CenterPoint Energy, Inc. (CNP) Q4 2012 Earnings Report, Transcript and Summary

Good morning, and welcome to CenterPoint Energy's Fourth Quarter and Full Year 2012 Earnings Conference Call with senior management. [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 you 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 Investors section. 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 71670374. You can also listen to an online replay on our website and we will archive the call for at least 1 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 pretax 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 10th anniversary as a standalone 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. 10 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 10 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 benefit costs. 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 backhaul 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 a 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 that we recognized 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 5 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 pipeline, and are continuing customer settlement discussions. From a market perspective, while a 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 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 3/4 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 have seen some recent announcements of increased rig counts in dry gas areas, we expect our volumes to remain at these levels in 2013. Given 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 based fee -- or volumetric fee-based and not subject to commodity risks. 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'm 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 at 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 ratings. The 2013 capital plan, as 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 proceedings, 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 8th consecutive year that 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. [Operator Instructions] Sarah, would you please give the instructions?

[Operator Instructions] Our first question is from Carl Kirst with BMO Capital.

First question, and 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, and 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 price end [ph] a little less than $4, and it was $2.50 at the time we had our call. So I think that's part of it. But generally, I wouldn't read much at all into that entire spread.

Okay. 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. And so 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& -- 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. And sorry, one clarification, is the CapEx that you mentioned for Field Services, does that include the Bakken project?

It does.

Your next question comes from the line of Charles Fishman with 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. So it's kind of a swap structure. But it's geared around 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 weather, 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.

Your next question comes from the line of Ali Agha from SunTrust.

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 $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've also been pretty clear and open about your interest in Oncor. And so I wanted to just understand where the focus remains in terms of, at least, opportunities right now, and whether the financial issues going on with energy futures holdings, does that cause the Oncor monetization to become more front burner or are you seeing any activity on that front?

First, we're still interested in growing Field Services, it's a big focus of ours. But it's not at the -- 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'd 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, so is it all the higher tax rate that's causing flat EPS or can you just 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. But 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 up with a 45% tax rate, because that had that non-tax deductible goodwill impairment. So you take that out, we ended it with a tax rate of approximately 33%. And that was really due to a lot of hard work over the last number of years to resolve issues with IRS, mainly legacy issues, so we did have a benefit in tax, in fact, some of it actually was reported in other income. So we had a benefit of approximately $0.09 all-in, if you will. So that's kind of come back. So we effectively have a higher tax rate this year, so the guidance reflects our expectations 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 a sense of some refunding but primarily some restructuring of debt, so you continue lower interest expense. This year, it was lower by about $34 million. Next year, think a maybe equivalent number, maybe a little bit more than that, so that's favorable to us. So that's some offset. And 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. And as you know, our objective is always -- we'll a, keep you informed, but our goal is to work as hard as we can to exceed the midpoint of that range and continue to grow our company this year.

Your next question comes from the line of John Edwards with Crédit Suisse. John Edwards - Crédit Suisse AG, Research Division: 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. John Edwards - Crédit Suisse AG, Research Division: Okay, great. That's helpful. And then just real quick on your natural gas distribution. It obviously was a really good quarter and the margin per customer was up quite a bit versus what we were thinking. Just maybe 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's any other things in that regard?

Scott, do you have anything to add there? Bad debt expense has been something that we've been working on for several years. As 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're running a pretty tight ship now. It's taken us 3 or 4 years to completely kind of revamp the way we run that business, and I think it's showing in through the reduced O&M. But we do have a lot of new rate mechanisms that's gone in over the last 3 or 4 years that provides 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'll just add to that as well, the couple other things that -- one of the bigger items that was -- if you're just looking at the quarter against prior quarter, it was around weather and usage. Between the 2 of those, they were up $6 million to $8 million over the prior quarter, so that was a good part of the delta.

Your next question comes from the line of Faisel Khan with Citi.

I wonder if you could give us a little bit more detail on the Bakken project. I see the open season and I guess it's for both gathering and pipeline takeaway capacity for, I guess, crude oil, liquids and natural gas, but if you can go to a little bit more granularity in terms of what the open season encompasses, that'd be great.

Yes. Let me ask Greg Harper to address that.

Faisel, the open season is primarily for a crude gathering system and it would have a little tank storage potential as well. It does not contemplate takeaway pipelines from those gathering termination point. We will be putting it into rail or other pipeline is the contemplation at this time. So this is strictly a gathering system, so taking crude oil from wellhead to central control points and then onto tankage.

Okay. And if our numbers are right, there's about, 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're going after?

Exactly. You've 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.

I think you'll 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's lots of wanting to get an alternative to trucking and this is the best alternative, honestly.

Definitely. There's been a paradigm shift with the number of trucks that Dave mentioned is the kind of result of the prolific nature of the crude level coming on from the drilling and the frac-ing.

Okay. So then, it would -- I could 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.

And so how do you guys compete versus everybody else? Like what's the competitive landscape like for in the Bakken? I would assume it's pretty competitive, but I don't know how you guys go about getting the business versus somebody else?

I mentioned before, Faisel, as 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've 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're going to do something that is kind of in concert with a big producer customer and have the similar type contracting 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 third -- the first quarter of last year?

Good question. What we found in the Mississippi Lime, where we were looking at it is there's a lot of high nitrogen issues. And we're just not seeing enough gas to gather to offset that issue for it takes to treat it. Now another major producer that had an RFP out has withdrawn that and that major producer has moved to a different area in 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.

Okay. Got it. And on the results of Field Services, throughput down from $237 million to $205 million, but operating income up year-over-year. Can you just 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'll give you a high-level, I won't give you exact numbers, because I don't want to get into our producers' falling volumes. But I would say that the difference obviously going from $237 million to $205 million is decline just across the board on our footprint, but the makeup, obviously, the increased margin, on the top line, I think, goes from $91 million to $109 million. That growth is driven by our contracts. The guaranteed return contract and primarily the volume commitment contracts.

Okay. So assuming that volumes -- well, let me ask you 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 in the call, but I think they've had some producers moving into our area and back into the Haynesville area, Encana announced that on their earnings call, with an increase in 5 rigs by year end. We don't have anything -- we don't have in our plan or 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'll 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. But we're -- I think our fleet agreement is in evergreen within the next 24 months. So that's -- again, we serve a fleet via MRT, that is the asset that we are currently in the middle of a rate case at FERC on. And we've 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 an 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 Line CP in 2017 or so.

Got it. And then just last question for me. On CapEx, you guys mentioned, I think, $1.8 billion in CapEx, did you guys give a breakdown in your prepared remarks, if you did, don't worry about it, I'll go back to the transcript, but if you didn't, I'd appreciate a breakdown of the CapEx.

You know, we've got those documented in the 10-K. Plus, if you look at the supplemental material, it's laid out there in a fair amount of detail, so probably the best way to find it.

Your next question comes from the line of Andrew Weisel with Macquarie.

Just 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 I'm just wondering why it drops and if there's potential upside there?

Andrew, I'll take that. There is -- if you noticed some downward movement, perhaps there's some conservatism in there, but there was also some projects that we have early on that end at that point. We're putting in a backup control center, which consumes about a couple hundred million dollars worth of investment over the near term. And once that ends, that's part of the reason it turns down. But the theme of kind of maintaining the ongoing investment of -- in infrastructure, for hardening and system maintenance, as well as load growth, that theme would kind of carry through but we'll have to see what actually happens in terms of whether growth picks up or slows down or maintenance requirements change. But 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 take -- that could fill that gap, but right now, this larger slug is really related to large projects.

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

Well, it really looks at the total capital spend 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 ending 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're 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've seen loads -- we've 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 that is 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 and we're obviously in communication with our producers weekly, monthly to make sure we're deploying our capital palatably relative to their growth and they're -- before they bring on their production. So basically, some of them had a forecast early in the year, maybe fourth quarter of 2011, what they would be doing in 2012, they've been modifying that during the year, and so we just pulled back the capital. However, they're committed to their acreage to us and/or volume commitments to those areas. So that will come once they start drilling. As far as 2013, that's the same thing we planned out this year. I think the Bakken is probably under 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. And then just lastly, if you can 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 2 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 in 2013.

Your next question comes from the line of Scott Senchak [ph] with Decade Capital.

Just looks like about 70% of your CapEx spend in '13 is going to the regulated electric and gas distribution segments. And just as I look out in your CapEx forecast and the K, it's roughly the same kind of spread, and I'm just wondering, is that kind of a change in theme going forward or is that just where the opportunities you see right now exist?

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, our bill control center, so it's -- 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 base growth there of 5% up to 7%. So they're going to provide some growth. Pipelines are the ones that probably are little less certain. That's probably flat to slightly up, if we move in some of the projects we're going after. And Field Services, we expect it's going to grow. It's been our fastest-growing unit the last 3, 4 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. So overall, our goal is to achieve that 4% to 7%, or 5% to 7% growth in earnings.

Your next question comes from the line of Scott Graham [ph] with Kellinger Capital [ph].

It's actually John Kiani [ph]. 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 Houston? 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 within Field Services, please?

Gary, why don't you take that one.

Okay. John, maybe to start, why don't we just start with MLP. We've been consistent on this, John, as you know, in our discussions, that we continue to see the formation of the MLP as an effective financing vehicle, and certainly, in terms of funding the growth for our midstream business. As to the timing of that, as we reported this morning, 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've been funding all of that, 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 it, David alluded to, and Scott, and certainly, Greg, as we have more visibility around that midstream growth in 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'll 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 have -- 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. And again, as Greg and his team worked 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 the MLP because it takes time to form it. Obviously, we've 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 the best interest of our shareholders to do so.

Got it. And then one other separate question. How should we think about the potential bid 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 nonregulated 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 that's -- we'll work hard at it if it ever comes on the market.

Your next question comes from the line of Steve Mars [ph] with 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 a railroad in the same area?

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

And I'd say that, I think it was Faisel or Carl that mentioned the 75% In our particular counties, we're looking at it as 100% is truck.

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

Your next question comes from the line of Ali Agha with SunTrust.

I just wanted to follow up on 2 issues. One on the use of the excess cash, I know we've had discussions in the past. And I know cash is fungible, but we try to look at that excess cash as perhaps adding to the overall growth profile for the company. Obviously, you've been using the cash, as you mentioned, you've got about $500 million left. I just wanted to get your sense of where -- what are you thinking of that cash right now, in the context of that, say, 5% to 7% -- 4% to 7% EPS growth rate, does that cash put you at 100 basis points to that, I mean, keep you at 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're 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 talked about the MLP also frequently in the past as kind of a funding vehicle. At the same time, you've 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 2 separate entities and creating or unlocking shareholder value that way, as opposed to just being driven by the funding needs? What's your latest thinking on looking at these as 2 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're thinking about maybe we spin one off 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 it 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, and if we think there's a way to do it, we're 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 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. So when 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 and it's a question of doing the filing, so don't try to put it on 2013 or '14. I think, what we said, it's front and center at the right time.

Okay. I guess, one, I'll just clarify. But looking at the CapEx that you've 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 there is some validity in what you said, that we need that 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. So I would say just kind of stay tuned on this one, Ali.

Our last question comes from the line of Andrew Weisel with Macquarie.

Just to follow up on one of the comments you just made. I just want to make sure I heard it right. You're 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 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.

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.