Holly Energy Partners, L.P.
Q3 2013 Earnings Call Transcript

Published: 30 Oct 2013

[Operator:]

Welcome to Holly Energy Partners’ Third Quarter 2013 Conference Call and Webcast. At this time all participants have been placed in a listen-only mode and the floor will be open for your questions following the presentation. (Operator Instructions) Please note that this conference is being recorded. It is now my pleasure to turn the floor over to Blake Barfield. Blake, you may begin.

[Blake Barfield:]

Thanks Jackie, and thanks to each of you for joining this afternoon. I am Blake Barfield, Investor Relations for Holly Energy Partners. Welcome to our Third Quarter 2013 Earnings Call. With us today are Matt Clifton, Chairman and CEO; Bruce Shaw, President; and Doug Aron, Executive VP and CFO. This morning, we issued a press release announcing results for the quarter ending September 30, 2013. If you’d like a copy of today’s press release, you may find one on our website, www.hollyenergy.com. Before Matt, Bruce, and Doug proceed with their prepared remarks, please note the Safe Harbor disclosure statement in today’s press release. In summary, it says statements made regarding management expectations, judgments or predictions are forward-looking statements. These statements are intended to be covered under the Safe Harbor provisions of Federal Securities laws. There are many factors that could cause results to differ from expectations, including those noted in our SEC filings. Today’s statements are not guarantees of future outcomes. Also, please note that the information presented on today’s call speaks only as of today, October 30, 2013. Any time-sensitive information provided may no longer be accurate at the time of any webcast replay or reading of the transcript. Finally, today’s call may include discussion of non-GAAP measures. Please see today’s press release for reconciliations to GAAP financial measures. And with that, I’ll turn the call over to Doug Aron.

[Doug Aron:]

Thanks Blake. Thanks to each of you for joining our call this afternoon. Last Friday, October 25, Holly Energy Partners announced a quarterly distribution to $0.4925 per unit. This increase marks the 36th consecutive quarterly increase in HEP’s distribution to unitholders, an increase every quarter since our IPO more than nine years ago. Specific to the third quarter of 2013, this distribution reflects a 6.5% increase over the split-adjusted $0.4625 per unit declared for the third quarter of 2012. The distribution will be paid on November 14, 2013, to unitholders of record as of November 4, 2013. For the quarter ended September 30, 2013 Holly Energy Partners’ distributable cash flow was a record $43.9 million, comparing favorably to the $40.4 million distributable cash flow generated in the third quarter of last year. EBITDA in the period was $53.2 million, ahead of our anticipated $50 million quarterly run rate. Net income attributable to HEP for the quarter was $21.9 million, a decrease from the $23.3 million in the same time period of last year. The decrease in net income attributable to HEP is due principally to a $5 million year-on-year increase in depreciation and amortization, resulting in part from storage tank write downs. Though accounting rules require us to write down tank assets that are replaced or taken out of service, HEP’s cash flow was not affected since minimum commitments do not change and costs to construct the replacement tanks are in certain cases reimbursed per the terms of our contracts with HollyFrontier. Operating expenses decreased to $21.7 million in the quarter, down from the $22.7 million in the third quarter of 2012. OpEx benefited from a one-time $3.5 million tax refund and was offset in part by some environment accruals. The reimbursable portion of operating expenses for which there is offsetting revenue was approximately $2.1 million. Excluding the reimbursable expenses for which there is offsetting revenue, we expect operating expenses for the fourth quarter of 2013 to be in the range of $20 million to $22 million and will anticipate some quarterly increase in 2014. SG&A expenses were $2.4 million for the period, slightly below the expected quarterly range of $2.5 million to $3 million per quarter. As a reminder, approximately 85% of HEP revenues and therefore income and distributable cash flow are supported by minimum commitments for major customers. Following the July 1, 2013 PPI tariff adjustments, long-term minimum commitment contracts with major customers will result in minimum annualized payments of approximately $259 million. Now, I’ll provide an update on shortfalls billed and deferred revenue recognized during the quarter. Under certain contracts held by HEP, we received payments for quarterly shortfall billings below minimum commitments. Those payments are included in distributable cash flow for the current accounting period, yet classified as deferred revenue and therefore not included as revenue on HEP’s income statement until the future period in which the revenue can be recognized. Deferred revenue recognition primarily results from shortfalls billed in previous quarters which clawback rights were either used or expired. Specific to the third quarter of 2013, shortfalls billed for shipments below minimum commitments totaled $4 million, offset in part by $200,000 of deferred revenue recognized in this quarter. As of September 30, 2013, we have $11.2 million in deferred revenue recorded on the balance sheet. The bulk of this quarterly – or this quarter-on-quarter increase relates to shortfalls billed on the UNEV pipeline. In the fourth quarter of this year, we expect to recognize approximately $2.3 million of deferred revenue. With regard to HEP’s credit facility, as of September 30 of this year, we have $365 million borrowed, leaving a $185 million of remaining availability. We have $450 million aggregate principal amount of senior notes outstanding made up of $150 million of 8.25% notes due 2018 and $300 million of 6.5% notes due 2020. Now, I’d like to turn the call over to Bruce for a few comments, after which we’ll open the call for questions.

[Bruce Shaw:]

Thanks Doug, and thanks to everyone for joining today. I have just a few comments to add. First about the third quarter performance, second an update on growth projects and finally a recap of capital spending, before turning to Matt, and then to questions. Despite minor impacts from weather and refinery downtime, volumes on HEP’s pipelines and terminals performed near expected levels for the quarter with quarterly revenue also helped by the fact that tariffs under most of our contracts increased at the beginning of the third quarter as Doug mentioned, boosting the annual run rate of revenue by about 2%. Recall that HEP’s revenues are a 100% fee-based and that most of our contracts contain minimum commitments in built-in annual escalators, giving us a strong and growing foundation on which to build for the future. As for our current growth projects, we’re making good progress on expansion of our crude gathering system in Southeastern New Mexico. We’ve already completed initial components of this expansion and we anticipate full completion of the project by late first quarter or early second quarter of next year. Once fully operational, the project will add approximately $7.5 million in annualized trunk line revenue from contractual minimum volume commitments, as well as additional gathering pipeline revenue as new lease production is connected to the expanded system. In addition, we’re on schedule to complete enhancements to UNEV’s product terminal in North Las Vegas. The project should enable the pipeline to better serve customers with peak volume shipments when the product pricing ARB is open between Salt Lake City and Las Vegas especially in the winter time by increasing the number of truck loading racks from two to four. For UNEV, as we’ve said on previous calls, we don’t expect significant volume upside until refinery expansions in Salt Lake City are completed in late 2014 to 2015 timeframe. Until then, UNEV is supported by minimum commitments from HollyFrontier and from Sinclair and a GP giveback from HollyFrontier related to HEP’s ownership interest. We continue to evaluate several potential products with HFC, currently focusing most of our time on options to increase crude delivery capacity for HollyFrontier between Cushing and Tulsa, Oklahoma. We’ve not made final decisions on other projects including a new products pipeline between HFC’s refinery in Cheyenne, Wyoming and Denver, Colorado, or the addition of crude by rail functionality to our New Mexico crude gathering system but neither project is highly likely under current market conditions. We continue to explore potential growth opportunities, particularly on the crude supply and gathering side of our business, both in the Southeastern New Mexico, West Texas region and in geographies near HollyFrontier’s other refineries. We also regularly evaluate third-party acquisitions that could have a strategic fit for us. Our CapEx for the third quarter of 2013 totaled $16.3 million, including $2 million of maintenance capital expenditures. This brings our total CapEx through September 30, 2013, to approximately $33.5 million, including about $6.6 million of maintenance CapEx expenditures. We expect that our 2013 total capital spending will be in the $50 million range, with most of our expansion CapEx spend on our crude gathering project, a smaller portion on the UNEV terminal, and about $8 million to $10 million for maintenance CapEx. I’d like to finish by again thanking the entire HEP team for their strong commitment to safety, reliability and customer service. The company’s continued success and readiness for future growth would not be possible without the hard work and dedication of each and every one of our employees. Now, I believe Matt has a few comments to add before turning it back for questions. Matt?

[Matt Clifton:]

Thanks Bruce. I’ve just a couple of high level comments before we turn it over for questions. As Bruce mentioned, our project to expand our crude oil gathering and trunk line system is proceeding as planned. This is clearly an exciting organic opportunity for HEP. This expansion will provide needed gathering and takeaway capacity for dramatically increasing Delaware Basin production in the western edge of the Permian Basin. Our existing system was one of a few hard deep [ph] systems in place in Eddy and Lea County, New Mexico, where success in both vertical and horizontal drilling has materialized over the last couple of years. Current volumes on our existing gathering system have increased approximately 50% to just under 75,000 barrels a day since we acquired the system five years ago, with most of that growth occurring over the last couple of years as Permian exploration success has surged. Our expansion project will position us to continue to capture the benefits of increasing crude oil transportation revenue from rapidly expanding Permian Basin production. On the non-organic front, although our team has explored a number of third-party asset acquisitions over the last 12 months, we have now fund any price points that would have added unitholder value. Our practice is to be better for unitholders, not just bigger. Looking forward, our strategy is to preserve our track record of consistent unitholder distribution growth, is to continue to prioritize our safe reliable operations, control cost, explore organic opportunities and improve the cash flow over existing asset base, evaluate ways to provide enhanced transportation alternatives to our general partners refining facilities and to pursue external growth opportunities in a disciplined manner. With that, I’ll turn it back to Blake.

[Blake Barfield:]

Thanks Matt. And Jackie, at this time we’re ready to open the call for questions. If you can please again provide the instructions.

[Operator:]

(Operator Instructions) Our first question comes from the line of Edward Rowe with Raymond James.

[Edward Rowe:]

Good afternoon guys. Recognizing Midland spread being quite volatile right now, can you provide some color around the potential crude by rail project and what sort of takeaway commitments are you looking to target to proceed with that project?

[Bruce Shaw:]

Sure. I can take that one. We – recognizing the volatility around Midland and Cushing, it’s really driven by potential interested parties that would rail the crude out of the area. We think that mostly likely home for West Texas crude by rail could very well be California. So it really kind of comes down to – I think we may have touched on this a bit the last quarter as well, but it really comes down to what those folks – what kind of the types of crude they are looking for and what kind of spread they would need to make that economic forum, as much as it would center just a way around Midland. But Matt, I don’t know if you want to add anything to that.

[Matt Clifton:]

No, I think that pretty well covers it, Bruce. I think obviously the Brent-TI differentials have shrunk in, and Midland as you noted has been pretty volatile on its relationship, the Cushing. So there is – I think most of the people on our company said you would look to sign up for that long-term commitments are pretty much on the sidelines and not willing to sign up for commitments, but rather want the flexibility to rail crude if as and when from various places as the economics dictate. So we continue to look at it. Right now if anything, it looks a little shaky.

[Edward Rowe:]

Okay. That’s good. In terms of the two other potential pipeline projects, the Cushing, the Tulsa and the Wyoming, the Denver pipelines. Can you guys share with us how you guys are progressing in terms of reaching the commitments that you were looking forward to proceed with those projects?

[Bruce Shaw:]

Sure. On Cushing, the Tulsa, what we’ve done there is come up with an estimate of what it would take to build a new pipeline between Cushing and Tulsa. We’re using that estimate to determine what kind of commitment levels and the corresponding tariff rates we’d need from a shipper. Obviously, that shipper being HollyFrontier. With that in hand, we’re also getting inquiries from other folks who either own pipes in the area that are currently operating or could operate, that is potentially dormant at the moment with some other options. So until really we have all those data points, we’re not going to know how our economics of the new pipeline would stack up, although it’s obvious point that existing pipelines, if they can be economically expanded in good condition – relatively good condition, typically we can compete a little bit better than a brand new pipe build. So that’s the Cushing. The Tulsa, should no more over the next several months. Certainly we’ll have an update for everybody this time next quarter. As far as Cheyenne to Denver, I think as we mentioned last time, we’ve got a new owner or at least a potential new owner of the Rocky Mountain pipeline system that currently owns the leg between Cheyenne and Denver. And as soon as we see what that new owner can confirm what they plan to do with that pipeline system, would lessen the need for a new pipeline between Cheyenne and Denver. Obviously building that pipe between Cheyenne and Denver a longer build as well as a tougher build through that Northern part of Colorado.

[Edward Rowe:]

All right. That’s helpful. That’s all I had.

[Operator:]

Your next question comes from the line of Mark Reichman with Simmons.

[Mark Reichman:]

Good afternoon. Just a few questions. First, let me ask a little bit about the pipeline volumes. It seems like some of the other companies that have been reported have seen stronger demand for gasoline, less so for jet fuel. And I was just kind of interested in the mix on demand on your pipeline systems? And then second, I just wanted to clarify on the gathering expansion. I heard that – I thought I heard you say that it would be completed in the first or early second quarter ‘14 and I was still kind of under the impression that it would start contributing in the first quarter, so just to clarify that. And then lastly on the write-down of these tanks. I know that you’ve seen some of that in El Dorado and Tulsa and I was just curious moving forward, what would you expect in terms of tankage replacement?

[Bruce Shaw:]

Sure, Mark. This is Bruce. Let me take the question about Malaga first. We do expect contribution from Malaga in the first quarter of next quarter. There is a potential it could begin a small contribution before the end of the calendar year, but the full run rate of revenue we don’t expect to come on until the project is fully complete, which will either be the towards the end of the first quarter or beginning of second quarter. Because the project is being finished in phases, parts of it will come on some of the gathering revenue may come on, sooner than the committed trunk revenue will come on. So that’s the answer to the first question. I believe your second question was about product pipeline mix. And I’m not at liberty to share, I mean the exact – obviously mixes of our customer shipments. I would tell you that most of our product pipeline is going to be gasoline or diesel, very limited jet shipments. And we’ve not really seen any kind of a change in demand for those product pipelines. It really just varies with refinery production, the refineries that we serve. Matt, I don’t know if you want to add anything to that one.

[Matt Clifton:]

No, I think that’s right, Bruce. We haven’t seen really – I think generally the refineries have a – at least in our geographic areas or incentivize [ph] the maximize diesel production just based on the crack spreads there. So we haven’t seen a material change in the mix in our pipes.

[Bruce Shaw:]

And then the last question, Mark, on tanks. We own between Tulsa, Cheyenne, El Dorado and a few tanks obviously in the crude patch. Over 400 tanks, the way our tank inspection program works, we’ll be inspecting call it 10% or so those tanks every calendar year. And I think if I remember right, our forecast – approximate forecast for depreciation expense in the fourth quarter is $17.5 million to $18 million. So, slightly less than our number for the third quarter this year.

[Doug Aron:]

The only thing I’d add there, Mark, just so to until we’re transparent on these. Most of these tank write-downs, particularly one that we experienced this quarter, and I think we’ve had some impacted in previous quarters related to the purchase by HEP of tanks at El Dorado, Tulsa and Cheyenne all from HollyFrontier. And part of that transaction in order to shift kind of the risk inherent in the first regulatory inspection of the tank and sometime to the seller from the buyer, we had a provision that to the extent that we found in that first inspection significant repairs that had to be made or replacement had to be made that the seller in this case, HollyFrontier, would reimburse us. Unfortunately, which is I think prudent from a cash flow and financial standpoint. From an accounting standpoint, it just – when we have a situation where we have to condemn a tank, even though it’s being reimburse, we have to accelerate the depreciation that was allocated to that tank. And so we have a non-cash hit to the P&L.

[Mark Reichman:]

Okay. Thank you very much. I appreciate that.

[Operator:]

Your next question comes from the line of Theresa Chen with Barclays Capital.

[Theresa Chen:]

Hi there. I just had a question about the implied terminals – terminalling fee this quarter. It rose pretty strongly both on a year-on-year and quarter-over-quarter basis more so than a tariff increase that implied. Any color on that, on how sustainable that is or is there one-time things that happened?

[Bruce Shaw:]

No. This is Bruce. I’ll take that one. We do have as our terminalling volumes include more blended barrels, lot of times the decisions by our shippers to blend or add certain things to barrels can create an extra fee of the terminal. I think the terminalling fee per barrel – I don’t have in front of me on a per barrel basis. We don’t expect great increases to that overtime, but I believe it’s a really result of shipper decisions on a quarter-by-quarter basis.

[Theresa Chen:]

Okay. And any color on the strength also seen in the third-party terminalling volume this quarter?

[Bruce Shaw:]

The only change there is we’re seeing a little more volume at our Tucson terminal, out in Arizona. We’re seeing a little more third-party interest in terminalling there. So the majority of the increase you see in third-party terminal volumes is going to come from that Tucson terminal.

[Theresa Chen:]

Thank you.

[Bruce Shaw:]

Sure.

[Operator:]

(Operator Instructions) Your next question comes from the line of Connie Hsu with Morningstar.

[Connie Hsu:]

Hi, good afternoon everyone. My question is on your crude pipeline volumes. I was surprised to see that they were down a bit, down 8% compared to last year, 6% compared to last quarter. Could you provide some color here on what caused the drop?

[Bruce Shaw:]

Sure. So Connie, our crude volumes, of course those are going to be made up of both trunk line volumes and gathering volumes. Our gathering volumes were pretty consistent and had been pretty consistent this year. And I think as Matt mentioned, they are up close to 50% over the original volumes we saw back in 2008, 2009 timeframe when we bought the system. The trunk volumes are going to vary depending on how many barrels the Navajo refinery decides to bring in by truck can vary. What we’re seeing is we expand and enhanced the Malaga area and the gathering in trunk line system, in transition we may see a few barrels – a few more barrels brought in by truck, that are typically brought in on truck lines by pipeline and that may show or demonstrate – come out in a temporary decrease in overall crude shipments. But we don’t think that is something that will happen long-term. It’s just going to bounce around a little bit as we get that new project completed and online in the spring of next year.

[Connie Hsu:]

Okay, thanks. And so that should affect – well, it would likely affect your fourth quarter volumes as well then?

[Bruce Shaw:]

It could have a small impact. I would tell you that from a revenue perspective it’s very, very limited given the minimum contractual commitments we have on those trunk pipelines. So really from a revenue perspective, it’s going to have little if any impact. From a volume barrels per day perspective, you may see a similar number in the fourth quarter, that’s right.

[Connie Hsu:]

Okay. And then in your comments early you mentioned the crude rail facility and the potential pipeline from Cheyenne to Denver. It seems less likely than before. So if those don’t end up happening, could you comment on what other growth options you’re looking at now?

[Bruce Shaw:]

Well, as we mentioned and I think Matt touched on too, that the two real growth kind of built-in growth areas for HEP right now center around our crude gathering and delivery business in Southeastern New Mexico that we continue to look for ways to expand in addition to the currently identified project. We also have built in growth around the UNEV pipeline once the refinery expansions are complete in Salt Lake City. Other places we look for growth would be taking our crude transportation expertise to other areas where we see crude production growth that also combined with geographies that are near existing HollyFrontier refineries. So nothing definite to report, for example around the other refineries, Cheyenne, El Dorado or Tulsa but we continue to look real hard at areas like those that may provide opportunity for us.

[Connie Hsu:]

Okay. That’s great. Thank you.

[Operator:]

That was our final question. And now I’d like to turn the floor back over to Blake Barfield for any additional or closing remarks.

[Blake Barfield:]

Thanks again for joining the call today. Please feel free to reach out to Investor Relations if you have any follow-up questions, otherwise we look forward to sharing our fourth quarter and full-year 2013 results next February.

[Operator:]

Thank you. This concludes today’s conference call. You may now disconnect.