CenterPoint Energy, Inc. (CNP) Q3 2012 Earnings Report, Transcript and Summary

Good morning, and welcome to CenterPoint Energy Third Quarter 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 for CenterPoint Energy. I'd like to welcome you to our Third Quarter 2012 Earnings Conference Call. Thank you for joining us today. David McClanahan, President and CEO; Gary Whitlock, Executive Vice President and CFO; Scott Prochazka, Executive Vice President and Chief Operating Officer; and Greg Harper, Senior Vice President and Group President of Pipelines and Field Services, will discuss our third quarter 2012 results. We also have other members of management with us who may assist in answering questions following the prepared remarks. Our earnings press release and Form 10-Q filed earlier today are posted on our website, centerpointenergy.com, under the Investors section. 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'd like to mention that a replay of this call will be available through Thursday, November 14, 6:00 p.m. Central Time. To access the replay, please call (855) 859-2056 or (404) 537-3406 and enter the conference ID number 30496727. 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. Good morning, ladies and gentlemen. Thank you for joining us today and thank you for your interest in CenterPoint Energy. This morning, I will discuss our consolidated results for the third quarter of 2012. Gary will discuss 2 unusual amount cash items recorded this quarter, as well as some recent financing activities. Scott will comment on the performance of each business unit. And finally, Greg will discuss certain aspects of our Field Services business. This morning, we reported net income of $10 million or $0.02 per diluted share. The results for the third quarter of 2012 include 2 unusual items. First, a $252 million noncash goodwill impairment charge associated with our competitive Energy Services business. And second, a $136 million noncash pretax gain associated with our purchase of the remaining 50% interest in the Waskom gathering and processing joint venture. Excluding these unusual items, net income for the third quarter of 2012 would have been $174 million or $0.40 per diluted share. Net income for the third quarter of 2011 was $973 million or $2.27 per diluted share. As you may recall, last year, we also recorded an unusual item. Net income of $811 million associated with the final resolution of the true-up appeal. Excluding this unusual item, net income would have been $162 million or $0.38 per diluted share. Operating income for the third quarter was $88 million. Excluding unusual items, operating income for the third quarter would have been $340 million compared to $357 million for the same period last year. As you will hear in a few minutes from Scott, our businesses delivered solid performances this quarter, in line with our expectations. Our regulated electric and gas distribution utilities produced strong results and despite the low natural gas prices and the lack of basis differentials, our midstream and competitive Energy Services businesses performed well. I will now turn the call over to Gary.

Thank you, David, and good morning to everyone. Today, I would first like to discuss the 2 unusual items that are included in our results for the third quarter. Then, I will review our debt refinancing, earnings guidance and dividend declaration. The $252 million noncash impairment charge relates to the goodwill resulting from the 1997 merger between Houston Industries and NorAm Energy. $335 million of that goodwill was associated with our competitive Energy Services business. In the third quarter of each year, we perform a goodwill impairment test. The adverse wholesale market conditions facing our Energy Services business, specifically the prospects for continued low geographic and seasonal price differentials, led to a reduction in our estimate of the fair value of goodwill associated with this business. No other business unit required a goodwill impairment charge. We also recorded a $136 million noncash gain as a result of our acquisition of the remaining 50% interest in the Waskom joint venture. This acquisition is classified as a business combination achieved in stages requiring a writeup of our original 50% interest to fair value. Turning to our financing activities during the quarter. We took advantage of very low interest rates and refinanced some of our debt. Specifically, Houston Electric issued $800 million of general mortgage bonds at attractive rates and redeemed $800 million of Houston Electric general mortgage bonds scheduled to mature in 2014. The redemption premium on the 2 series was approximately $69 million, and this refinancing will reduce our annual interest payments by approximately $28 million. Now, let me discuss our 2012 earnings guidance. This morning in our press release, we reaffirmed our second quarter estimate for annual earnings in the range of $1.13 to $1.23 per diluted share. Our guidance excludes the effects of the goodwill impairment charge and the Waskom acquisition gain. As a reminder, our earnings guidance range is based on our performance to date and includes a number of variables such as commodity prices, volume throughput, weather, regulatory proceeding and our effective tax rate. I'd also like to remind you of the $0.2025 per share regular dividend declared by our Board of Directors on October 24. We believe our dividend actions continue to demonstrate a strong commitment to our shareholders and the confidence the Board of Directors has in our ability to deliver sustainable earnings and cash flow. Now, let me turn the call over to Scott, who will discuss the quarterly results of our businesses in more detail.

Thank you, Gary, and good morning to everyone. I'll begin with Houston Electric which reported operating income of $205 million this quarter or $8 million less than the third quarter of 2011 which included the benefits of extremely hot and dry summer weather. This year's operating income benefited from the growth of more than 40,000 customers since the third quarter of last year. This represents a growth rate of 2%, which we believe should continue for the remainder of the year. We also benefited from higher transmission-related revenue, the ongoing recognition of deferred equity returns associated with the company's true-up proceeds and an increase in miscellaneous revenues. More than offsetting these benefits, however, were a $38 million impact from the return to more normal weather and a $9 million impact from the rate changes implemented in September of 2011. Overall, Houston Electric had a strong quarter and is expected to have another good year. To address the growing infrastructure needs of the Houston service territory, we expect to invest capital in excess of $500 million per year for the next several years resulting in rate base growth of approximately 4% per year. Given our transmission and distribution capital recovery mechanisms, we don't anticipate the need for a major Houston Electric rate case in the near term. Our natural gas distribution business reported $5 million of operating income in the third quarter of 2012, which was $7 million more than last year. This quarter benefited from the growth of more than 31,000 customers since the third quarter of last year. Additionally, we have been focused on productivity gains and operating efficiencies to offset the impact of an extremely mild winter. We have seen the benefit of these efforts and expect to see similar benefits for the remainder of the year. Annual rate adjustment mechanisms in a number of our jurisdictions continue to help us recover new investments, as well as to offset reductions in usage without the need for expensive and time-consuming rate proceedings. We are also benefiting from increased customer charges in our Texas jurisdictions. We continue to focus on system reliability by replacing older infrastructure and on upgrading our systems to enhance customer service. These investments, together with normal load growth and system maintenance, are expected to require capital expenditures of $350 million to $400 million annually and produce rate base growth of approximately 6% per year. Now, let me turn to our midstream businesses. Our interstate pipelines unit recorded operating income of $48 million compared to $60 million for the same quarter of 2011. The decline was primarily the result of reductions in seasonal and market-sensitive transportation and ancillary services and a reduction in compressor efficiency on our Carthage to Perryville pipeline due to lower volumes. Low natural gas prices and significantly compressed basis continue to adversely impact this business. Equity income from SESH, our joint venture with Spectra, was $8 million compared to $6 million in the same quarter of 2011, reflecting the benefit of a new contract with an anchor shipper that started in January of this year. From a commercial perspective, we continue to pursue opportunities to serve customers on or near our pipelines with particular focus on power generation and natural gas producers. In addition, we continue to evaluate the current rates and rate structures for our 2 interstate pipelines. In August, Mississippi River Transmission filed its first rate case since 2001 and requested a $47 million rate increase. Our filing is based on an updated cost of service including new depreciation rates, a capital structure composed of 61% equity and a 13.6% return on equity. We also sought a recovery compliance cost surcharge to recover future security, safety and environmental costs associated with mandated requirements. In September, the FERC issued an order accepting MRT's filing, suspending the filed tariff rates until March of 2013 and limiting the scope of the surcharge to the recovery of security costs. MRT has asked for a rehearing on the surcharge issues. Unless we reach a settlement on the rate case, we expect the third quarter 2013 hearing. In October, we also initiated discussions with customers for a new tariff structure on our CEGT pipeline. These discussions centered around an updated cost of service and the mechanism for recovering increased costs associated with security, safety and environmental activities similar to the mechanism we requested in our MRT rate filing. Turning now to our Field Services unit. We reported operating income of $55 million compared to $61 million for the same quarter of 2011. Operating income benefited by $7 million from the Amoruso and Prism acquisitions. These benefits were offset by lower revenues from sales of retained natural gas due to lower prices, reduced throughput from our traditional basins and the timing of revenue recognition related to throughput commitments. These throughput commitments are an important feature of our contracts, and Greg will discuss them in greater detail later in the call. With respect to our gathering volumes, throughput increased approximately 7% compared to the third quarter of last year. We expect our overall system throughput to average around 2.4 billion cubic feet per day through year-end, including approximately 200 million cubic feet per day from our recent acquisitions. Our competitive Energy Services business reported an operating loss of $7 million, excluding the goodwill impairment discussed -- impairment charge discussed by Gary, as compared to an operating loss of $10 million in the same quarter of last year. After adjusting for mark-to-market accounting and gas inventory write-downs, results for the third quarter of 2012 increased $11 million compared to the third quarter of 2011. This business is benefiting from the elimination of uneconomic fixed cost transportation and storage agreements and the growth in both retail customers and sales volumes. Our focus continues to be on expanding our customer base, rationalizing our fixed costs and growing our product and service offerings. In summary, our business units delivered solid, operating and financial results. And the benefits of our balanced electric and gas portfolio were again evident this quarter. I will now turn the call over to Greg.

Thank you, Scott. I want to take this opportunity to provide some additional information about our Field Service business. Specifically, we continue to get questions on our throughput commitments and recent acquisitions. Field Services provides gathering, treating, processing and other related services to producers in and around their traditional natural gas production basins of Arkoma, Anadarko and ArkLaTex, as well as in the unconventional shale plays of Fayetteville, Haynesville and Woodford. We operate 4,000 miles of gathering pipelines, processing plants with a capacity of 625 million cubic feet per day and treating plants with a capacity of approximately 9,000 gallons per minute. Today, about 40% of our volumes come from traditional gathering basins, while 60% are from the shale plays. These percentages are inclusive of the recent acquisitions which we consider in the traditional category. Commercial and operating initiatives evolve with market dynamics and customer requests. We strive to revive best-in-market services, especially when it comes to being on time and on budget. Our track record, combined with our focus on building strong relationships, serves us well as projects emerge. Generally, our Field Services business seeks unlevered after-tax returns on investment in the low- to mid-teens. While other gatherers may seek higher returns, our contracting strategies mitigate project risk with longer terms of 10 to 15 years and throughput commitments or guaranteed returns, especially on large capital projects. Of course, without these mitigants, we would require higher returns. However, we find that our customers value price assurance and market access certainty provided by our contracting strategies. In turn, we benefit from more stable revenues and cash flows. Without this throughput commitment strategy, we would be recognizing less revenue this year. Now, let me discuss how throughput commitments can affect the timing of revenue recognition. Throughout the year, producer production reports and actual volumes are closely monitored to ensure that revenue is recognized in accordance with contract terms and throughput commitments. First, contract years are usually not the same as calendar years. Second, we recognize revenue based on both actual and projected flows. If a producer report indicates that production will not meet the throughput commitment in a particular contract year, we calculate the amount of revenue associated with the actual production and the amount of payable under the throughput commitment for the applicable calendar quarter. Shortfall throughput volumes and retained gas are not included in throughput data, which we provide as part of our supplemental financial materials. As a rule of thumb, we have previously stated a good rule of thumb is that retained gas is equal to about 1.5% of throughput. However, we have and can realize levels at or above 2% based on concerted optimization efforts. Following our recent acquisitions, we now own 100% of the Waskom gas processing plant in East Texas. This facility is capable of processing approximately 320 million cubic feet per day of natural gas. It also includes a 14,500-barrel per day fractionation plant in an ethane line which directly serves a major market. Waskom provides several takeaway options for natural gas including our CEGT pipeline and our Carthage to Perryville pipeline. Furthermore, the rail loading facility that was completed in late 2011 provides customers optionality and increased access to premium natural gas liquids markets. We are 2 months into our integration of all the Prism assets and are beginning to implement changes to optimize certain operations at these facilities. From a risk standpoint, we mitigate commodity exposure through our contracting methods. On the liquid side, our commodity-sensitive contracts account for about 35% of all of our processing revenue. However, we have the option to change the majority of these contracts to fix these structures if we so choose. Finally, we are pursuing a number of potential Field Services projects in the Bakken, Mississippi Lime, Tuscaloosa Marine and other place in or near our footprint. Clearly, we would like to be in a position to discuss these more completely. However, we're still in the discussion, evaluation and/or negotiation phase, and are not able to give more details at this time. We can say that the Bakken survey and right-of-way assessment have been completed and we're finalizing our estimates of the capital requirements for this project. Now, I'll turn the call back over to David.

Thank you, Greg. Last month, we celebrated our 10th anniversary as a stand-alone independent public company. I would like to take this opportunity to thank our employees who have been so instrumental in the success of our company. I couldn't be more proud of them. Our balanced portfolio of electric and natural gas businesses has served us well and we expect that to continue. Our business performance and execution have allowed us to grow significantly and have put us in a strong position as we pursue attractive opportunities. I feel better today about the position of CenterPoint Energy than at any time during our 10-year history. Once again, I would like to thank you for your interest in interest CenterPoint Energy. We will now open the call for questions.

[Operator Instructions] Our first question is from Ali Agha with SunTrust Robinson.

Gary, could you update us in terms of what you would define as your excess cash position at this point?

Yes, we're between $500 million and $600 million.

$500 million and $600 million. And when you look at the deployment of that cash, and I know the Bakken project has been one of the front burner ones. From a timing perspective, is it -- should we expect that we could see some returns on any of that investment in 2013? Or is it more likely 2014 and beyond when we -- the earliest when we would see returns?

Let me take that question. As you know, last call, I indicated that I thought we would deploy all of this cash by the end of next year. So we're going to deploy it either in our core businesses, and we have plenty of organic growth in especially our utilities, and some in our other businesses as well. But we also are attempting and working hard to try to invest in some new opportunities outside our core businesses. I think there's a chance some of that could be reflected in late 2013, but most likely, it's a 2014 kind of operating income impact.

Okay. And David, one other thing. If I look at your Field Services business, just looking at the existing portfolio and not tackling in any new projects or investment, this current portfolio, what kind of annual growth rate can this support?

It really depends on natural gas prices. As gas prices increase, I think we're going to see more growth prospects. We serve traditional basis -- basins, as well as dry gas basins. At this low gas price, we're not seeing a lot of well activity. Probably, well activity this year is about half or maybe even a little less than half of what we saw last year. But we also know there is a heck of a lot of gas in these basins and it will ultimately be produced. So as gas prices move up, I think we're going to see activity, which is going to drive just gathering volumes and expansions of this system. But just -- not just as importantly, but there is another aspect, and that's our retained gas piece. As Greg said, we retain about 1.5% and 2% if we can really optimize compression. That provides upside as natural gas prices rise as well. And so, I think we'll see it on the natural gas sales retained gas, as well as just throughput, in our system. That's going to be a little further down the road because we know that gas prices aren't expected, at least in our forecast, to jump above $4 for a year or two.

And last question, Gary, just to clarify. The effective tax rate, if you take out all the non-recurring stuff, what was that for the quarter and what are you budgeting for the year?

Okay, yes. If you exclude the unusual items for the third quarter, our effective tax rate for the third quarter would have been about 24%. That compares, Ali, to a run rate of 37% effective tax rate. We did, in the third quarter, benefit from approximately $17 million of favorable IRS settlements. But for the fourth quarter and on, think about 37%.

Your next question comes from the line of Carl Kirst with BMO Capital Markets.

Greg, just a couple of quick questions. And understanding there's only limited you can say about the Bakken, we're narrowing the cost. Previously, I think you sort of ring fenced it in sort of $100 million to $200 million range with larger long-term aspirations. Are we still in the same ZIP code? I mean, is the general scope of the project essentially still the same?

That's correct, Carl. I'd say it's still in that $100 million, $200 million range. Our producer customer is also still confirming what their production profiles look like. And as they get more optimistic about it, obviously, the capital would be on the higher end. But if it stays where it is right now, it'd be on the lower $100 million to $150 million end. But if they hit things, as they would like to see, it'd be on the upper end.

Okay. No, fair enough. And then if I could just ask you to -- and appreciate you got the organic projects, Bakken, Mississippi Lime, et cetera. What about from an M&A standpoint, have you seen any -- a change in producer sentiment over the last 3 months, say for instance, from the 3 months prior as far as their willingness to divest given that the choppiness of commodity prices? Or is it pretty much just kind of the same as it's been through the year?

No, I would say that -- it's a good question because I think the producer activity is still there. I think some of the things that are on the market, with the particular producers that are putting them on the market, aren't necessarily in what we would consider areas that we would want to pursue, or on a contracting strategy that we want to pursue or they would be willing to commit to. The Encana opportunity in Amoruso was a really nice opportunity because they were willing to commit to a volume commitment. Some of the things we are seeing on the market today, a shipper, producer is not necessarily willing to do that.

Okay. And then maybe just sort of a last question. This is maybe more for clarification and throw it open to David, Scott or Gary. But as we look at the noncash goodwill impairment charge to the marketing, was that all due to one transaction? I'm just -- I can't recall when that type of dollars were deployed in the commercial services. I'm sorry, I just didn't do what that stemmed back to?

Well, that goes back, as I mentioned in my prepared remarks, Carl, to the acquisition that Reliant had of NorAm Energy back in 1997. And the goodwill associated with that acquisition, a portion of it was allocated to our CES business, our commercial energy -- Competitive Energy Services business. And based on today's economics, we have to look at, of course, in each year, the potential of an impairment. And that's what really I described, is we looked at that, which is on an income basis, we looked at the projected cash flows of that business based on the dynamics of the marketplace, discount those back and effectively found that this goodwill that was $335 million was impaired. We valued it now at $83 million and the $252 million is the write off of that. So it's noncash, and as I mentioned, no other business was impacted. That was just around CES and it's all the things you know about and others, really driven by the market dynamics, and...

Sure, no. I appreciate that I'd missed the first 5 minutes, so all you had to do is say NorAm. I appreciate the color.

I wasn't here then, either.

[Operator Instructions] Your next question comes from Faisel Khan with Citigroup.

A couple -- just a couple of small questions. You mentioned the better results in gas distribution from non-annual rates, but also customer growth. Can you elaborate a little bit more where that customer growth is coming from?

Yes. We've seen customer growth, I think, in the order of about 1% kind of on a year-over-year. And the split in customers is probably very heavily Texas, with a little bit in Minnesota. It's probably the mix. But it's the 31,000 that we've seen, that addition that's driving that 1% increase.

Okay, got you. And then on the increase in customers at the competitive natural gas business, up 17% over the last year, what's driving that?

Yes, so the drivers behind that is a transaction, a purchase we had made of a book of customers that was a key part of it, as well as just the ongoing organic efforts of the team to add customers where we currently serve.

Okay. And that book of customers you bought, is that -- would you say that, that is -- that, that book has been incrementally more profitable to the business, and so it's offsetting kind of the underlying assets? Or is it kind of similar margins to the business you had before?

I'd say it's similar margins to the business that we've had before. So it was a good -- it was a good addition in terms of extending the quality of the retail business, but it was very -- it's very similar to what we currently have in place.

Okay. Then on the midstream business, can you give us a little bit more of a breakdown on the volumes in terms the legacy volume declines versus the new volumes you've hooked up to the business and what were the underlying declines in the legacy volumes?

I think what Scott mentioned, we were at 60% on the shale volumes and about 40% on the traditional basins volumes on those billable or throughput reported numbers in the call. I think, or we have definitely seen a continued uptick in our year-over-year volumes in definitely the Haynesville and North Louisiana volumes. While not as great as we had anticipated, they are still growing. And the traditional basins, excluding our recent acquisition, I'd say would be down slightly.

When you say down slightly, does that -- are you seeing 5% declines, 2% declines, 10% declines?

Yes, I'd say it's been averaging or fluctuating between 5% to 10%.

[Operator Instructions]

Sarah, as we do not have any other questions, we will end the call for today. Thank you, everyone, very much for participating. We appreciate your support.

This concludes CenterPoint Energy's Third Quarter 2012 Earnings Conference Call. Thank you for your participation.