埃特莫斯能源 (ATO) 2012 Q1 法說會逐字稿

Greetings, and welcome to the Atmos Energy first-quarter 2012 earnings conference call. At this time, all participants are on a listen-only mode. A brief question-and-answer session will follow the formal presentation. (Operator Instructions). As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Ms. Susan Giles, Vice President of Investor Relations for Atmos Energy Corporation. Thank you, Ms. Giles. You may begin.

Good morning, everyone, and thank you for joining us. This call is open to the general public and media, but designed for financial analysts. It is being webcast live over the internet. We have placed slides on our website that summarize our financial results. We will refer to just a few of the slides during the call, but we will be happy to take questions on any of them at the end of our prepared remarks. If you would like to access the webcast and slides, please visit our website at AtmosEnergy.com, and click on the conference call link. Additionally, we plan to file the Company's Form 10-Q later today. Our speakers this morning are Kim Cocklin, President and CEO, and Fred Meisenheimer, Senior Vice President and CFO. There are also other members of our leadership team her to assist with questions as needed.

As we review these financial results and discuss future expectations, please keep in mind that some of our discussion might contain forward-looking statements within the meaning of the Securities Act and the Securities Exchange Act. Any forward-looking statements are intended to fall within the Safe Harbor Rules of the Private Securities Litigation Reform Act of 1995. And now I'd like to turn the call over to Kim Cocklin. Kim?

Thank you, Susan. Good morning, everybody, and we certainly appreciate you joining us and your interest in Atmos Energy. Before we begin, I would like to extend my congratulations to all the Giants fans on the phone, and condolences to the Patriots and the Cowboys fans. Yesterday, we did report first-quarter consolidated net income of $69 million, or $0.75 per diluted share, compared to $74 million or $0.81 per share one year ago. When you exclude the unrealized gains in both periods, net income was $56 million or $0.61 per share this quarter compared to $74 million or $0.81 last year.

Regulated operations contributed 93% of our net income, and nonregulated operations contributed the remaining 7%. Regulated earnings were in line with our first-quarter expectations of fiscal 2012. Abundant natural gas supply across the nation has created a low gas price environment, which is extremely good for utility customers. However, our nonregulated operations are adversely impacted by such a low price and low volatility, and did not contribute as expected. Our liquidity and financial position remained very strong. Our debt-capitalization ratio was 53.4%, at December 31, compared with 51.4% one year ago. Short-term debt this quarter increased to $390 million, compared to $248 million in last year's quarter, primarily to fund natural gas purchases in our nonregulated segment and increased capital spending. During the quarter, we purchased about 388,000 shares under our current share repurchase program, at an average price of $32.31 per share.

Also during the quarter, we resolved the FERC investigation that arose in 2007 in our nonregulated segment. Under the terms of that agreement, we paid about $12 million plus accrued interest. We cooperated with the FERC throughout the process, and had adequate reserves for the resolution. Yesterday, our Board of Directors declared the 113th consecutive quarterly cash dividend. The indicated annual dividend rate for fiscal 2012 is $1.38. Our CFO, Fred Meisenheimer, will review our earnings results in greater detail now, and I'll return for closing comments and will open up the call for questions. Fred?

Thanks, Kim. Good morning, everyone. As a reminder, because of the agreement to sell our distribution assets in Missouri, Illinois, and Iowa, we combine and report the financial results for those assets on the income statement as discontinued operations. Therefore, the corresponding detail by line item will be excluded from my prepared discussions.

Rate relief remains the primary driver of our success in the regulated operations. Rate increases for distribution and Atmos Pipeline - Texas combined generated almost $13 million of incremental margin quarter-over-quarter, with about $5 million for distribution and $8 million for APT. Specifically, distribution margins were negatively impacted by utilizing required updated weather data to calculate the weather normalization adjustment in the Mid-Tex division, which we expect to substantially flip around by the end of the heating season. Regulated transmission and storage, we refer to as APT, benefited from the rate case that became effective last May. Also, during the current quarter, APT's consolidated throughput rose 5%, due to increased through-system demand and the execution of new delivery contracts with local producers.

Turning now to our nonregulated operations, and you may want to turn to slide number 7, the ongoing and unfavorable market cash conditions continued to pressure this segment. We anticipate natural gas storage levels will remain high for an extended period of time, and for unseasonably warm weather to continue during the second quarter of fiscal 2012. We expect gas prices to remain relatively low, with little volatility, and spot to forward spread values and basis differentials to remain compressed. Realized delivery gas margins decreased about $5 million from the same period one year ago, due to a 4% decrease in consolidated sales volumes, mainly due to warmer weather, which reduced sales to our utility, municipal, and other weather-sensitive customers. These decreases were partially offset by a 6% period-over-period increase in sales to new and existing industrial and power generation customers. A decrease in gas delivery per-unit margins from $0.15 per Mcf in the prior-year quarter to $0.10 per Mcf in the current-year quarter, primarily due to lower basis differentials, resulting from higher natural gas storage levels, coupled with increased transportation rates charged by the interstate pipelines being utilized to deliver natural gas to our customers.

Realized asset optimization margins decreased about $26 million from the prior-year quarter. The prior-year quarter, due to compressed spot to forward spread values, AEH traded more frequently in the daily cash market, and earned inter-month trading gains that exceeded the demand fees paid for its contracted storage capacity. In the current quarter, AEH elected to take advantage of falling natural gas prices by purchasing and injecting a net 15.7 Bcf into storage, and capturing incremental physical to forward spread values that should be realized in future periods. As a result of this decision, we realized no storage withdrawal gains to offset the realized losses on the settlement of financial instruments used to hedge these natural gas purchases. We anticipate this trend will continue during fiscal second quarter. However, based on the current setup, a substantial portion of the incremental margins captured during the quarter are anticipated to be realized during the third and fourth quarters of fiscal 2012, when contracts expire and the realized gains are recognized.

Moving onto our earnings guidance for fiscal 2012, as a reminder, our practice is to provide annual earnings guidance only. We have affirmed our fiscal 2012 earnings per share guidance of $2.30 to $2.40 per diluted share, and have updated the expected contribution by business segment. This range assumes no mark-to-market impact at September 30, 2012, but does include a pretax book gain of $5 million from the sale of our Missouri, Illinois, and Iowa distribution assets, which is still anticipated to close by the end of fiscal 2012.

Let me draw your attention to slide 20 and 21, where we have outlined our budget assumptions and net income by segment. Our projections now include a $3 million increase to net income for each of the regulated gas distribution segment and the regulated transmission and storage segment, with an equal and offsetting $6 million decrease in the nonregulated segment. As a result of the challenges of higher natural gas storage levels and the unseasonably warm weather, we are now re-projecting nonregulated delivered gas and storage and transportation margins to range between $70 million to $75 million, down slightly from the $74 million to $82 million previously.

We also anticipate delivered gas volumes of between 435 to 445 Bcf, down about 10 Bcf at a per-unit rate of $0.12 to $0.13, which was originally forecast at $0.13 to $0.14. Our original guidance for nonregulated asset optimization margins assumed summer-winter spread of about $0.49, with associated storage fees of $0.34, netting to $0.15 per decatherm. Due to the erosion of spread values and the continued weak market fundamentals I just mentioned, we are lowering our expectations for asset optimization margins to the range of breakeven to $2 million. For the near term, we are expecting asset optimization activities to at least offset the contracted storage demands.

We do not foresee returning to the level of margin contribution we experienced in previous years of high market volatility. Keep in mind however, storage is essential for the over 1,000 customers to which AEH provides services, such as our distribution divisions, utilities, and other regulated municipalities contracting for firm, natural gas supply. We are working to shorten the lease terms of contracted storage to one year or less, to better manage storage costs. Total nonregulated margins are expected to be between $70 million and $77 million, again with no impact from mark-to-market of our physical storage and offsetting financial hedges.

In the regulated segments, we have confidence that we can achieve a $6 million increase in net income. Because of the mild weather we encountered in the first quarter, and continue to experience in the current quarter, our crews are able to focus on capital projects, thus reducing O&M expenses. Additionally, they have not encountered an adverse weather event, which drives incremental O&M; the overtime and general expenses associated with such a weather event. This held true for both our distribution and regulated pipeline operations.

Also in our distribution business, the new Rule 8 regulation encourages spending for system safety and reliability in Texas. It also allows regulatory asset treatment and defers expenses for carrying costs. We now have more clarity and a better understanding as to the treatment of these expenses, and believe there is some upside, which we did not anticipate when our fiscal 2012 guidance was first announced. In our regulated transmission and storage segment, lower O&M costs from the absence of a weather event as I just mentioned, as well as a shift to more capital type work with the 70-degree weather we've been experiencing, also should reduce O&M expenses from second quarter.

Also, at the regulated pipeline, we're getting better value from our proprietary storage and commanding higher demand fees on new contracts than we anticipated. There is a strong appetite from producers and marketers for firm capacity transportation, which Kim will discuss in a minute. Our original earnings projection assumed an average annual short-term interest rate of about 60 basis points, which is currently running at just 40 basis points. We think we've got about $1 million of upside for the remainder of the fiscal year. We have increased our capital budget by $50 million, which sets a new range of between $680 million to $700 million for fiscal 2012. Increased capital spending will primarily be at Atmos Pipeline - Texas. Kim will offer more details in a few minutes.

As you know, the second fiscal quarter historically generates the greatest revenue for us. We remain optimistic that we can achieve earnings per diluted share of between $2.30 to $2.40, and a consolidated net income range between $210 million and $220 million for fiscal 2012. Thank you for your time, and now I'll turn the call back over to Kim. Kim?

Thank you very much, Fred. Capital investment, as Fred talked about, is an extremely important component of our earnings growth. As you well know, it increases our rate base and the more valuable the rate base for our regulated operation, the greater opportunity for increased revenues and growth. And as Fred mentioned, we are projecting investing significant capital on our intrastate Atmos Pipeline - Texas system to increase its capacity to secure new long-term gas supply on a firm, reliable basis and enhance the reliability of our service in certain critical locations along the Mid-Tex system, and this was approved by our Board of Directors yesterday, when they added an increase to capital budget for fiscal 2012 by $50 million, as Fred said.

There's two projects that we're talking about. The first is the Line W Looping Project, which is designed to secure new long-term gas supply for the Dallas-Fort Worth metroplex area. Atmos Pipeline Texas is going to spend between $47 million and $52 million in capital to construct a 34-mile 24-inch high-pressure pipeline north of Fort Worth connecting Boyd, Texas, to a producer's interconnect in Montague County. The project is supported by a multi-phased firm transportation agreement with a producer for deliveries to the north side loop through the year 2019. The rates, which are designed on a straight fixed per-well basis will consist of demand fees, which are expected to generate incremental annual revenue of $10 million to $14 million beginning in fiscal 2013. A lot of the project up there is driven by the continued drilling by producers of wet gas and gas that's associated with oil in the Montague County area.

Also, during fiscal 2012, through fiscal 2014, Atmos Pipeline - Texas is projected to spend between $110 million and $120 million in capital to construct a 59-mile 24-inch high-pressure pipe that connects Line X south of Fort Worth up to Boyd, and the new Line W that I just talked about. This pipeline is intended to eliminate the dependency of an interruptible exchange agreement, and improve service reliability during critical peak periods to current regulated customers of Atmos Pipeline - Texas. These capital expenses are GRIP-eligible, with an 11.8% return on equity, and the project certainly improved the reliability of our pipeline system for the customers we serve.

As we outlined last November, we are planning increased capital investment over the next five years, in particular, to fortify our regulated asset infrastructure. We expect to grow our regulated rate base from between 6% and 6.5% on a compounded annual basis during this five-year period, resulting in earnings growth and enhancing the reliability and safety of our regulated assets. We continue to successfully execute our rate strategy to reduce lag, improve return on equities, and increase recovery of fixed costs. Last week, we filed a rate case in the Mid-Tex division, which requests an annual operating income of $46 million for the affected cities. It's based on a proposed return on equity of 10.9%, resulting in a proposed overall return of 8.74%.

The cap structure in the case is 49% debt, 51% equity. The authorized rate base investment is $1.53 billion. Case is based on a test year that ended September 30, 2011, with a forward-looking planned investment and associated deferred taxes included through March of 2012. We are also seeking the approval of a new annual rate review mechanism, which would continue to allow annual cost adjustments without the need to file future rate cases. The case, you remember, was filed as a result of the existing rate review mechanism expiring at the end of January. We were unable to renew that rate review mechanism, so we did file this rate case to address the deficiency in the Mid-Tex division. As you may recall, our fiscal 2012 projections did not include any rate increase in the Mid-Tex division, because we were continuing negotiations with the cities at this time is to review the rate mechanism.

Also, in the Mid-Tex division, we filed the first City of Dallas annual rate review filing in January, requesting an increase in operating income of $2.5 million. Copies of the Mid-Tex filings can be found on our website. So far this fiscal year, rate outcomes have provided annual operating increases of $7.7 million. Other rate actions, which we have filed and are pending, include a Kansas case, which seeks an increase of $6.1 million, and a filing that we made yesterday for West Texas, which seeks $11 million there. In total, we have about $66 million in rate requests outstanding, and anticipate filing another 10 to 15 cases this fiscal year, which would request between $20 million and $30 million of additional operating income increases.

We started fiscal 2012 on solid footing. We continue to have very healthy credit ratings, which lets us borrow money at very attractive rates. Our balance sheet is very strong, and we're focused on keeping our cap structure within the 50% to 55% range, and we remain committed to growing our assets and delivering consistent long-term financial success. We thank you for your time this morning, and we'll open the call up for questions now. Jackie?

Thank you. (Operator Instructions). Our first question is coming from Ted Durbin of Goldman Sachs.

Maybe I can just come back to the distribution segment. I'm trying to understand exactly -- I'm not sure I followed the weather normalization impact. You're saying that you think it will largely reverse, it sounds like, from your fiscal second quarter? And then maybe just can you go again into the drivers -- you bumped guidance up a little bit in the segment, about $3 million, just a little bit of drivers of why guidance this quarter went up this quarter?

Well, we're experiencing unusually warm weather, and so we have redirected our crews instead of doing O&M type work, they're working more on capital projects. With the absence of any weather events, we're not incurring the overtime and additional administrative costs that are related to that, and so we're seeing upsides from those things occurring and reducing the expenses. We've gotten some good results in some of our rate activity that we've had that has been a little bit better than what we had in our original estimates, and so that has improved things, and then also as we've gotten more into this Rule 8 and the benefits from that, where we're able to defer and capitalize certain costs, we've realized that there's more benefit there than what we originally anticipated. So kind of a combination of all those things. We feel very, very confident in being able to raise the level of income from both of our regulated unit segments, both the utility and the pipeline.

Okay. Thanks, Fred, that's helpful. Next question, on the Mid-Tex rate case here, I guess I'm trying to understand how you're seeing this play out. It looks like -- if I look at your slide 14, and you're thinking you're probably going to have this 90-day suspension, and then I'm just wondering what kind of feedback you're getting from your initial filings from the cities? And maybe a couple of other things, looks like you're more than doubling the fixed charges for the residential customers, what's the thinking there? And then are you looking to make this into a multi-year settlement like you had last time where you'll have the RM go forward for three or five years?

Ted, this is Kim. The filing was obviously well-known by all of the affected customers because we had a lot of discussions leading up to the time that the case was filed. So they were very familiar with what the case involved and what the case was going to request because all of this was part of the negotiations to extend the current RRM. We are extremely pleased with the relationships that we've developed, and that we continued to strengthen with all of the city customers in the Mid-Tex division. You're exactly correct, we are proposing to increase the fixed customer charge that would be very similar to the way that we design rates and a lot of other divisions including most other divisions, but it would reduce the commodity charge.

I think the case -- the customers continue to be very open and receptive about discussions, and are interested, and are taking -- this is their opportunity to look and see why we need what we need, or why we're proposing what we're proposing. So we think that there's a good likelihood, at least we are going to be very earnest and sincere and desirous of reaching a settlement in the case. So we haven't baked any upside in the 2012 results. But I think at the end of the day the customers are very, very satisfied, and, I think happy with the way that the RRM has operated up to this point. And it's kind of a considered opinion of everyone that at the end of the day, we will seek a middle ground, which provides a win-win outcome for all of the parties involved in the case, and continue to have an RRM after we finish the proceedings.

Okay.

Pretty optimistic. Because of the relationships that are there.

Okay. That's helpful. And then last one for me on the new regulated transmission lines, I saw that you've got the Line W project contracted out to 2019, but I didn't see what the duration of the contracts for the Line X to Boyd. Can you talk about that? And I guess I'm trying to understand, if you've got these demand charges that are already locked in from your producer customers, but we're also going to get GRIP recovery, are you be recovering your costs twice? How is that interplay between GRIP and the existing demand charges?

We've never recovered our costs twice. So we're not recovering the cost twice. There's two separate projects. The one project is essentially -- would be part of the [rider rev] treatment revenues for third-party transportation and that contract with the producer would be considered part of those third-party revenues, and so what we would experience is 25% of the upside associated with those revenues to credit 75% back, but the project is very beneficial, and it is moving a lot of volumes that are associated with gas, or associated with oil in Montague County. So they've got to move.

The other project that you're talking about really replaces an interruptible agreement that the pipeline had been relying upon to provide service for a lot of the regulated customers that it has, in particular the Mid-Tex division, so we experienced some operating history last year when we had the very peak conditions at the end of January and early February. And during those times, we have an opportunity to look where certain sensitive spots are on the system, and where we need to fortify our assets, and that's essentially what that project is doing. It's replacing the interruptible exchange that was relied upon, and replacing it with a firm capability to reach the areas that we're currently serving and that are growing at a pretty good clip in the Dallas-Fort Worth area.

Okay. Thanks. I appreciate the detailed answers.

Thank you. We appreciate your interest and congratulations to, well, I don't know. You're not a --

I was nonpartisan. I was looking for a good game, and we got one.

Our Browns didn't do anything.

Thanks, guys.

Thank you. Our next question is coming from Faisel Khan of Citigroup.

On the Line X to Boyd, I just wanted to get clarification there, what are your expected revenues from that line? Because you gave us the Line W, but just trying to figure out the Line X.

The revenues?

Right. The revenues that you'll be producing annually from that particular project?

You're talking about not the Line W?

Right. Line X.

Well, it would be -- it would receive the regular rate treatment, so it's going to earn 11.8% return on equity. It's going to be, it would be included in our GRIP filing that we make. So it's going to be treated as sort of the regulated revenue side of that business.

Okay. Understood. And then can you remind us on this particular pipeline, how much of the volume -- how much of the customer's volume is utility-based versus producer-based?

Yes. X would be pretty much all dedicated to providing service to the regulated customers, the utility customers. And that right now, I mean we rely on an interruptible exchange agreement with another party that we've been told cannot be made firm.

Okay.

What we experienced in that extremely cold snap is that we need firm, reliable service, particularly on that area of the system, because we've got some low spots there on the West side of Fort Worth, and then we also got a lot of growth that's occurring in that area. So it's going to be regulated -- principally service for regulated customers. Now, they've said that there's additional services provided for third-party producers, and on off-peak periods, then that revenue also would be counted towards the rider rev calculation, and near the benefit of credit of 75% of the customers and 25% to us.

Okay.

So it's really a very, very good deal. It's an excellent project for the customers that are served by Mid-Tex in terms of reliability and diversity of supplies. But it also provides us significant growth opportunities of our rate base.

Okay. Understood. I just wanted to make sure I went back to one of your other comments. You said you were projected to grow rate base by about 6% a year for the next four to five years? Is that correct?

No. 6% to 6.5%.

6.5%. Okay. How much capital are you going to spend to kind of achieve those rates?

This year, our capital budget, we're expecting to spend $700 million. And we've been -- that's a $50 million increase as of yesterday. This year, the $638 million we were starting out with was an increase of about $40 million or so, over the prior year.

Okay. And as you spend that governmental capital, is there going to be a regulatory lag in terms of getting recovery?

A lot of that money being spent is GRIP-eligible. And they lot of it is -- comes under this new Rule 8, which totally eliminates any lag. A good portion of the money in the Mid-Tex will be spending also will be on steel service lines, and there's no lag on that money either. So we've got the steel service lines, we will complete that program of 100,000 steel service lines this year, and so that money's no lag, GRIP money comes in very quickly, and the Rule 8 money is no lag, plus we're able to defer a lot of the costs, depreciation, interest, et cetera, in relation to the Rule 8 spending. So it's a very beneficial type -- type spending of money.

Susan can give you the run rate on the capital investment historically. It's ramped up pretty considerably, and then in support further of the lag, what we've done there, that last count -- I don't know where we're at right now, about 90% to 93% of the capital that's invested on the regulated side of the business begins to earn a return on and of its investment within 12 months, Faisel. So we've it cut down considerably and as Fred said, this Rule 8 treatment has really ramped up the opportunity to reduce lag.

Okay. What would you guys say the growth rate was in rate base in last five years?

4% to 4.5%.

Okay. Fair enough. I appreciate the time.

Thank you. (Operator Instructions). Our next question is coming from John Hanson of Praesidis.

Just want to double-check one thing, make sure I've got this straight here. In the release, you talked about how optimization and the inventory of gas and some accounting work. I want to make sure I understand, you made the statement that you expected that to be realized for the third and fourth quarters. The incremental margins were kind of got available inventory there. My question is, is that locked in at this particular point in time, or is it contingent on any changes in price or is that locked in margins going to come back for us?

It's locked in. The way it's set up right now, third and fourth quarter, we have locked in gains that will roll off, and we will realize the money from that.

Okay. So in between now and then we're just going to be probably subject to the whims of the prices and remarking each quarter in terms of the inventory. Okay.

Right. You're going to probably see that, what we have experienced in the first quarter for non-reg will continue in the second.

Okay. Good. Thank you very much.

And it will be the offset by quarters three and four.

Thank you. (Operator Instructions). Thank you. Our next question is coming from Peter Hark of BLP.

A couple of housekeeping questions. First, on the sale of the distribution assets, Kim, I was hoping you could update us on where that stands and what needs to happen to get it across the finish line?

That's on track, and everything continues to work its way through the regulatory process, and on the timeline that we have anticipated. And we continue to expect to have a successful close in fiscal 2012. Probably looking at a May timeline right now, when the transaction would close for us. I mean, Iowa's already waived on it, and Illinois and Missouri, we've had several very positive and successful meetings with the purchaser included, and the staff of the Commission involved. And we seem to be working our way with really no big showstoppers, no big issues.

Okay. Thanks. And that leads to the next question. On slide 20, per the assumptions you're making, the $2.30 to $2.40 this year, the first bullet point is assuming a contribution from these properties of $0.09 to $0.11. So I'm just trying to understand, is that an annualized number? Or is that the earnings of the discontinued ops that you anticipate through May?

That's an annual number.

Okay, Fred, and would you have the quarterly breakout, like you did for this quarter, where you broke out the discontinued ops for the first quarters of 2011 and 2012? Would you have the second through fourth quarters contributions?

No. We don't have that. We break it out as we report the results, consolidated results, and then we break out the discontinued portion and then give some granularity on that. Because on the face of financials, it's a one-liner. But then we show a breakdown on that as we report our earnings.

Okay. Great. And again the argument being that you'll lose this $0.09 to $0.11 of annualized earnings but redeploy the $124 million of proceeds. What would that --?

That's correct. One thing to remember, this discontinued earnings is the accounting-required calculation of that. And so they do not -- the accounting rules do not allow certain costs to be allocated that normally would be allocated to those operations, and in the regulated environment, we have the ability to, once we dispose of these assets, to reallocate those overhead costs to other rate jurisdictions. And recoup that.

I see.

On a normal unregulated type environment, those certain overhead costs would discontinue. You don't recoup them. We're able to reallocate and recoup those down the road.

How much would that be, Fred?

It's in the neighborhood of $6 million to $8 million on an annual basis.

Great. Thank you. And then have you -- remind us, have you said what the after-tax proceeds will be out of the $124 million? In after-tax --

Proceeds or gains?

Yes. The after-tax proceeds.

We just quoted the $5 million pretax gain, that's the only thing that we disclosed.

Okay. Fair enough. The other question has to do with the FERC investigation. You had paid a penalty and some disgorgement of some prior profits of $12 million. I don't know if you had reserved against that, or is there an earnings impact that you felt in your first quarter?

There was no earnings impact to us currently on that. It had been reserved in prior time periods.

Okay. Great. Thanks very much, Fred.

Thank you. (Operator Instructions). There are no further questions at this time. I'd like to hand the floor back over to management for any closing remarks.

Thank you, Jackie. Just to remind you all that a recording of this call is available for replay on the website through May 2. Again, we appreciate your interest in Atmos Energy and thank you for joining us. Goodbye.