Southwest Gas Holdings, Inc. (SWX) Q4 2013 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to the Southwest Gas 2013 Year End Earnings Conference Call. My name is Britney, and I will be the operator for today. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes. I would now like to turn the presentation over to your host for today, Vice President of Finance and Treasurer, Ken Kenny. Please proceed.

Thank you, Britney. Welcome to Southwest Gas Corporation's 2013 Earnings Conference Call. As Britney stated, my name is Ken Kenny, and I am the Vice President of Finance and Treasurer. Our conference call is being broadcast live over the Internet. For those of you who would like to access the webcast, please visit our website at www.swgas.com and click on the conference call link. We will have slides on the Internet, which can be accessed to follow our presentation. Today, we have Mr. Jeffrey W. Shaw, Southwest's President and Chief Executive Officer; Mr. John P. Hester, Executive Vice President; and Mr. Roy R. Centrella, Senior Vice President, Chief Financial Officer; and other members of senior management to provide a brief overview of 2013 earnings and an outlook for 2014. Our general practice is not to provide earnings projections, therefore, no attempt will be made to project earnings for 2014. Rather, the company will address those factors that may impact this coming year's earnings. Further, our lawyers have asked me to remind you that some of the information that will be discussed contains forward-looking statements. These statements are based on management's assumptions, which may or may not come true, and you should refer to the language in the press release, our SEC filings, and also Slide #2 presented today for a description of factors that may cause actual results to differ from our forward-looking statements. All forward-looking statements are made as of today, and we assume no obligation to update any such statement. With that said, I'd like to turn the time over to Jeff.

Thank you, Ken. I will begin on Slide 3 highlights -- 2013 highlights. In 2013, we posted record earnings per share which were, in part, impacted by strong market returns underlying our company-owned life insurance policies. We'll speak more about that in today's call. Given our earnings, cash flows, and strength of balance sheet, the board recently increased the annualized dividend on common stock by $0.14 per share or 10.6%. This marked the eighth straight year the dividend has been increased and the third straight year of double-digit percentage increases. In addition to fully decoupled rate designs in all of our jurisdictions, we now have infrastructure replacement mechanisms approved in Arizona and Nevada, and a pending proposed order in California that would authorize a similar mechanism there. We are anticipating a decision of a proposed general rate order in California next month that we will discuss during today's call. Over the course of the last 12 months, all 3 credit rating agencies have lifted the company's ratings due to the improved earnings, cash flows, balance sheet and regulatory environment. We'll discuss this further in a few minutes. Finally, we continue to make solid progress with our pipeline construction services subsidiary. NPL posted their highest earnings in its history. Their focus on safety and service has earned them a solid reputation and the recent growth reflects this. Great strides have been made to strengthen the management infrastructure to accommodate this growth. We believe they are well positioned to grow the bottom line going forward. Next, the call outline. First, Roy Centrella, our Chief Financial Officer, will summarize 2013 financial results. He will discuss financial results for both the -- the Natural Gas segment of the business and our pipeline construction services segment or NPL. John Hester, our Executive Vice President, whose responsibilities include all regulatory activities, will then discuss all current regulatory proceedings and initiatives being pursued by the company. I will then conclude by discussing expected customer growth, an economic overview of our service areas, our projected capital expenditures for the next 3 years, a comment regarding future dividend growth, and I will make concluding comments regarding 2014 expectations and our focus going forward. So with that, let me turn the call over to Roy.

Thank you, Jeff. And let me welcome those of you joining us today. I plan to provide a summary of 2013 operating results, recap the primary factors impacting the change in 2012 and review financing-related activities. And then I'll give some commentary on expectations around 2014. So let's move to Slide 5. Our consolidated net income increased from $133 million in 2012 to $145 million in 2013. As a result, basic EPS increased from $2.89 to $3.14. Both operating segments showed improvement between years and returns on investment underlying company-owned life insurance, or COLI policies, was a significant contributing factor. More on that later. Let's move to Slide 6 in the Natural Gas segment highlights. The Gas segment contribution earnings was a record, although operating income was a little lower than last year. The increase was mainly driven by strong COLI returns and interest savings resulting from our refinancing efforts. Operating margin improved by 3% in 2013, in part, due to the company adding 28,000 net new customers. This is a 1.5% growth rate and the highest customer addition level since 2007. This next slide summarizes the Gas segment income statement. Operating margin increased by $22 million in between years. However, operating expenses increased by $26.5 million or 4%, resulting in a net decrease in operating income of $4.5 million between years. Other income increased $8.1 million between years, and net interest deductions were also favorable, declining $4.4 million. The net result was an increase in the Gas segment contribution to net income from $117 million in 2012 to $124 million in 2013. Slide 8 breaks down the increase in operating margin from 2012 to '13. The rate relief contributed $8 million in incremental operating margin, and most of that was from Nevada. Customer growth contributed $7 million, as the company increased its customer count by 1.5%. Other margin increases, totaling $7 million, did include some modest industrial large commercial growth, but the primary driver was the recovery of regulatory assets which are being amortized in Arizona. For 2014, we expect a similar level of customer growth and California rate relief to be the primary drivers of incremental operating margin. Margin from our infrastructure tracking mechanisms, which is a strategic focus of ours, is not expected to be significant just yet. Slides 9 and 10 cover operating expenses. Operating expenses increased $26 million or 4% between 2012 and '13, which was consistent with our previously provided projections. There were several factors influencing the increased costs, as shown on Slide 10. Pension expense increased to net $5 million due, primarily, to the relatively low interest rate in existence at the end of 2012. Amortization expense and general tax increases amounting to about $8 million, for which the company received offsetting revenue, made up nearly 1/3 of the overall operating cost increase. Looking ahead, pension expense will be significantly lower in 2014, which should allow operating expenses to increase in the 2% to 3% range. Slide 11 shows the mitigating factor to operating cost increases, which is productivity improvements. One measure of that, that we keep track of is the customer-to-employee ratio, which improved from 836 employees per customer to 858 between years, an increase of 2.6%. This has been a long-term focus of ours as we have embraced technology and process changes. A few of our current initiatives involve billing and payment processing, call center optimization and customer service field automation. Next on Slide 12, we look at other income, which improved $8.1 million between years, as 2,000 returns on investments underlying COLI policies were very strong, consistent with the broad-based improvement in the stock market. And a pipe replacement program subject to partial non-recoverability concluded in 2012. With regards to COLI, we think returns in the range of $3 million to $5 million would represent a normal level, but these returns are influenced by market forces and, therefore, subject to volatility. On the next couple of slides, we'll look at financing activity and liquidity. Net financing cost declined $4.4 million between years. This resulted mainly from several favorable refinancing activities, most notably, a $200 million, 7.625% note which matured in May of 2012. The refinancing savings were partially offset by a $250 million note offering we did last October. These notes, although very favorably priced, will cause interest expense to increase in 2014 by $5 million to $6 million. Slide 14 shows our liquidity position, which is very good right now. The debt offering we did last October allowed us to pay down our $300 million credit facility, which had built up a long-term need from refinancing activities and capital expenditures. Credit facility currently runs through March of 2017. And on Slide 15, you'll note that all 3 credit rating agencies upgraded our credit ratings within the last 12 months. Most recently, Moody's raised us a notch to A3, bringing all 3 ratings to the equivalent of at least an A-. This will definitely benefit us as we access the debt capital markets in the future. Now I'll turn our attention to NPL, starting on Slide 16. NPL had a very solid year in 2013. Revenues increased 7% to a record level of $651 million. Construction expenses increased 6% over the prior year, and we will talk about the components of that change in a minute. NPL contribution to net income increased $4.4 million overall compared to 2012. Slide 17 provides a snapshot of NPL income statement. NPL achieved record net income of $21.2 million, modestly exceeding their previous high watermark of $20.9 million in 2011. The revenue increase of $44.6 million was primarily driven by additional pipe replacement work across the country, as many NPL customers are in the early years of long-term infrastructure replacement programs. Construction expenses increased by $31.8 million or 6%, which is broken down in greater detail on Slide 18. There were a number of factors affecting the change in operating expenses between years. The overall increase in replacement work was the most significant factor. Secondly, you'll recall the prior year included a $15 million pretax loss on a large fixed-price contract, which we have previously discussed. Third, G&A expenses increased $10 million, including $6 million for structural changes related to NPL growth and $4 million associated with the legal settlement relating to former employees. No similar legal matters are pending. And finally, 2013 gains on sales of equipment, which offset construction expense, were about $4 million lower than in 2012, with 2012 being the anomaly year. As noted on the slide, the increase in depreciation expense was a result of equipment purchased to support the growth in volume of work. With that, let me turn the time over to John Hester.

Thanks, Roy. Turning to Slide 19, we have a number of topics that we would like to review as part of the regulatory portion of our call today. I'll start with the report on the status of our currently pending California rate case filing, followed by updates on our use of infrastructure recovery mechanisms, our Arizona decoupled rate design, our Paiute Pipeline general rate case application, our proposed Paiute Pipeline-Elko lateral expansion, and our proposal to build an LNG facility in Arizona. Moving to Slide 20. Our most recent California rate case application was filed with the California Public Utilities Commission in December 2012. Our request sought an $11.6 million revenue increase, incorporating a 10.7% return on equity on a 57% common equity component. We further proposed to decrease depreciation expense by $3.1 million, continue our current 5-year rate case cycle and request a 2.95% annual attrition increase for years 2015 through 2018. We also requested establishing a new infrastructure recovery mechanism. The administrative law judge in the proceeding originally issued a draft decision in December of last year, which was subsequently amended and reissued earlier this month. The proposed decision recommends a $7.5 million revenue increase based on a 10.1% return on equity and a 55% common equity ratio. The draft decision also adopts our proposals relative to depreciation expense, continuation of our 5-year rate case cycle, 2.95% annual attrition rate increases and establishment of an infrastructure recovery mechanism. We currently expect the Commission to issue a final decision in this case next month. Turning to Slide 21. The company and its customers continue to have a positive experience with Southwest Arizona customer-owned yard line program. Under this program, the company offers to perform a leak survey on such customer facility and can replace the line with utility-owned facilities if a leak is found. At the end of last year, Southwest had evaluated about 85% of the 100,000 customers that have been identified as having a customer-owned yard line. In the 2 years since the program began in January 2012, Southwest has replaced about 4,000 customer-owned yard lines at a cost of approximately $10 million. Southwest currently has a surcharge in place as of June 2013 to recover annualized first-year program costs of approximately $600,000. Later this afternoon, we will be submitting our request to the ACC to increase the level of that surcharge to reflect the addition of 2013 program expenditures. If approved, the updated customer-owned yard line surcharge will provide annualized program cost recovery of $1.5 million. Southwest anticipates the Commission will rule on this request later this summer. In November of last year, Southwest requested approval from Arizona Corporation Commission to expand its customer-owned yard line program to include replacement of leaking and non-leaking customer-owned yard lines, with any offers to replace non-leaking lines being contingent on the presence of Southwest pipe replacement contractors being in the area already replacing other Southwest-owned distribution facilities. The ACC approved the proposed program expansion last month. Continuing with our infrastructure recovery in Slide 22. In Nevada, Southwest has had a number of developments in the infrastructure replacement front in the past 12 months. First, in March of 2013, Southwest submitted a filing to the Public Utilities Commission of Nevada proposing to accelerate the replacement of early vintage plastic pipe in 2013. The filing proposed a $15.6 million replacement program and the establishment of a regulatory asset to defer the depreciation and pretax rate of return associated with the accelerated investment. Request was resolved via a stipulation with the Commission staff and the Bureau of Consumer Protection and was subsequently approved by the Commission in June of last year. In November of 2013, Southwest filed a separate request with the PUCN for approval to undertake a 2014 accelerated pipe replacement program. The 2014 proposal sought to replace $18.9 million of early vintage plastic pipe, again, along with the establishment of a regulatory asset to recover depreciation expense and a return on the new investment. While the 2014 filing was not supported by the Bureau of Consumer Protection, it was ultimately approved by the Commission last month. Moving to Slide 23. More broadly, in Nevada, the Public Utilities Commission also recently approved just this past month, an ongoing prospective mechanism for Southwest to propose accelerated pipe replacement programs. This was an initiative that was initially included as part of the company's 2012 Nevada rate case filing but was deferred to a rulemaking for further review during most of calendar year 2013. The Commission's January approval now allows Southwest to make future accelerated pipe replacement proposals for the year 2015 and beyond. The new model calls for Southwest to submit a replacement plan proposal in June of each year, followed by Commission review and potential approval by year end. Southwest then undertakes any Commission-approved replacement efforts in the coming calendar year and request establishment of a cost recovery surcharge upon completion of the replacement work. We believe this new infrastructure recovery template is an excellent demonstration of the Nevada Commission's and Southwest's mutual interest and partnership in pursuit of pipeline safety. Turning to Slide 24. 2013 marks the second complete year that our Arizona decoupling mechanism has been in place. Recall, the decoupling mechanism was incorporated in the rate case settlement that was approved by the Arizona Corporation Commission in December 2011. As part of that rate case settlement, Southwest was required to file an Annual Report for the Commission to review the operation of the mechanism. Southwest made its first such filing in April of 2013, generally reporting that the mechanism has been working as designed and that Southwest had essentially received no customer complaints on the matter. The Commission staff reviewed Southwest filing, and in December of 2013, the Commission approved continuation of Southwest decoupling mechanism without modification. Moving to Slide 25 for some updates on Paiute Pipeline. Yesterday, we filed a new general rate case with the Federal Energy Regulatory Commission on behalf of our Paiute Pipeline subsidiary. This is the first rate case filing for Paiute in 5 years, and was required under the settlement reached in Paiute’s 2009 rate. The application requests a revenue increase of $9 million and is based on an overall rate of return of 9.97%, which incorporates a request of 13.65% return on equity on a 53.4% common equity ratio. Under the FERC regulatory model, Paiute's proposed rates are scheduled to take effect in September, subject to refund pending final resolution of the case. We also have an exciting system expansion for Paiute that is detailed on Slide 26. Paiute Pipeline convened an open season in August of 2013, and received sufficient interest to proceed with proposing a new lateral tying Ruby Pipeline into Paiute system in Elko, Nevada. The new line will be 35 miles in length and is estimated to cost about $35 million. A variety of prefiling activities are currently underway, with the formal application expected to be submitted in June. Subject to FERC review and approval, construction of the new laterals are expected to begin in May of 2015, with a proposed in-service date of November 2015. The final project I wanted to touch on as part of the regulatory portion of our call today is a proposed LNG storage facility detailed on Slide 27. Last month, Southwest submitted an application to the Arizona Corporation Commission seeking pre-approval to construct an LNG storage facility in Southern Arizona. The facility is designed to help avoid the type of service outages that Southwest and several other utilities experienced in February 2011 as a result of production area supply and interstate pipeline disruptions. Total capacity of the facility is 233,000 dekatherms, the project's cost is estimated at $55 million, which includes the 20% contingency. A decision from the ACC is anticipated later this year. If approved by the ACC, construction of the facility is estimated to take 24 to 30 months. With that, I will turn the call back to Jeff.

Thank you, John. Let's turn to Slide 28 and discuss customer growth breakdown. You'll see on the table, the beginning and ending customer numbers for 2011, 2012 and 2013. Note the gradual improvement in the first time -- new meter sets from 13,000 to 21,000 between '11 and '13. This is consistent with what we have discussed in previous calls, that the recovery in our service areas would be positive but gradual. And that's what we're seeing. We had at one time, you may recall, excess inactive meters, those that were not taking service over and above what we normally would expect, of around 55,000, at the peak of the recession. We're now down to 26,000 meters as of the end of 2013. So as you can see, the meter turn-on, turn-offs, we had 7,000 such customers restored to service in the year 2013. So we believe that again, gradually, these customers will be hooked up and we'll get to a more normalized level eventually. Slide 29. The graph is favorable in that all these lines are going in the right direction. The unemployment rate, seasonally adjusted, is improving. And that being said, you can see that all of our service areas still are in excess of the national average. We need to see job growth at a greater level, we believe, in our service areas before we see any significant increase in customer growth. We're watching that statistic very carefully. Move to Slide 30. An economic overview. You can see that there is moderate employment growth year-to-year. This should help drive moderate customer growth on a going-forward basis. Again, consistent with what Roy had just said a few minutes ago, we expect about 1.5% growth rate going forward. Slide 31. Capital expenditures. The $375 million you see estimated for 2014 contemplates continued increased pipe replacement work. It also indicates some cost or include some cost relative to the Elko lateral project that John referenced. We have to do some preliminary work as that project moves forward. The $1.1 billion which we estimate between 2014 and 2016 includes replacement work, the increased use of the tracker mechanisms, which John referenced in his comments; but it does not include the LNG facility. That, if approved, would be over and above what you see in this $1.1 billion over the next 3 years. Slide 32. The dividend. We've had an annual compound average growth rate on the dividend since 2009 of 8.97%, just under 9%. If you take a look at the most recent 3 years, the percentage increase has been in excess of 10%. So we're very pleased that we've been able to address dividend policy. The $1.46, on an annualized basis, that the board has now approved, is the highest dividend amount -- annualized dividend amount in the company's history. On a going-forward basis -- I'll speak to the dividend in just a minute. For 2014, on Page 33, under the construction services business. Now NPL has been charged to grow revenues. We picked a range of 5% to 8%, but in saying such, please know that their growth will not necessarily be linear. They may have years that will be better than that and years that may not be as good as that. One thing they are charged to do, though, and the management incentive plans is to continue to provide a very solid service level to the customer and to maintain their safety ratings. Safety is very, very important to the reputation. And with the strong reputation, they've been successful in being able to secure new contracts. So that's going to be a focus. Fortunately, throughout the country, we're seeing increased favorable regulatory support for pipeline infrastructure replacement. And so that is very positive for NPL. I will mention that early weather conditions in 2014 had -- and this may be no surprise, especially in the East, somewhat in the Midwest, have been such that they've not been able to do the level of work that they would've planned to do. And they're hopeful that, while we need moisture throughout the nation, they're hopeful that the weather -- the extreme weather will abate and allow them to begin work. We're not certain whether in the current year, they can make all that up, they're going to do everything they can. If they do, it may require a little bit of extra over time and so forth in order to accomplish that. But they are focused on trying to get all the work done that they were contracted to do in the year, notwithstanding the weather event that we've seen thus far. 2014 expectations for the Natural Gas Operations on Slide 34. John mentioned the California rate decision. We're hopeful that we will receive such a decision next month. Again, we expect net customer growth of about 1.5% in 2014. Our operating cost increase assumption is in the 2% to 3% range, which includes net pension expense decrease of $7 million. Financing cost, however, should increase by $5 million to $6 million, notably, because of some of the recent financing transaction that was completed in late 2013. We again expect normalized COLI returns of somewhere between $3 million to $5 million. The volatility of that number will likely track the broader market. We will have an expanded -- a continued expanded focus on infrastructure replacement mechanisms in all jurisdictions, which should favorably benefit the company, mitigating the effects of regulatory lag that, maybe in the past, we would have experienced. And finally, the pipeline -- the Paiute Pipeline general rate case that John discussed is on file. And again, we will have a decision on that out into the future that we will report back to you. Slide 35. Let me just mention the dividend. The board will continue to review the earnings, the cash flows, the balance sheet, our capital needs and make a decision with respect to the dividend. But we are committed to move the dividend to a level that is competitive with the industry, and a payout ratio that would be competitive with the industry. So we will continue to address dividend policy as we have at each of the last 8 years, and you can expect to hear additional information on that on a going-forward basis. So with that, I will turn the time back to Ken, and I'm sure we will take any questions that you may have.

Thanks, Jeff. That concludes our prepared presentation. For those of you who have accessed our slides, we have also provided an appendix to the slides, which includes other pertinent information about Southwest Gas, and can be reviewed at your convenience. Our operator, Britney, will now explain the process for asking questions.

[Operator Instructions] And your first question comes from the line of Grier Buchanan with KeyBanc Capital Markets.

This is Grier Buchanan on Matt Tucker's team. The first question I wanted to ask on NPL. Well, I guess, first off. Was the $4 million legal charge all incurred in the fourth quarter?

Not -- this is Roy. Not all of it, but about $2.7 million was.

Okay. That's helpful. And then in terms of 2014. Are you expecting margins similar to last year? And are you seeing any changes in terms of pricing or competition?

No, I think that would be a fair assumption. I agree with that -- margin rates to be fairly similar.

Okay. And then just one more on NPL, and I'll jump back in the queue. In terms of new construction, are these jobs you're seeing are still mainly within the traditional -- focusing on the traditional LDC customer or is there any new customer segment that you see emerging?

No, at this point, our focus is still primarily on the LDCs, that's their bread-and-butter. Lots of times, when they're in an area, there may be some ancillary business they get by having crews there, maybe some paving work, things of that nature. But by and large, there is so much work available at the LDC space that they're still pretty focused on that.

And your next question comes from John Hanson.

Just a couple quick questions. You did a good job with your slides and all your commentary, but just you've got a couple of big projects that are potentially coming up with the pipeline expansion and the LNG. Will we have enough financing to cover those or will we need to do some external financing on those?

I think that we'll evaluate that in the context of all of our needs. We are focused, John, on trying to grow rate base in a way that will benefit both the customer and the shareholder. And these projects both have those elements. So we expect to be successful. I think that our cash flow's going to be strong but it -- we will, over time, build the need to do a moderate amount of additional financing. That's what we just did with this $250 million debt facility that we've done in 2013. We used our credit facility over time, until we have a sizable, something sufficient that is efficient to go into the market and get the best rate that we can. And that's what we just did and we'll do that again. But I wouldn't say those projects, specifically, will drive this, it will be part of a larger evaluation that we do in all of our capital needs.

And your next question comes from the line of Tim Winter with Gabelli.

I was wondering, as NPL continues to grow, making up a bigger portion of the whole company, and the market sort of appreciating that this business is in the early stages. Any thoughts about doing anything creative with NPL, such as an IPO or anything of that nature?

Tim, that's a great question. And I think that as we evaluate NPL, I'm not sure if you had asked me 5 years ago, we could have seen what's happened with this business. But because of the reputation, they really are positioned well to take advantage of an opportunity. And so we're going to do that. We think they need to be of a sufficient size in order to increase the optionality for the business. But I will tell you that, yes, we have certainly talked about that as a management team and as a board. And we will do what we think is in the best interest of the shareholder over time. Right now, we're focused on building the business and making it as attractive as possible, making the value as great as we can. And I think that's a sensible thing to do when you have a business and you have an opportunity that stares you in the face like this does.

And at this time, there are no further questions in the queue.

Okay, then. Well, thank you, Britney. This concludes our conference call, and we appreciate your participation and interest in Southwest Gas Corporation. Thank you.