CenterPoint Energy Inc (CNP) 2012 Q4 法說會逐字稿

Good morning and welcome to CenterPoint Energy's fourth-quarter and full-year earnings conference call with Senior Management.

During the Company's prepared remarks all participants will be in a listen-only mode.

There will be a question-and-answer session after Management's remarks.

(Operator Instructions)

I will now turn the call over to Carla Kneipp, Vice President of Investor Relations.

Ms. Kneipp?

Thank you very much, Sarah.

Good morning, everyone.

This is Carla Kneipp, Vice President of Investor Relations.

Welcome to our fourth-quarter and full-year 2012 earnings conference call.

Thank you for joining us today.

David McClanahan, President and CEO; Scott Prochazka, Executive Vice President and Chief Operating Officer; and Gary Whitlock, Executive Vice President and CFO, will discuss our fourth-quarter and full-year 2012 results and provide highlights on other key activities.

We also have other members of Management who may assist in answering questions following the prepared remarks.

Our earnings press release, Form 10-K and supplemental materials, are posted on our website, CenterPointEnergy.com under the Investor section.

The supplemental materials are for informational purposes and we will not be referring to them during the prepared remarks.

I remind you that any projections or forward-looking statements made during this call are subject to the cautionary statements on forward-looking information in the Company's filings with the SEC.

Before David begins I would like to mention that a replay of this call will be available through Wednesday, March 6. To access the replay please call (855)859-2056 or (404)537-3406 and enter the conference ID number 71670373.

You can also listen to an online replay on our website and we will archive the call for at least one year.

And with that I will now turn the call over to David.

Thank you, Carla and good morning, ladies and gentlemen.

Thank you for joining us today and thank you for your interest in CenterPoint Energy.

This morning we reported full-year earnings of $417 million, or $0.97 per diluted share as compared to $1.36 billion or $3.17 per diluted share in 2011.

I'd like to remind you of the unusual items that occurred during each year.

In 2012, we recorded a non-cash goodwill impairment charge as well as a non-cash pre-tax gain from an acquisition.

In 2011, we recorded the results of the final resolution of our true-up appeal.

Excluding the effects of these unusual items, net income for 2012 would have been $581 million or $1.35 per diluted share compared to $546 million or $1.27 per diluted share in 2011.

Using the same basis that we use when providing guidance, full-year adjusted earnings would have been $1.25 per diluted share in 2012 compared to $1.20 for 2011.

Our regulated electric and gas utilities benefited from strong service territories, timely rate recovery mechanisms, and effective expense management.

Our midstream and energy services businesses performed well given the current market environment of low natural gas prices and minimal geographic price differentials.

Our financial results once again highlight the strength of our balanced energy delivery portfolio.

We are looking forward to another good year in 2013.

We are stronger financially than we've ever been and have good investment opportunities across all of our businesses.

Last year we celebrated our tenth anniversary as a stand-alone, independent, public company.

When we first became CenterPoint Energy, we indicated we would focus on domestic energy delivery with a balanced portfolio of electric and natural gas businesses.

Further, we committed to building a Company that provides a competitive dividend with growth.

Ten years later, we are proud of our accomplishments and remain committed to these objectives.

I would like to take this opportunity to thank the employees who have made the past ten years a success.

I am very proud that our employees stayed focused on, and believed in, the vision, values, and strategy that have come to define us.

Without their hard work and dedication we would not be where we are today.

Now I'll ask Scott Prochazka, our Chief Operating Officer, to update you on our business unit performance and our expectations for 2013.

Thank you, David, and good morning to everyone.

I will start with our largest business, Houston Electric, which had a good year.

Core operating income was $492 million compared to $496 million in 2011.

The modest decline was due to more normal weather when compared to the extreme heat we experienced in the prior year as well as the adverse effects from new rates implemented in September of 2011.

These impacts were almost entirely offset by a number of positive factors, including a continued strong Houston economy marked by the addition of more than 44,000 new metered customers, ongoing recognition of deferred equity returns associated with the Company's true-up proceeds, and decreased labor and benefits cost.

Right-of-way revenues approached $27 million which is substantially above historical levels of $2 million to $3 million per year.

The increased interest in our right-of-way easements is another sign of the strong economic activity in Houston.

Our gas LDCs also had a good year.

Operating income in 2012 was equal to that of 2011 at $226 million despite record mild temperatures in the first quarter of 2012.

Over the year, weather negatively impacted this unit by about $47 million compared to the prior year.

We were able to mitigate approximately $26 million of the weather impact through our use of a financial hedge and weather normalization rate adjustments.

We were able to offset the remaining weather effects through reduced operations and maintenance expenses, lower bad debt expense, the addition of more than 22,000 customers, and the effects of other rate adjustments.

Now let me turn to our Midstream businesses.

Our Interstate Pipelines achieved operating results, including equity income from SESH, of $233 million last year, down from $269 million the previous year.

The decline was due to a back haul contract that expired during 2011 as well as the associated reduction in compressor efficiency on our Carthage to Perryville pipeline.

Other factors included low commodity prices and significantly compressed basis which contributed to lower off-system transportation revenues, lower seasonal and market sensitive transportation contracts, and reduced ancillary services.

Equity income from SESH was $26 million for 2012 compared to $21 million the previous year.

This increase reflects the full-year benefit of a restructured long-term agreement with an existing anchor shipper.

Our Field Services unit had a strong year.

Full-year operating income was $214 million compared to $189 million the previous year.

This improvement was driven by increased margins from gathering projects, guaranteed returns and throughput commitments in our contracts, and acquisitions made in 2012.

Our total gathering throughput increased approximately 9% compared to the previous year.

These benefits were partially offset by the lower contribution of sales from retained gas as a result of lower commodity prices.

Our final segment is our Competitive Gas Sales and Services business.

Setting aside the goodwill impairment charge in the third quarter, this business performed better in 2012 as compared to the prior year.

In 2012, we continued to adapt this business to new market realities by focusing on retail, commercial, and industrial customers.

This business is benefiting from the strategic reduction of uneconomic fixed cost, transportation, and storage agreements, as well as a 14% increase in our customer base.

Now I would like to discuss 2013 and give you some insight into each business unit's prospects.

Houston Electric is fortunate to have a robust and growing service territory.

We estimate that annual customer growth will continue at around 2%.

This level of growth should add approximately $25 million in base revenues.

We expect 2013 revenue from right-of-way to remain above historical levels.

You may recall we recognize all revenue from these leases in the year each agreement is signed.

Future right-of-way revenues will depend on subsequent economic activity in our service territory particularly around the Houston ship channel.

This year we expect our capital investment in this business will exceed $700 million.

Future capital expenditures are expected to range between $500 million and $700 million annually and produce annual average rate base growth of approximately 5%.

This capital will be used to help improve service reliability and system resiliency, upgrade our systems to enhance customer service, and support normal load growth and system maintenance.

Our vibrant service territory and rate recovery mechanisms should allow us to earn our authorized rate of return the next several years.

Turning now to our Gas Operations group, we expect 2013 to be another good year.

We will continue to execute our strategy of improving operational efficiency, as well as implementing new and innovative rate mechanisms.

A number of our jurisdictions now have annual mechanisms which provide more timely recovery of capital investment, or adjust for deviations from normal weather, or both.

In addition, some jurisdictions have adopted rate designs that decouple the recovery of our revenue requirements from the volumes of gas sales.

These mechanisms are a more efficient form of regulation that emphasizes audit-based procedures and requires less expensive and time-consuming litigation.

In 2012, revenue increased approximately $37 million as a result of the successful implementation of this rate strategy.

In this business we anticipate investing, on average, $400 million of capital per year over the next five years, much of which we expect to recover through annual mechanisms.

Capital investment will be primarily for growth, system modernization, and safety-related infrastructure, which results in annual average rate base growth of approximately 7%.

Switching to Interstate Pipelines, low natural gas prices and compressed basis differentials are expected to continue to impact this business.

We anticipate the third and fourth quarter of 2012 results to represent a more normalized performance level in this environment.

Our pipelines' capital budget for 2013 is approximately $200 million and will be used primarily for pipeline maintenance, line replacements, and pipeline safety and integrity projects.

Our pipelines remain highly subscribed at around 95%.

Nearly 40% of our contracted demand is to serve the LDC and industrial load near our pipelines.

As we have indicated in the past, we are seeking rate adjustments for our MRT and CEGT pipelines and are continuing customer settlement discussions.

From a market perspective, while the construction of a large expansion in our footprint is less likely given current market conditions, we do see interest in expanding services to our producer customers in the form of supply laterals.

And of course we continue to pursue market opportunities on or near our pipelines with particular focus on power generation load.

Moving to our Field Services business.

In 2013, we expect to see continued opportunities to expand our geographic footprint and service offerings.

On February 19, we announced a binding open season to develop and operate a crude oil gathering system in North Dakota's liquid-rich Bakken shale.

The open season will remain active through March 29 and our expectation is that we will have signed an agreement with a major producer by that time.

Our Field Services capital budget for 2013 is approximately $270 million with more than 0.75 allocated to growth projects.

We will continue to look for other growth opportunities both in and outside of our current footprint.

Natural gas gathering volumes averaged about 2.5 billion cubic feet per day in 2012.

While we had seen some recent announcements of increased rig counts in dry gas areas, we expect our volumes to remain at these levels in 2013.

Given the lower commodity prices, we continue to see the benefit of our contracting strategy of throughput commitments and guaranteed rates of return.

Although we increased our processing activity through acquisitions, today it represents less than 15% of our overall margin contribution within Field Services.

Further, 50% to 60% of that processing capability is volumetric fee-based and not subject to commodity risk.

As a rule of thumb, we estimate that our sensitivity to changes in the price of natural gas liquids is approximately $3 million in revenue for every $0.10 change in natural gas liquids pricing.

Finally, our Competitive Gas Sales and Services business will continue to focus on expanding its customer base, reducing fixed costs, and growing product and service offerings.

We expect 2013 performance to be an improvement over 2012.

Reflecting on our 2012 performance, I'm pleased with the results we achieved.

I am optimistic about our prospects for 2013, and we will work diligently to ensure our businesses perform as expected.

Further, we will continue to look for opportunities to invest where we believe we can create value for our shareholders.

I will now turn the call over to Gary.

Thank you, Scott and good morning to everyone.

As David mentioned in his remarks, we are very pleased to have celebrated our 10 year anniversary as CenterPoint Energy.

As you all know, at the formation of our Company in October of 2002 we were very highly leveraged with limited financial flexibility.

However, since that time we have worked diligently to recapitalize our Company and today we have a strong balance sheet and solid investment-grade credit rating.

The 2013 capital plan that Scott discussed totals approximately $1.7 billion.

Our cash on hand, internally generated cash, and other liquidity sources will fund this capital plan.

In addition, to ensure we align the Houston Electric capital structure to the capital structure approved in its last rate proceeding, our 2013 financing plan will include the repayment of $450 million of maturing debt at Houston Electric in March of this year.

Now I'd like to discuss our earnings guidance for 2013.

This morning in our earnings release, we announced guidance in the range of $1.22 to $1.30 per diluted share.

This guidance range takes into consideration a number of economic and operational variables that may impact our actual 2013 earnings performance.

The most significant variables we consider for our annual guidance are commodity prices, volume throughput, weather, regulatory proceedings, and our effective tax rate.

And we have developed our guidance range by using a combination of these variables.

We have assumed natural gas pricing in 2013 of approximately $3.50 per MMBtu and $0.95 per gallon for our mix of natural gas liquids.

In addition, we have assumed a return to a more normal effective tax rate of approximately 37%, an average share count of approximately 430 million, as well as lower interest expense.

As the year progresses we will keep you updated on our earnings expectations.

Finally, I'd like to remind you of the $0.2075 per share quarterly dividend declared by our Board of Directors on January 25.

This marks the eighth consecutive year we have increased our dividend.

We believe our dividend actions continue to demonstrate a strong commitment to our shareholders and the confidence of Management and the Board of Directors in our ability to deliver sustainable earnings and cash flow.

Now let me thank you for your continued interest in CenterPoint Energy and I will turn the call back over to Carla.

Thank you, Gary.

We will now open the call to questions.

And in the interest of time, I would ask you to please limit yourself to one question and a follow-up.

Sarah, would you please give the instructions?

(Operator Instructions)

Carl Kirst, BMO Capital.

Thanks, good morning, everybody.

First question, and I don't want to read too much into this, but just noticed that in the guidance for 2013, you guys are putting out an $0.08 spread versus, I think, what we started with this time last year with maybe a wider $0.12 spread.

Again, I hesitate to read into that.

But I didn't know if there was any implication of either more certitude or less variability around your planning process.

And I didn't know if there was any color on that.

Carl, I wouldn't read much into that.

As you might recall, last year when we started the year we had a much wider -- we had a natural gas price that was much more in flux.

We were assuming something in our [plan] a little less than $4, and it was $2.50 at the time we had our call.

I think that's part of it.

But generally, I wouldn't read much at all into that -- the tighter spread.

Okay.

I appreciate that.

And just a second question here, and it really speaks to the gas utility with the earnings power.

I think historically we had been thinking of the normalized earnings power of the gas utility in the maybe $200 million, $220 million range.

Here you guys had a really nice year considering that there was $25 million of still weather impact.

And so, I guess the question is -- do you think the great O&M expense management that you had for this year, is that sustainable?

Meaning that, have we, in effect, lifted the new normal earnings power for this segment up in the $250 million range?

Carl, first, I think we have lifted it some.

I think you're right.

But I'm going to ask Scott to address the O&M side of this.

Yes.

I think some of the O&M is sustainable; I wouldn't say all of it.

Knowing that we started the year in such a hole with the weather, we looked at where we could defer some of the O&M.

And so, some of that will move out into the future.

But there are some improvements that we made that would be sustainable.

The other point I would probably add here is that we did pretty well on our bad debt expense.

And as gas prices grow, even if we stay at a fairly competitive or aggressive low rate in terms of our write-offs, as gas prices increase, which we have in our forecast going forward, that number will naturally increase.

So, there will be some degradation in terms of having more bad debt expense on a go-forward basis.

Understood.

Appreciate the color.

One clarification -- is the CapEx that you mentioned for Field Services, does that include the Bakken project?

It does.

Okay.

Great.

Thank you.

Charles Fishman, Morningstar.

I was wondering if you could explain to me the mechanics of the weather hedge on the natural gas?

And I guess specifically, is that something that you eventually have to share with customers, that $8 million benefit in 2012?

Scott, you want to take that?

Yes.

So, the mechanics of this are -- we calculate the -- or determine what we believe the value of heating degree days are.

And we can hedge against those with a third party, such that if we -- if it goes one way, there is payment to the party, and if it goes the other way, then the party pays us.

It's kind of a swap structure.

But it's geared around a calculation of normal weather and a determination of what the value of each heating degree day is within the regions which we carry these in.

As far as whether this ends up getting shared, we hold these hedges at corporate, and we do this really to target kind of stabilizing the earnings.

So, some year it's up; some year it's down.

But it's geared around stabilizing the earnings in that unit.

Okay.

Thank you.

Ali Agha, SunTrust.

Hey, David or Gary, for those of us who have been keeping track of the excess cash balance, and you guys have been keeping us up to date on that as well, as I recall, you indicated at the end of the last quarter that excess cash balance was $600 million.

Can you update us on what that number is as of the end of the year, and also where we stand in terms of deploying that for new projects?

Ali, it's about $500 million, give or take.

That varies depending on when we pay our gas bills.

But it's about $500 million.

As Gary said, we have a $1.7 billion CapEx in front of us.

It's a large capital program cutting across all our businesses.

And we're going to be using this money to fund those projects, as well as any new growth projects that have not been identified but that we're pursuing.

So, I would say that by the end of this year we're going to come close to spending most of that cash, if not all of it.

Okay.

And then, secondly, in terms of spending the cash, clearly the focus has historically been on the Field Services area and the Bakken project seems to be going forward.

At the same time, you have also been pretty clear and open about your interest in Oncor.

I wanted to understand where the focus remains in terms of, at least opportunities right now, and whether the financial issues going on with any of the futures holdings, does that cause the Oncor monetization to become more front burner, or are you seeing any activity on that front?

First, we are still interested in growing Field Services.

It's a big focus of ours.

But it's not exclusively Field Services.

We are very interested in growing our regulated businesses.

And so, we've said in the past, if Oncor would come on the market, it would be a unit that we'd absolutely look at.

But it's not stopping us from doing what we would normally do anyway.

So, yes, we're interested, but we're pursuing a number of different options, and it's just not Oncor.

One last question.

Gary, just to clarify the '13 guidance, at the EPS level, it's pretty relatively flat with '12.

And when you were going through the segment, discussions looked like you were net-net higher.

Is it all the higher tax rate that's causing flat EPS?

Or can you give us a little more color on why flat versus the '12 actual?

Yes, I'll take a shot at that first, and certainly Scott can add to it.

Let's talk about the tax rate.

I think that is an important thing to focus on.

The ongoing tax rate will be 37%.

If you recall, last year we ended with a 45% tax rate.

But that had that non-tax-deductible goodwill impairment.

So, you take that out, we ended with a tax rate of approximately 33%.

That was really due to a lot of hard work over the last number of years to resolve issues with the IRS, mainly legacy issues.

So, we did have a benefit in tax.

In fact, some of it actually was reported in other income.

We had a benefit of approximately $0.09 all in, if you will.

That's kind of come back.

So, we effectively have a higher tax rate this year.

The guidance reflects our expectation of a higher tax rate this year.

Now, in addition to that though, we do expect lower interest expense because, as you know, we have been recapitalizing the Company in the sense of some refunding, but primarily some restructuring of debt, so you continued lower interest expense.

This year it was lower by about $34 million.

Next year, think of maybe equivalent number, maybe a little bit more than that.

So, that's favorable to us.

That's some offset.

Then the business -- you heard Scott describe the businesses.

Over the long term, they will grow.

He described those as sort of net neutral to up a bit, I think, when you put it all together.

So, again, we still have a range because we still have some variables.

As you know, our objective is always, A, keep you informed.

But our goal is it to work as hard as we can to exceed the midpoint of that range, and continue to grow our Company this year.

Thank you.

John Edwards, Credit Suisse.

Just real quick question.

Going forward, given how the Competitive Natural Gas Sales and Services came in, pretty significant increase, what's a reasonable run rate to think about for that segment going forward?

Good question, John.

We used to say we thought the pure retail side of this was in the $30 million range.

I think long term it is.

Probably in the near term, it's more in the $20 million range.

So, we're working hard to improve the profitability there.

We've gotten rid of a lot of the uneconomic contracts, which helps a lot.

But the key is to grow the business and improve margins, and that's what we're attempting to do.

Okay.

Great.

Thanks.

That's helpful.

And then just real quick on your Natural Gas Distribution.

It obviously was a real good quarter, and the margin per customer was up quite a bit versus what we were thinking.

Just maybe if you could give a little more granularity on that?

I mean, you've already talked about some things -- cost savings and rates and so on.

If there is any other things in that regard.

Scott, do you have anything to add there?

Bad debt expense has been something that we have been working on for several years.

Scott said that may tick up.

But the new policies and procedures around credit and collections are not going to change.

So, I think we've got a good handle on that.

We are running a pretty tight ship now.

It's taken us three or four years to completely revamp the way we run that business.

And I think it's showing through the reduced O&M.

But we do have a lot of new rate mechanisms that's gone in over the last three or four years that provide for annual or automatic adjustments.

So, we don't have to go in and seek rate increases.

And I think those are important, and they're starting to have a very positive effect on this business.

I will add to that as well.

A couple other things -- one of the bigger items that was -- if you are just looking at the quarter against prior quarter, it was around weather and usage.

Between the two of those, they were up $6 million to $8 million over the prior quarter.

So, that was a good part of the delta.

Okay.

Great.

Thanks very much.

That's all I had.

Thanks.

Faisel Khan, Citi.

I was wondering if you could give us a little bit more detail on the Bakken project.

I see the open season.

I guess it's for both gathering and pipeline takeaway capacity for, I guess, crude oil, liquids, and natural gas.

But if you could go into a little bit more granularity in terms of what the open season encompasses, that would be great.

Let me ask Greg Harper to address that.

The open season is primarily for a crude gathering system.

Okay.

And it would have a little tank storage potential as well.

It does not contemplate takeaway pipelines from those gathering termination points.

We would be putting into rail or other pipelines, is the contemplation at this time.

This is strictly a gathering system.

So, taking crude oil from well head to central control points, and then on to tankage.

Okay.

And if our numbers are right, I think about 75% of the crude oil in the Bakken is gathered by truck right now?

Is that a fair estimate?

Is that the business you are going after?

Exactly.

You nailed it right on the head, Faisel.

This is a great opportunity to, number one, help the state get those trucks off the road.

And we think it's a competitive opportunity and alternative right now for the producers in this area.

Faisel, I think you will also see this type of crude gathering system being employed in other areas around the country.

Because of the amount of trucks necessary to move this, there is lots of wanting to get an alternative to trucking.

And this is the best alternative on that.

Definitely, there has been a paradigm shift with the number of trucks Dave mentioned, is kind of a result of the prolific nature of the crude level coming on from the drilling and the fracking.

Okay.

I take it also that in this gathering system, you would tie in the associated gas production that's being flared into the system, too, is that right?

That's not contemplated in this particular offering.

It would be something that we would be prepared to do, obviously having a footprint in that area if we get the appropriate nominations.

How do you guys compete versus everybody else?

What's the competitive landscape like in the Bakken?

I would assume it's pretty competitive.

I don't know how you guys go about getting the business versus somebody else.

I mentioned before, Faisel, is we step out of our footprint, that a key strategy for us was to do it with maybe a major producer friend or companies.

And that's what we have been trying to do both here in the Bakken as we look at Mississippi Lime, as we look at Tuscaloosa Marine, as we look at even Marcellus.

We're not the type of Company that's going to go out and do something speculative.

We are going to do something that is in concert with a big producer customer, and have the similar type contract that we've had in the past in our new gathering footprint.

Okay.

And whatever happened with the Mississippi Lime open season?

That was like in the first quarter of last year?

Good question.

What we found in the Mississippi Lime where we were looking at is there was a lot of high-nitrogen issues.

And we're just not seeing enough gas to gather to offset that issue for what it takes to treat it.

Now, another major producer that had an RFP out has withdrawn that.

That major producer has moved to a different area in the Mississippi Lime, and is expected to issue an RFP, and we will be participating in that.

So, ongoing negotiations with smaller customers, but again, right now the aggregation level that we're seeing doesn't contemplate a project at this point in time.

But we stay in constant communication with these customers.

Got it.

And on the results of Field Services, throughput down from 237 [bcf] to 205 [bcf], but operating income up year over year.

Can you walk us through the math on how that happened?

I suspect it's from your newer gathering contracts that are in place.

But give us an idea of what is declining in the background as we see these volumes sort of come off from current levels.

I will give you a high level.

I won't give you exact numbers because I don't want to get into our producers' flowing volumes.

But I would say that the difference, obviously going from 237 bcf to 205 bcf is a decline across the board on our footprint.

But the makeup, obviously the increased margin, the top line I think goes from $91 million to $109 million.

That growth is driven by our contracts -- the guaranteed return contracts, and primarily the buying commitment contracts.

Okay.

So, assuming that volumes -- let me ask this.

Do you expect volumes to continue to decline for the rest of this year?

We expect volumes to be at the same level as last year.

I don't think David or Scott mentioned it in the call, but I think they have had some producers moving into our area, back into the Haynesville area.

Encana announced that on their earnings call, with an increase in five rigs by year end.

Okay.

We don't have in our planner, in Gary's projections right now that that would increase volume flow.

We see that as protecting and preserving current levels.

If we get upside, that's going to be great.

Faisel, I might also add -- I think in '12 we lost something like $28 million due to lower commodity prices, primarily natural gas.

So, we've got some upside if natural gas prices firm up, and they're probably going to.

Our projection is they will be higher in '13 than they were in '12.

So, even if you get the same volumes, there could be some potential increased profitability there.

Okay.

Got it.

And then just on the pipelines, you guys mentioned you were 90% subscribed on the pipelines.

Are there any contracts that are up for renewal in the next 24 months that we ought to be concerned about?

Well, I don't want you to be concerned about anything, Faisel.

It's our job to go get those renewed.

I think our Laclede agreement is in evergreen within the next 24 months.

So that's -- again, we serve Laclede via MRT.

That is the asset that we are currently in the middle of a rate case at FERC on, and we have had a settlement conference on that.

So, we see that -- that is obviously a very large contract on MRT, and we will work to extend that, and renegotiate and extend.

On CEGT, there is a mishmash of contracts that can come up and roll off.

But I think the largest contracts on CEGT would be like Line CP in 2017 or so.

Got it.

And then just last question from me.

On CapEx, you guys mentioned, I think, $1.8 billion in CapEx.

Did you give a breakdown in your prepared remarks?

If you did, don't worry about it, I will go back to the transcript.

But if you didn't, I'd appreciate a breakdown of the CapEx for --

We have those documented in the 10-K.

Plus, if you look at the supplemental material, it's laid out there --

Got it.

-- in a fair amount of detail.

Okay.

I'll look there.

Probably the best way to find it.

Okay, guys.

I appreciate the time.

Thanks.

Andrew Weisel, Macquarie.

A couple of questions on CapEx.

First, at the electric utility, it looks like some pretty big declines after '13 and '14, mostly in this public and system improvements category.

Is a lot of that conservatism?

It's not related to the load growth, so just wondering why it drops, and if there is potential upside there?

Andrew, I'll take that.

There is, as you noted, some downward movement.

Perhaps there is some conservatism in there, but there is also some projects that we have early on that end at that point.

We're putting in a back-up control center, which consumes about a couple of hundred million dollars worth of investment over the near term.

Once that ends -- that's part of the reason that it turns down.

The theme of kind of maintaining the ongoing investment in infrastructure for hardening and system maintenance as well as load growth, that theme we have kind of carried through.

But we will have to see what actually happens in terms of whether growth picks up or slows down, or maintenance requirements change.

Most of it is driven by some big projects that we have that we know we have early on.

You may end up having some additional, bigger projects that materialize down the road that could fill that gap.

But right now, this larger slug is really related to a large project.

Okay.

So then, when you talked about the 5% annual rate base growth, should that be frond-end loaded, meaning faster than that in '13 and '14?

Well, it really looks at the total capital spent over the period.

So, if you look at where we get to rate-base-wise by the end of this period, it looks at what -- that rate would represent an average growth rate from the starting point to the end point.

It just so happens that it's kind of front-end loaded.

Okay.

Great.

And then on usage, I think I heard you say you are expecting 2% growth in customer accounts in 2013.

How has usage per account been trending, and what's your expectation for total weather-adjusted load growth?

Over the past, load growth we saw kind of flat to maybe slightly declining.

This was looking back several years.

Interestingly, this year we have actually seen usage increase slightly.

We believe it has to do perhaps with the economy and with the economy strengthening here in Houston, as well as the relatively low price of power.

So, we have seen a little bit of a bounce in usage this year.

Going forward, we forecast usage to be about flat.

But we do know that we continue to see what we think will be some ongoing headwind on the downside just from things like replacements of appliances with more efficient -- replacement of air-conditioning units and lighting standards, that type of thing.

But more or less, we look at it as about even to maybe a slight decline as we look forward.

Okay.

Great.

That's very helpful.

Then next question just on the Field Services CapEx.

Obviously, the acquisition was the biggest chunk from 2012.

But the other CapEx was quite a bit lower than what you'd expect -- what you forecasted in the 10-K a year ago.

Just wondering if a lot of that was stuff that has been deferred based on the acquisitions or canceled, or how to think about that going forward.

And maybe a little more color in 2013 on the Bakken spending you mentioned as a big piece of the growth and what else might be included in that.

This is Greg.

I'll answer the 2012 question first.

The capital was lower in 2012, and that's primarily from deferrals.

Most of our capital that we look to deploy are based on existing contracts.

We are obviously in communication with our producers weekly, monthly to make sure we're deploying our capital ratably relative to their growth, and where they're bringing on their production.

Basically, some of them had a forecast early in the year or maybe fourth quarter of 2011 what they would be doing in 2012.

A [big percent] modifying that during the year, and so we just pulled back the capital.

However, they are committed to their acreage to us and/or buying commitments to those areas, so that will come once they start drilling.

As far as 2013, that's the same thing we've planned out this year.

We think the Bakken is probably in there around [$120 million] or so, [$125 million].

So, the balance -- the majority of the balance is still growth capital.

I think, Scott mentioned 75% of our capital is growth.

So, the remaining 50% to 60% of the balance is growth capital.

And that, again, is tied into what our producers are telling us right now where they think they'll be by year end.

Great.

Very helpful.

Then just lastly if you could let us know how much operating income came from the acquisitions last summer, and if doubling that would be a good proxy for 2013 and beyond run rate?

$13 million for 2012 came from the two acquisitions.

That was -- we expect to do better than double that in 2013.

They came on at different times of the year.

One was August 1, and one was a little bit earlier than that.

But our plan calls for more than doubling that.

Yes.

That's correct.

In 2013.

Great.

Thank you very much.

Scott Senchak, Decade Capital.

Hi.

Thanks.

Just looks like about 70% of your CapEx spend in '13 is going to the regulated electric and gas distribution segments.

And as I look out in your CapEx forecast in the K, it's roughly the same kind of spread.

And just wondering, is that kind of a change in theme going forward, or is that just where the opportunities you see right now exist?

You know, this is really -- it's much easier to see the spend in the regulated utilities than site field services because we don't speculate about projects that we're not sure of in the 10-K.

But for our Houston Electric and our gas LDCs, we have plans to go in and replace pipe or improve systems or build control centers.

So, we have a lot of clarity around regulated capital expenditures.

When it gets to Field Services, we put in there what we know.

But we don't put in there what we don't know.

I would be very disappointed if we don't have some growth projects that come up in Field Services that would increase the level of expenditures in that unit.

Okay.

Great.

And then, in the past, you've given us some growth rates for each of the businesses.

Has that changed at all, or is that still kind of the same outlook?

And can you comment on that?

We've given overall that we want to be in the 4% to, say, 7% EPS growth rate.

That's our long-term -- and each one of our units have a little different growth around it.

Houston Electric, gas LDCs, you heard Scott talk about rate-based growth there of 5% to 7%.

So, they're going to provide some growth.

Pipelines are the ones that probably are a little less certain.

That's probably flat to slightly up if we win some of the projects we are going after.

And Field Services -- we expect it's going to grow.

It's been our fastest growing unit the last three, four years.

It's grown a little less than 20% a year.

And as it gets bigger, that percentage will come down.

But we expect Field Services to continue to be our fastest growing business segment.

Overall, our goal is to achieve that 4% to 7%, or 5% to 7% growth in earnings.

Okay.

Great.

Thank you very much.

Scott Graham, Teilinger Capital.

It's actually John Kiani.

I know you talked a little bit about this already.

But can you just give a little bit more color around some of your plans to allocate capital between Field Services and the regulated use?

And more specifically, talk a little bit about the status of using an MLP as a financing vehicle for some of the projects that you're currently working on, like, for example, the Bakken project and within Field Services, please?

Gary, why don't you take that one.

Okay.

John, why don't we just start with the MLP.

We have been consistent on this, John, as you know, in our discussions.

We continue to see the formation of the MLP as an effective financing vehicle.

And certainly enough to, in terms of funding the growth for our midstream business.

As to the timing of that, as we reported this morning, and we've talked about on the call, we do have a sizable CapEx program.

Certainly a significant amount of that visibility is in the regulated business, and we're pleased about it.

But as you know, we have been funding all of that, or funding our capital through internal sources of cash, including this year.

As you know, we also have another benefit of bonus depreciation, which is about another $170 million.

So, in terms of funding, it's been internal sources, cash on hand.

But as we talked about, or David alluded to, and Scott and certainly Greg, as we have more visibility around that midstream growth and the Bakken, I think sets the stage for hopefully additional growth there and beyond.

I think the MLP becomes front and center as a financing vehicle.

As David said, we would think by the end of this year, cash on hand plus internal sources at some point we will need a financing need in the future, and when we have visibility around that growth I think the MLP, again, is front and center.

So, absolutely not off the table -- on the table.

And I think it's really related to when we see the need for it.

Got it.

So, it sounds like, I guess, the good news is that the financial stability of the Company just from the perspective of excess cash on hand and also some additional cash flow from bonus depreciation gives you a lot of flexibility at the moment to fund CapEx both on the regulated side but also importantly, on the Field Services side with that internally generated cash flow.

Is that --?

John, I think that's right.

But I also don't want you to walk away, or other investors, with -- everything is that precise.

Again, as Greg and his team work very diligently to originate business, when we see that we have the growth there, I don't think that having cash on hand and available liquidity will hold us back from forming an MLP because it takes time to form it.

Obviously, we have done all the ministerial things of audits and those things, so we're prepared to do an MLP, can do one.

We just want to make sure it's at the right time and in the best interest of our shareholders to do so.

Got it.

And then one other separate question.

How should we think about the potential fit or strategic benefit, hypothetically speaking, from Oncor, as I think you all were discussing a little bit earlier when you said you would consider taking a look at it if it was for sale.

Is it something that helps to balance out the non-regulated earnings from Field Services?

How should we think about some type of a business like that for you all?

Well, it certainly would do that.

Obviously, Oncor is a sizable electric T&D business.

It would add substantial amount of regulated assets and earnings to our portfolio.

And we recognize that we need to have a good regulated base as we grow our unregulated base.

So, it certainly fits that pistol for us.

So, we're going to be diligent about looking at it, if it ever comes on the market, and I think it would be a nice fit.

But it's all about making sure you can buy it for a price that creates shareholder value.

And we'll work hard at it, if it ever comes on the market.

Okay.

Thank you very much.

You bet.

Steve Marrs, Citizens Trust.

Two questions, please.

Number one, going back to a previous comment regarding the 75% of your Bakken crude being handled by truck, and you guys are probably salivating over that, would there be any maybe joint venture being done with, say, railroads in the same area?

Steve, we hadn't entertained anything like that because we're really doing it at the gathering level not the long-haul level.

And there is some other folks looking at big pipes coming out of that area to basically compete with the railroads.

But I don't think -- that's not something we're interested in right now.

Yes.

And I would say that, I think it was Faisel or Carl that mentioned the 75%.

In our particular counties, we're looking at, it's 100% is trucked.

Very well.

Second question, please.

With the earlier question regarding the CapEx on your electric operations possibly declining this year and/or next, would that, therefore, push you folks to maybe a positive cash flow overall for this year or next year?

One is that capital in our electric business is going to be much higher in 2013 than it was in 2012.

And it's going to stay pretty high for a number of years.

I think we're projecting pretty close to $700 million this year and next year, before it starts declining down to the mid-$550 millions.

So, it's going to be high.

We've got $1.7 billion capital program.

We can't fund that from internally generated funds; we do have cash on hand that we can utilize.

But if you are in the utility business, you want to be growing rate base, and you don't want to necessarily have excess cash flow for very long.

It probably means you are in a pretty stagnant service territory.

So, we expect that these capital expenditure numbers are going to remain at this level for some time because this service area that we're in is -- I would venture to say it's probably, if not the best, one of the best in the country.

Very well.

Thank you, all.

Ali Agha, SunTrust.

I just wanted to follow up on two issues.

One on the use of the excess cash.

I know we have had discussions in the past, and I know cash is fungible.

But we've tried to look at that excess cash as perhaps adding to the overall growth profile for the Company.

You know, obviously been using the cash.

As you mentioned, you have about $500 million left.

I want to get your sense of, what are you thinking of that cash right now in the context of that, say, 4% to 7% EPS growth rate?

Does that cash put you at 100 basis points to that, I mean, keep you the higher end?

How should we think of the cash as it's being deployed, and how does it manifest in that growth rate that you are targeting?

We've talked about this in the past.

It certainly doesn't change the opportunities we look at.

We think we have lots of opportunities.

But the fact that it doesn't have a cost to it, it does add to your return in the near term.

So, I think there will be some upside in that because we don't have a cost associated with it.

But in terms of changing opportunity set, I don't think so.

Okay.

And then, second, you've talked about the MLP also frequently in the past as kind of a funding vehicle.

At the same time, you have also acknowledged that your Company is more of a conglomerate, if you will, of the regulated businesses and the unregulated piece.

Have you all thought about looking at those businesses and perhaps looking at them as two separate entities, and creating or unlocking shareholder value that way as opposed to just being driven by the funding needs?

What is your latest thinking on looking at these as two separate companies and perhaps unlocking some [conglomerate] value that's being discounted right now?

Ali, I think it's a good question, and we clearly think about that.

To some extent, the MLP gets at both of those, both the funding issue and the independent valuation issue.

So, I think we do consider, is there a way to unlock value where the sum of the parts that's being reflected in our stock price today is different.

And I think an MLP has the potential to do that for us.

So, yes, we're looking at that.

And if you are thinking about maybe we spin one offer versus keep the other -- we did that study a number of years ago.

We didn't think we had enough scale at the time, and I don't think that's really in our thinking today.

But ways to unlock value are absolutely in our thinking, and we'll attempt to do that.

And assuming the plan works out as you're envisioning the rest of the year, should we think of this as a 2014 event?

I would say we continue to look at -- and I'm not sure what the timing will be, and I don't think I can really comment on that.

But I want to tell you, the management team at CenterPoint is absolutely focused on trying to create shareholder value.

If we think there is a way to do it, we are going to pursue it.

2013 not likely.

Is that fair?

This is Gary.

I don't think I would start characterizing like that.

I really wouldn't.

I'm not trying to be cute about it.

I think 2013, could it be viable?

Of course it could.

But you come back to what would make it viable for us.

Of course, it is viable, but in the sense that when we see the visibility of the growth, and as we described, we do have a lot of clarity around the CapEx plan on our regulated businesses.

Greg is working diligently, and they have been originating business.

And we see that there is more clarity there.

I think we can execute, and as I've described to you, Ali, we can execute quickly on that.

So, we have the ministerial work done.

It's a question of doing the filing.

So, don't try to put it in 2013 or 2014.

I think what we said, it's front and center at the right time.

Okay.

I guess one point to just clarify.

Looking at the CapEx that you laid out for us currently, that CapEx would not necessarily support this.

You would probably need some new projects beyond that.

Is that fair?

I think it's all -- it's not -- I think that there is some validity in what you said, that we need to make sure we have confidence that we're going to be able to grow the business.

And I think we're getting more and more confident all the time around that.

I would say just kind of stay tuned on this one, Ali.

Got it.

Thank you.

Andrew Weisel, Macquarie.

Just a follow-up on one of the comments you just made.

I just want to make sure I heard it right.

You are now looking for long-term growth of 5% to 7%?

Is that compared to 4% to 6% previously?

Internally we say 4% to 7%.

We did say 4% to 6%.

We've kind of set our goals a little bit higher here than in the past.

But I would say that that doesn't indicate a change in our thinking.

Okay.

Thank you.

Maybe next time I would have started the press release with something like that because that is good news.

Thanks a lot.

Okay.

Thank you.

Thank you.

Since we do not have any other questions, we will end the call.

Thank you very much for participating today, and we appreciate your support.

Have a nice day.

This concludes today's conference call.

You may now disconnect.