8% to 9% target for our dividend increases over the next several years. And I think that is a really strong statement in our sector to be able to grow your dividend at that kind of rate.

Right. And that's up from the last articulated target of 6%, correct?

Yes, we had talked before of about 6% growth rate in the dividend, and now we're talking about 8% to 9% over the next several years.

Okay. Shifting gears to Aliso, you've articulated what your estimate is relative to the line items you've laid out. As we go forward here and we think about the path to understanding whether or not there will be further costs as they relate to fines or penalties, which of the primary agencies that will be reviewing the safety, efficacy, performance of the plant? And if there were to be fines or penalties, in what categories would they potentially fall, and who would be the agency that would be deciding whether or not to implement them?

Well let me just start by saying that the key agencies that are doing the investigation are the Department of Oil, Gas and Geothermal resources, or DOGR, and the CPUC, and they are now beginning the investigatory phase to see what's happening on the leak. I'm going to refer to Martha regarding the whole scope of agencies that would be involved, and how we deal with fines and penalties. I will say though that there haven't been any that have been assessed, so it's hard to estimate anything. Martha?

Thank you, Debbie. That's correct.

DOGR and the California PUC are the primary agencies that would be -- are investigating, and would potentially fine the Company for what they discover in the investigation. And as Debbie said in her remarks earlier, our insurance coverage is quite broad with the four insurance policies that we have. And we do believe that in certain circumstances and depending on the nature and manner of the assessment, that insurance should cover fines and penalties.

Okay. Last question, in the California Utilities bucket of things that have changed, I just want to be clear on my understanding. The first thing that changed has changed, or one of the things that's changed is you're no longer budgeting for $60 million of repair allowance and tax benefits.

But the other thing that's changed is you've updated your assumptions for -- to take into account what you believe the impact is of the underlying economics of the settlement. Are those the two major changes?

Greg, that's correct. As we've looked at this, we told you last March that under the rate case process that when we go through the rate case process that there would be a trueup on this repairs allowance, and that was approximately $60 million. So, our earnings would be reduced for that going into 2016 at our utilities.

But then we've reached this rate case settlement. And when we've laid out our guidance for 2016, our assumptions are and our range is that something similar to the rate case settlement would be adopted, and that's what we would anticipate.

Hey, Greg, -- .

$60 million is after-tax, right? Sorry.

Yes, because it's a tax item. But Joe wants to say something.

Greg, this is Joe. I just want to make sure just to be clear for you and others, the $60 million was taken into account in the guidance we gave you last year for 2016. So that's not something that was new in our new introduced guidance today. But the GRC settlement was new, but the $60 million was in last year's number.

Okay. So $60 million was baked into the February guidance?

Yes. But it's important to understand, because it's a difference going from 2015 to 2016. So it's a critical item to understand.

Got you. Thank you. I'll get off now, thanks.

Thanks, Greg.

We'll move next to Steve Fleishman of Wolfe Research.

Yes, hello, good morning. Apologize to answer. To ask a question that you probably don't want to directly answer right now, but just you're on the one hand saying the 8% to 9% -- . Yes, can you hear me?

Now we can hear you. We honestly did not cut you off.

You might regret that you didn't after I ask this question. But so just on the long-term growth rate, so we have two data points today.

We have twice the utility average, and we have 8% to 9% dividend growth that better aligns with long-term earnings growth. Is it fair to say the 8% to 9% is not a view of your long-term earnings growth?

Yes, that's fair to say. And I'll answer that question, and I'll give you an answer -- and I'll use 2015 as an example.

We grew 11% in 2015, we increased our dividend by 8%. So, I would not link the two directly together. What I would look at is what are the fundamentals of the growth drivers, and the fundamentals of the growth drivers are Cameron getting online on time, our utilities performing well, and our Mexican pipelines being constructed and in service, and all of that is going quite well.

Okay, great. And then on the Cameron floor update and the decision to move to directly to a contracting as opposed to an MOU. Could you just maybe give a little bit more color on why you're doing that, and is that something the customers want, or is that something that's better for you so you don't have to commit as much up front? I wasn't sure I understood the rationale there.

Sure, I'm going to ask Octavio to cover that. But what I would say is we see it as better for us, because we do have a timeframe by which we have to commit to get Cameron in service and maintain continuous construction. So actually, getting the sales and purchase agreements done and have a definitive agreement is a real positive for us. So this is something we like to have in place.

Octavio, why don't you have a talk about it from the customer perspective as well.

Sure, thank you. The reason why is because, as Debbie indicated, we have a timeframe that's tight, and we're trying to take advantage of the long-term pricing that we have from our EPC contractor. So going to an MOU would create an additional step that might drag that schedule, and as you know, given the way we structure our deals on the LNG, we're not just selling cargos for a price, which would be a much easier sell. We're actually putting together deals that deal with low commodity risk and essentially long contracting capacity for the liquefaction.

So we have to speak a lot to our customers about the upstream conditions, where the gas comes from, where it's delivered, how it's delivered. And those tend to be more complicated sessions, and as a result, we've all decided to go forward.

It wasn't just us, the customers also decided to go their way. So the people we're talking to at this point, we've all agreed to pursue the supply purchase agreements and gas supply agreements as part of our discussions in order for later in the year to have the full commitment to take the commitment we need to make on the capital side to launch the project.

Okay, great. And one last question on Aliso. Could you maybe just talk a little bit more about the -- and I know this is hard without the root cause analysis.

But one is, the potential scenarios of fixes for the future. And then, the second question is, it does seem like Aliso is a critical facility for reliability in California. Could you talk a little bit about that issue and this conflict with some people wanting it not to start up?

Sure I'm going to have Dennis address that. What I will say is that the DOGR has come out with a new set of rules that we're already implementing, and that they are very, very parallel to what we filed a few years back in our rate case for our program that's called Storage Integrity Management program, or SIMP. And so I think that there are processes and things that we actually envision and already had filed for in our rate case that would allow us to safely operate this field going forward.

Dennis, do you want to address further?

Sure, morning, Steve.

As Debbie talked, about our SIMP program and at the utilities we have an acronym for everything. But we actually started on a pilot program back in 2014, even before we've got an approval. And as you know, we have requested within our general rate case for additional funding for our Storage Integrity Management Program, so that, we're waiting for the final decision there.

As far as the importance of Aliso and gas storage in general to both gas and electric reliability. I think it's been very clear with a lot of the comments by both policy and regulatory leaders, especially coming from the California Energy Commission as well as the PUC, that it's vital that we have safe and reliable gas storage to support not just gas demand. But especially in the Los Angeles Basin, electrical liability, as well.

So we're pleased to see that even in the visit that Department of Energy, Secretary Moniz, when he came out and visited, he reemphasized the importance of making sure that obviously the facilities are safe. But that we have them back online in order to support both gas and electrical reliability. So we know that there's, as Debbie mentioned, there's a full process that's been approved by DOGR on their comprehensive safety review, we're working very closely with them on that.

There's also some legislation that's been presented that so far is open to amendments to incorporate the process that DOGR has laid out. So we're optimistic that sounder minds now from a policy, regulatory, and political side recognize the importance of getting Aliso back online as safely and as expeditiously as possible.

Okay, thank you very much.

Moving on to Neel Mitra of Tudor, Pickering.

Hello, good morning.

Hello, Neel.

Its been awhile since we've gotten an update on Mexico. Obviously, you have three bids coming up that are pretty important. Could you just comment on the competitive environment there, and what you're seeing and possible opportunities beyond just the CFE pipes at this point?

Sure. I'll have Mark talk about some of the upcoming bids. But a couple of things I've said before and I'll say again in terms of Mexico. And the key thing for us is that we have a really great set of assets in Mexico that are expandable assets, that have additional growth potential. And so these bids are very important to expand the infrastructure that we own there, but they are not the only way that we can grow in Mexico.

And Mexico now has some pipeline bids that are going to be coming for us very soon. We talked about the three that are out for bid right now. There will be others that will come out later this year.

Mexico is also going out for bid for about 2500 megawatts of renewables. And we have our ESJ plant operational there that has the ability to expand by about 1000 megawatts, so we think that's a great opportunity. And then Mexico is looking at going into other areas of bidding with electric transmission and electric generation.

So there's bidding, but there's also growth potential that occurs from the great asset base that we have there. Mark, do you want to talk about the bids?

Sure, Debbie.

As you noticed, there's three pipelines right now that are currently under that we've submitted bids for, and we're awaiting the determination. In total, it's roughly a couple billion dollars worth of work, and we think we're well positioned for it. But as you've seen, there has been some increased competition for some these pipeline bids, but we're sticking to our strategy of targeting high single digit IRRs and we're really looking to try to pick up these ones that we think fit our profile and what we're looking for. And obviously, we're interested these at the right price.

But I think the most important thing is Debbie's point is on the opportunities around our existing pipeline footprint, which, just to remind everyone, we are the largest pipeline operator in Mexico. We're very well positioned, not only for this new work, but to expand those opportunities and start building laterals into other industrialized areas.

And so we see the opportunity for IEnova in Mexico for continued growth. And I think we've all seen some of the comments on Pemex over the last few days, and their desire to raise additional capital and to think about selling some of their additional assets.

We're very well poised to take advantage of those opportunities. Our relationships there are very strong, and so we're very optimistic about IEnova's growth potential.

Okay. So to summarize really basically, you believe that there's a lot of lateral opportunities just beyond the CFE pipes which you can service off of your existing infrastructure. Is that the right way to think about it?

Yes, that and also in a eventually additional capacity through compression on a lot of the lines that we currently operate.

Got it. And then moving to the GRC settlement, the extension from Q1 to Q2. Is there anything to read into that bonus depreciation, extension, et cetera?

Do you feel comfortable with the settlement at this point? Or any thoughts on that?

Yes, and we feel comfortable that we're going to get a proposed decision in the March timeframe. That's what we are looking at. And the issue of bonus depreciation was part of the litigation in the record of the rate case.

And the settlement was made understanding that there was some potential for extension of that. So we think that the settlement -- we think it's likely to get adopted, and that we think that we should have a decision hopefully some time in the second quarter.

Okay, great. Thank you.

We'll go next to Julien Dumoulin-Smith of UBS.

Good morning, good afternoon.

Hello, Julien.

So just following up a little bit more on the Aliso conversation, can you elaborate a little bit more on thoughts on next steps just both from a regulatory process? But perhaps, more importantly from an operational perspective, how do you think about getting the asset back into service? And then also, how do you think about your own investment plan in light of what may be required out of that regulatory process, and/or working around any limitations on the Aliso Canyon asset itself?

Let me just make a comment on that, and then I'm going to refer to Dennis on it coming back into operation. I think one thing that's quite positive is that when we filed our rate case, we had actually filed for a program that would do internal inspections of wells, and some of the things that has now happened on pipelines. And we've filed for a program that would do that for storage facilities.

And that in the rate case settlement, we ended up with a two-way balancing account that would allow us to make those kinds of investments, to do the review of those storage wells, and go through them on a programmed planned basis, which is what we had proposed. But getting that all in place now and getting the facility operational for injection season, we've been spending a lot of time looking at how we use that program which is basically aligned with what the Department of Oil, Gas and Geothermal Resources, or DOGR, as outlined as well.

So, Dennis, why don't you talk about what we're doing now, with Aliso and all of our storage facilities.

Morning, Julien. Let me start with Aliso, and it's really a two-pronged approach.

The first is, we're obviously, as Debbie mentioned, we're cooperating with the investigation that's being led by DOGR and the CPUC, and they have an independent expert on the outside, a company called Blade Energy Partners. So we're supporting them, and they are really driving the time schedule there. S whatever time it takes for them to do their work and to issue the report, will take its own path.

But as far as getting the field back into service, as I mentioned, DOGR issued its comprehensive safety review that we're working with them on. And it's a very detailed process of testing, inspecting and if necessary repairs. And as Debbie mentioned, it is very -- parallels what we had put in place as far as our SIMP program and what we were doing from a pilot standpoint.

So we're working to expeditiously implement that. It's hard to tell at this point in time how long it will take us to get through all of the 115 wells. But the way that the program is put together, it does allow us, once we've accomplished a minimum threshold of tests on all of the wells, we can start bringing some of the wells on.

We don't have to do complete work on 100% of those. We can isolate or abandon certain wells, and bring on other wells at the same time.

So we'll be giving further updates on that down the road. But I think the key point there is, again, policy makers, to regulators, and we're very closely working with all of these so that they understand what could happen both here in the summer from an electric reliability standpoint and from a gas standpoint. We're all really working together to make sure that Aliso and all of our gas storage facilities are safe and reliable, and they can service our customers.

We're also - there also is an emergency regulation that was put in place by DOGR that applies to all gas storage facilities, not just Aliso, and so we're complying with that, as well. And that includes things such as daily pressure reads, testing the wellhead valves, and some other procedures that have to be put in place, so there's a lot going on. We've got a lot of people at all of our facilities, and we're focused on, again, doing this as expeditiously and as safely as possible.

Great, excellent. And just quickly following up on one of the last questions, with respect to the decision to move from an MOU to just an outright contract, let me just be very clear about this. Your confidence level is higher incrementally or you said, obviously, less ideal market backdrop, but moving in that step, I would presume to be a statement of comfort that indeed this is moving forward. But I don't want to put words in your mouth either.

There's no question that the market is tougher that it was when we signed Cameron 1 through 3. But Octavio has been negotiating with some very strong counterparties, and they want to go to a sales and purchase agreement. We want to go to a sales and purchase agreement. That would allow us more comfort in starting to spend money on the facility, because it lays out all the terms.

And as long as you meet those terms, then they are obligated. And an MOU doesn't have that same level of obligation. So I think getting these sales and purchase agreements signed would give us a lot of confidence in being able to move forward with the facility later this year.

Octavio, do you want to add anything to that?

I think that we're pretty much, as Debbie indicated, it's good that we're moving in this direction. Obviously, the counterparties are using resources that are expensive, whether it's law firms or their own internal resources. So there's interest involved in this.

As you know, this is a facility that's not selling into the current market, it's a facility that's going to sell in into the market 2020 plus. And it's going to be one of the lowest, if not the lowest, facility at that point in time to deliver LNG to a time where just about anyone agrees there's going to be a shortage of supply.

Got it, thank you.

Citi's Faisel Khan has our next question.

Thanks, good afternoon.

Hello, Faisel.

Just the decision to expense some of the LNG development expenses, was that for Port Arthur or was that for Cameron's trains 4 and 5?

Most of the -- the majority of the $20 million to $25 million is for Port Arthur, and it's to do the work that's necessary to design enough of the facility where you can price it so you can market it. And that is engineering and legal costs and all, and then legal costs associated with the sales and purchases agreements for Cameron, and then the related facilities, the Pipelines & Storage and all that integrate with that.

That's what most of the costs are, and they're expensed because those are the accounting rules. Once we get contracts signed, then we would expect that this expense to not be part of our ongoing guidance because we'll spend the funds once. And once we get contracts signed, then we would begin capitalization of the substantial part of the project costs.

Okay, got you. And then in terms of as you enter into these negotiations for train 4, what are the hurdle rates you're looking at in terms of a return on capital for the project? Is it similar to the IRRs you were talking about with the Mexico pipeline, 9% or is it higher? How do you guys look at the returns?

Well we don't share that because we're still negotiating with customers. But we always look at what our cost of capital is on a risk-adjusted basis, and that we would have a reasonable return for that. So that's the way we would be looking at it, and our returns tend to be in the high single digits low double digits for most of our projects.

Got it. And could you remind us on the pipelines in Mexico, the tariffs are in dollar denominated terms. Is that correct, or are some of them in peso terms?

In Mexico, our tariffs are in dollars, but we pay taxes in pesos. And so that's why we have the FX issue in Mexico, which usually has recently has always been in our favor in Mexico.

So it just happens to be a coincidence that the tax benefit in Mexico offsets the currency depreciation in Chile and Peru?

It's a little more than a coincidence. There usually is some relation to currency valuations around the world, but it has been more of a one-for-one offset in the past. It has disconnected a little bit as we've moved forward.

Faisel, this is Joe. I'll add-on to Mark's comment that the FX benefit in Mexico doesn't have to do with the tariffs, because all of these dollar denominated contracts and our dollar denominated business is really the functional currency, and that's how we operate in Mexico.

But we have to pay our taxes in pesos, and the Mexican tax rules require that we have FX adjustments related to our monetary assets and taking into account inflation. So as these currencies move in a similar direction against the US dollar, we get this natural hedge, natural offset.

Okay, that makes sense. But when you talk about your guidance though for 2016, you're talking about a further depreciation in some of these currencies, or are you just looking at the forward rates? I just wanted to make sure I understood that language.

Joe? Why don't you walk through that.

Let me walk through that, Faisel, because I think this is important for everybody to understand and we talk about it from time to time. But we have some really, really well run utilities in South America. And over time, those have done extremely well and you can look back to the early 2000s.

They've done very well over time, and we like those assets a lot. But they are local currency run companies, and their revenues are in local currency. And so, we've seen a depreciation against the US dollar, because we have to translate those into dollars, of about 15% to 20% since last year's plan.

So when we did the 2016 plan last year and showed you a number, those currencies have depreciated 15% to 20%, and there's to some degree some offset in our tariffs and they catch up over time because we have adjustments in our tariffs. But we've adjusted the revenues or the net earnings from those companies for that change in FX rates from a year ago to the ones we have now.

In Mexico, the tax expense I was just referring to a moment ago, that's an annual adjustment. It goes from what was the peso at the beginning of the year to what is it going to be at the end of the year. And I think Debbie mentioned in her remarks that we haven't had this in our planning in the past, and the reason is, we're not allowed to under GAAP accounting rules, we're not allowed to forecast that.

But this year, we put it in the plan because we know that the Mexican peso is forecasted to move about 3.5%, and so we forecasted a change in our tax expense for that 3.5%. And so in 2016, we see a little bit of a loss there. In 2015, we actually had earnings as a result of this.

We had a $31 million increase at Mexico, and a $20 million decrease in South America, so we had $11 million plus. So again, in 2013, 2014 it was neutral, and between 2015 and 2016 net it's going to be kind of neutral. These things don't move the needle very much for us, they are pretty small.

Okay. That's very clear and I appreciate that. Last question for me.

On the renewables segment, just -- and this is small number, but if I look at the top line revenues in your table of year over year, they are down. I'm just trying to understand why.

I know that there's a lot of stuff below the line including tax and gains on asset sale and stuff like that that tend to move the earnings. But on the top line, I would suspect that number would be relatively stable. So I'm just trying to understand why it would be down year over year.

Yes, I'm going to have Trevor go through that.

Sure, Faisel, what's really happening there is some of that is really the assets that have been dropped into the joint ventures structures. And so, there are certain assets that we owned 100% in 2014 that are now owned 50%, and then are picked up through the equity method of accounting.

Okay, got it. Makes sense. Thanks for the time. Appreciate it.

Thanks, Faisel.

We'll move on to Michael Lapides of Goldman Sachs.

Hello. One question on LNG, and less about your contracting and maybe more about just the broader LNG markets. If you read the stuff that comes out of a lot of the economic consulting firms or other folks, they tend to talk about how the LNG market is oversupplied.

And so that would imply that it would be a headwind for any new LNG development. And yet it seems with some of the things you talk about at Cameron 4 and Port Arthur that your views and your actions and potential growth are contrary to that. Just curious if you could talk a little bit about the global LNG market, what you see for the near term and what you'll see for the long term.

Sure, I'm going to ask Octavio to answer that. But what I want to raise to you is a lot of this is about timeframe, and that what you read about is the current LNG market is seen as being oversupplied. What you also read about is that beginning in the 2020 period and beyond, there is a need in the marketplace for more LNG. So part of it is the timing of these things.

If you were having a noncontracted project coming on today, that might be a real challenge. If you had a project coming on when there's a market need, and that market need grows over time, then that's a very different market that you're going after. So, Octavio, why don't you talk about the broad market, and then how we feel that our facilities are going to compete in that market.

Let me give an introduction to the timeframe issue. The one thing that we need to start looking at is the current market is oversupplied, as we indicated, no discussion about that. But we also have a little problem with the current market.

We have an oversupplied market, and yet the spot cargoes are more expensive than the long-term pricing, which was agreed on in the tight market. So the market is broken in its pricing formulas, and the market is adjusting to it as we speak and will adjust for the next couple of years. But our focus is not the current market.

Our focus is the 2020, as I've indicated, where you'll see that the current oversupply will be absorbed, and then there's a shortage. And unfortunately, or fortunately, depending on your point of view, these facilities take five, six years to come on line once you decide to go forward. And as a result, we need to make decisions today to meet that demand.

It is difficult to make. It's large capital investments when a lot of the big players are taking writedowns because of oil, that's the condition why the market is tough. Some of the buyers are confused by the oversupply.

But our focus is not the current market. So globally, I like to believe we're going to switch everything from gas to coal and oil, which would increase our current footprint significantly, and it seems like the winds are the other way around. If you do believe that we are going forward. Not only with the continuous economic growth, but with a change to a lower carbon footprint, then gas is going to play a role, not just in the current market, but in other markets that are yet to open.

One interesting statistic I heard this week at CERA Week was the fact that the lower demand from Korea and Japan was made up by increased demand in Middle East countries, and therefore the demand didn't go away. And that was not there in the earlier projection.

So globally, where our projects fit, we're comfortable. It is a tough market for people to make decisions when they are under significant pressure, but we think we are offering to the market the lowest cost producing facility for 2020 and that's why the interest is there.

And I remember at one of your investor meetings you outlined where you facility is, I think it was your last analyst day. You outlined where your facilities sit on a cost curve relative to other global LNG facilities.

Just curious, given the fact that Port Arthur is greenfield and Cameron was brownfield, the thing that surprised us back then and still does a little bit now is that they are so close to each other on that dispatch curve in compared to some of the others. How are you thinking about how the economics of Port Arthur as a greenfield would differ from some of the disclosures you've given previously on Cameron 1 through 3?

That's a very good question, and I'll be happy to bring up another topic that sometimes gets forgotten. In the economics of the Cameron-based project, we included $1 billion of the cost of the existing facilities, which is essentially replacement value. So the economics of Cameron in that chart you saw at analyst day, as well as other charts, included the value of existing facilities.

So what we're doing with Woodside and Port Arthur is looking at ways to break some of the paradigms in the industry, keep it as safe and reliable as we want it to be as the customers expect it to be. But look at ways to reduce costs. Just like we found when we did Cameron that we had the lower cost per ton for conventional technology of liquefaction, we have an even lower price for the expansion of Cameron for trains 4 and 5, and we expect to achieve similar results with Port Arthur.

If we don't find that we can do that, then port Arthur is not going to go away. We simply believe that the industry has to be going back to a discipline of developing the next lowest marginal cost available of supply in order to be sustainable.

Got it. Thank you, Octavio, much appreciated.

You're welcome.

We'll go next to Felix Curmin of Visio Asset Management.

Hello this is Ashar. How are you doing?

Hello, Ashar.

Debbie, I just want to -- there's a little bit of confusion, a lot of calls going on today. But if I'm correct, I heard you say in your prepared remarks, and please correct me if I'm wrong, that the goal is still to meet or exceed previous expectations set. Is that correct?

I'm not sure what expectations you're referring to. What we're very focused on is that the growth that we have outlined for you in our plans is long-term contracted growth or in our utility. And that what we put in our base plan is things we already have under contract, and then expected utility performance.

What we expect to do is over the next five years, we expect to add projects to that. This last year alone, we added 325 megawatts of renewables that will come on line late this year. We've added or will be adding when the transaction closes the Pemex acquisition that was not part of our base plan a year ago. So our expectations are that we aren't going to sit still.

We're going to continue to develop and grow our business. And that what we show you though in terms of our growth is -- and when we get to our analyst conference, we'll do what we always do which is the blue box and the green box. That shows you what we have contracted and what's basically in our utilities as projects approved or in our rate case, and then we show you what we're working on that could add to that growth over the five-year period of time. And we'll be doing the same thing for you this year.

Okay, thank you.

We'll go to Morningstar's Mark Barnett next.

Hey, good morning, everyone.

Hello, Mark.

Thanks for all of the comments on the LNG market today. I did want to ask one more question about Mexico.

And I know that some of the pressure on Pemex does create an opportunity in the some of the assets they might be looking to offload. But I'm wondering if you'll see beyond maybe this current slate of projects some headwinds just from the lower oil revenues from the Mexican government, and maybe if you could talk about how you see the balance of opportunity versus challenge?

Yes, honestly, when you talk to our CEO in Mexico, he sees it as an opportunity. Because the whole reason for reform was to bring capital into Mexico to build the infrastructure that they need for the kind of growth. And you have to realize, Mexico is going to be more competitive the lower the energy prices are in the long term for them. That has been their stumbling block on being globally competitive.

So to the degree that they can use other party's capital, and that would be us, we would like to put our capital there. And that they can build the infrastructure that reduces their energy costs, they're moving forward on that basis. And so, we think that -- I think it's a struggle for Pemex with having been reliant on oil revenues, but it's an opportunity for us to come in and build things that wouldn't otherwise be built, and that are needed as part of the long term Mexican infrastructure. So that's the way we look at it. Mark, do you want to --?

Let me just add to that too is I think that when we talk about energy reform in Mexico, I think a lot of folks are focused on the reforms at Pemex. And they haven't seen increases in production and some of the things that they expected to see from energy reform, and I think that's entirely the fault of $30 oil and very little to do with the reforms.

What are coming out of the reforms is a massive amount of energy infrastructure within the country, and that infrastructure is doing exactly what it's supposed to do. As Debbie said, it's lowering energy costs, bringing natural gas into regions of the country that didn't have access to it before. It's really making a big difference in lowering electricity costs across the country, and that's working very, very well.

And to the extent that low gas or low oil prices are hindering some of the reforms at Pemex, I think that again is creating a large opportunity for us because it increases the need for Pemex for capital. It gives opportunities for us to look at the assets that they are going to be putting up for sale. And so from our perspective, I think that we think the reforms are working very much as intended and that we will continue to benefit as being one of the best placed companies in the country to take advantage of those opportunities.

Okay. And with the latest round of bids, I apologize if I missed it in your comments. When you gave the bid dates, do you have an estimate for when you might expect the results from the bidding process?

They were looking at a -- they haven't given in specific dates, but probably in the March and April timeframe is most likely.

Okay. All right, that's all for me. Thanks a lot.

Thanks.

And it appears we have no further questions at this time. I'd like to turn the call back over to Debbie Reed for closing remarks.

Well thanks again for all of you joining us today, and all your excellent questions. We hope to see you at our analyst conference on May 24, and if you have any follow-up questions, our Investor Relations team is available to answer anything that was left off from the call today. Thank you very much.

And again, that does conclude today's conference. We thank you all for joining.