Holly Energy Partners, L.P.
Q4 2013 Earnings Call Transcript

Published: 21 Feb 2014

[Operator:]

Welcome to the Holly Energy Partners’ Fourth Quarter 2013 Conference Call and Webcast. [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, Jessica, and thanks to each of you for joining this afternoon. I'm Blake Barfield, Investor Relations for Holly Energy Partners. Welcome to our fourth quarter and full year 2013 earnings call. With us today are Mike Jennings, CEO; Bruce Shaw, President; and Doug Aron, Executive Vice President and CFO. This morning, we issued a press release announcing results for the quarter ending December 31, 2013. If you'd like a copy of today’s press release, you may find one on our website, www.hollyenergy.com. Before Doug and Bruce proceed with the 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 information presented on today’s call speaks only as of today, February 20, 2014. 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.

[Douglas S. Aron:]

Thank you, Blake, and thanks to each of you for joining us on our call this afternoon. On January 23, Holly Energy Partners announced a quarterly distribution of $0.50 per unit. This distribution reflects a 6.4% increase over the $0.47 per unit declared in the fourth quarter of 2012. The quarterly distribution was paid last Friday, February 14, to unitholders of record as of February 4, 2014. The increase marks 37 consecutive quarterly increases in HEP's distribution to unitholders, and more than doubles the initial distribution paid for the quarter end following HEP's public offering 9 years ago. For full year 2013, Holly Energy Partners paid $1.96 per LP unit, and cash distributed by the partnership totaled more than $144 million, an increase of nearly $20 million from the prior year. The $144 million distributed by HEP in 2013 was out of a total $147 million of distributable cash generated last year. That figure is approximately a $6 million decrease from the record $153 million in DCF generated for 2012. For the quarter ended December 31, 2013, Holly Energy Partners' distributable cash flow was $34 million -- $34.3 million. DCF for the fourth quarter and full year of 2013 was negatively impacted from both planned maintenance and unplanned operational issues at HollyFrontier's Navajo Refinery, which impacted volumes shipped on HEP assets in that area. As of the end of January, throughputs on HEP's assets that serve the Navajo Refinery have returned to normalized rates. EBITDA was $46.6 million in the fourth quarter, less than the $54.7 million earned in the same period last year, and below our approximate guidance of $50 million per quarter, going forward. Net income attributable to HEP for the quarter was $19 million, a decrease from the $27 million in the same period last year. The decrease in net income attributable to HEP is due principally to year-on-year decreases in revenues, increases in depreciation and amortization resulting, in part, from storage tank write-downs and higher operating cost from maintenance expense and property tax accruals. For the fourth quarter, the reimbursable portion of operating expenses, for which there is offsetting revenue, was approximately $3.5 million, and total operating expense was $27.4 million. Excluding the reimbursable expenses for which there is offsetting revenue, we expect quarterly OpEx in 2014 to be approximately $24 million. G&A expenses were $3 million for the fourth quarter, in line with our expected quarterly range of $2.5 million to $3 million. At year-end, long-term minimum-commitment contracts with major customers will result in minimum annualized payments of approximately $259 million. Now for an update on shortfalls billed and deferred revenue recognized during the quarter. In the fourth quarter of 2013, shortfalls billed for shipments below minimum commitments totaled $3 million offset, in part, by $2.3 million of deferred revenue recognized in the quarter, including $500,000 in clawbacks. At year-end 2013, we had $12 million in deferred revenue recorded on the balance sheet. In the first quarter of this year, we expect to recognize approximately $9.3 million of deferred revenue relating, principally, to shortfalls on the UNEV Pipeline. Speaking to HEP's credit facility, last week, we announced the redemption of $150 million of 8.25% notes due 2018. The total payment of this redemption is approximately $156 million and will result in an approximately $7.5 million interest expense in the first quarter of 2014. At current market rates, HEP will save approximately $8.5 million in annual interest expense as a result of this redemption. Once these notes are redeemed, HEP will have $300 million outstanding in principal amount of the 6.5% senior notes, which are due 2020. As of December 31, 2013, we had $363 million borrowed from our credit facility, leaving $287 million on remaining authorization from our recently expanded $650 million facility. Following the senior notes redemption, HEP will have approximately $519 million drawn on the revolver. Now I believe Bruce has a few comments before we open the call for questions.

[Bruce R. Shaw:]

Thank you, Doug, and thanks, everyone, for listening in. As Doug mentioned, our distributable cash flow for 2013 was $147 million which, while down slightly from 2012, reflects the resilience of HEP's business model and the continuing production growth around our crude gathering system in Southeastern New Mexico. This model, supported by long-term commitment contracts, allowed us to raise distributions each quarter in 2013, and maintain an above 1x coverage during the year, with 2 unusual quarters, the first and fourth, that contains planned and unplanned downtime for one of HEP's main customers, HollyFrontier's Navajo Refinery. Our fourth quarter distributable cash flow of $34.3 million was ahead of our 4Q '13 DCF guidance, primarily due to slightly better volumes than forecasted. And though we don't normally provide quarter-specific DCF guidance, we will make an exception for this first quarter of 2014, since the waste water constraints that limited production volume at HFC's Navajo Refinery extended into January, as previously announced by us and by HollyFrontier. So assuming there are surprises, positive or negative, we expect DCF for the quarter ending March 31, 2014, to be about 5% to 10% below a typical quarterly run rate of $40 million. We've already placed certain segments of our crude gathering system expansion in Southeastern New Mexico in service, with the overall project now expected to be fully complete in August. Since last quarter's call, we've agreed with HFC to amend the scope of the project so that barrels injected into the system will have even more delivery point flexibility. This increases the total project cost from $35 million to $40 million to $45 million to $50 million, with HEP recouping the additional project cost over the first 5 years of operation. As Mike mentioned in his press release quote, the segments already in service are currently contributing to cash flow, with the majority of the cash flow expected to begin late third quarter 2014. Looking forward, the HEP management team recognizes the importance of continued growth. Disciplined growth is our objective, and it is what drives our investment decisions. And when we say disciplined growth, we mean aggressively seeking out opportunities that fit both our strategic and financial criteria. We'll pursue both acquisitions of existing assets and newbuild projects that build on our core capabilities and our assets. To that end, we are investing more resources on the growth potential of our crude transportation business, both to boost volumes on our existing system and to capitalize on opportunities in new high-growth crude production areas. Though we don't have any specific projects to discuss at this time, we can say that we are initially focusing on the Rocky Mountain region, and we'll keep you posted on our progress. We are also on schedule to complete the expansion of UNEV's North Las Vegas terminal in April. The project will double the number of existing loading racks there from 2 to 4, and will enable the pipeline to better serve customers with peak volume seasonality, as well as position the terminal to handle more volumes once refinery expansions are complete in Salt Lake City. Though we don't expect significant upside for UNEV over minimum volume commitments until those refinery expansions are complete in late 2014 and 2015, we did see periods in the fourth quarter where shipments on UNEV exceeded 25,000 barrels a day, including UNEV's first spot volume shipments during the quarter. As we've highlighted previously, UNEV's economics are supported by minimum commitments from HFC and Sinclair, and a GP giveback from HFC related to HEP's ownership interest. Our CapEx for the fourth quarter of 2013 was $18.6 million, of which $2.1 million was for maintenance capital expenditures. For 2013, as a whole, CapEx was $52.1 million, including $8.7 million of maintenance CapEx, and $10.2 million of CapEx reimbursed by HollyFrontier related to tank maintenance under contractual agreement. Excluding maintenance and reimbursable CapEx, the majority of our spending in 2013 was toward our crude system and North Las Vegas terminal projects. We expect 2014 maintenance capital to be approximately $7 million, and expansion capital expenditures, excluding reimbursable expenditures, to be in the $40 million to $50 million range. To conclude, I would like to thank every one of our employees for being part of the HEP team, and for their focus on safety, system reliability and customer service. HEP wouldn't be what it is today or be ready for future growth without their efforts. Now I'll turn things back over to Blake, and we'll take a few questions.

[Blake Barfield:]

Thanks, Bruce. Jessica, at this time, we will open the call for questions, if you could again please provide the instructions.

[Operator:]

[Operator Instructions] Your first question comes from Mark Reichman from Simmons & Company.

[Mark L. Reichman:]

Just a couple of questions on the Southeastern New Mexico crude gathering system expansion. You did mention the scope was broadened, and I think originally that, that expansion was expected to generate roughly $7.5 million of incremental annual revenue for minimum volume commitments, and then an additional $1.5 million to $3.5 million of estimated gathering revenue, as new lease production was connected. Are those revenue targets still intact or would you expect the economics to rise with the increased investment? And also, when it fully goes into service, what's the increased capacity that you would expect across your systems?

[Bruce R. Shaw:]

Mark, this is Bruce. Let's take those questions in order. First question, about would we really expect more revenue out of the system? We certainly do longer-term. I want to focus, though, on the numbers you talked about, the $7.5 million is what is committed for the project. The $1.5 million to $3.5 million, we think is still a good range for potential above that. We're going to be working hard to increase that number, but we're just not ready to talk about what that range -- that increased range could be. And as you may have picked up in my comments, talked about the recouping of that initial investment over the first 5 years, just recognizing that there is no more committed revenue that we know for sure. So we're going to work hard to fill that up and add more to that. We're just not ready to put that out -- an estimate for that out yet. I believe your second question was about increased capacity on the system, and to that end, what this is doing, as I mentioned as well, it really increases the delivery point flexibility for a barrel entering the system, going to the various exit points that we offer. So it does increase the capacity, our ability to deliver to the exit points by, call it, 30,000, 40,000 barrels a day, better than what we originally had scoped. But more than anything, it allows us to take a barrel that goes into the system at any one of the delivery points and have better ability to move it across the system to the variety of exit points that we offer.

[Mark L. Reichman:]

Okay. And then, second, I think, in your earlier guidance, you had mentioned that January constraints at the Navajo Refinery was expected to reduce the first quarter crude throughput by about 10,000 barrels per day, what's it running at now? I mean, you had mentioned normalized levels.

[Bruce R. Shaw:]

The overall gathering system gathers today between 70,000 and 80,000 barrels a day. Obviously, varying a bit, but that's the general range. I remember talking a little bit about the impact of the issues in November, December and January, but given that those issues have been resolved, as covered earlier, we're seeing it back in its normal range, so...

[Mark L. Reichman:]

Lastly, and I'll get back in the queue, is on your liquidity and capital availability. You've mentioned the $40 million to $50 million of growth CapEx in '14, yet you'll have $519 million drawn on the $650 million credit facility. How much of that Southeast expansion has already been financed? And what are your financing plans over the course of the next year?

[Bruce R. Shaw:]

Well, as far as the crude expansion, we've spent 40% to 50% of that capital already, approximately. And in terms of financing, the reason we had that upsized facility and have that dry powder was to cover -- more than cover the known projects we have. Clearly, if other projects come up, that would drive additional financing decisions. But certainly, I'll defer to Doug if he has any other comments, but I think we're confident we've got the financing in place we need for now.

[Operator:]

Your next question comes from Theresa Chen from Barclays Capital.

[Theresa Chen:]

Just a follow-up on the previous question about the New Mexico crude system expansion. You had mentioned that some segment portion of the system now is in operation and contributing to results. Can you quantify around how much that is? And in August, when the system is fully online, do you expect the full $7.5 million to go into effect immediately or will there be some ramp-up period?

[Douglas S. Aron:]

Once the project is fully complete, the way our agreement works and commitment works, is that annual run rate of $7.5 million will begin at that time. So there won't be a ramp-up of the $7.5 million commitment once the project is deemed fully complete. In terms of quantifying the existing cash flow contributions, I hesitate to do that. I will tell you, it's less than 10% of the eventual flow of the system currently. What we connected are some gathering connections over on the west side of the system, so relatively small contribution, but real contribution even at that.

[Theresa Chen:]

Great. And then on your comments about the proposed Rockies pipeline, you seem more positive about it this time around versus last quarter. Can you just give some color on that shift in tone?

[Bruce R. Shaw:]

Sure. Let me clarify for you, Theresa, we are not suggesting that -- my comments on the Rockies had to do with crude transportation opportunities. The pipeline that we had looked at for a while, but have since put on the shelf, are the Cheyenne to Denver products pipeline, as a separate project. So I don't want to miscommunicate there and mislead you. That's a different issue. So we are exploring and see some good potential in the Rockies region for some crude gathering potential projects. But we do not currently plan to proceed with the Cheyenne to Denver products pipeline.

[Operator:]

[Operator Instructions] Your next question comes from Edward Rowe from Raymond James.

[Edward Rowe:]

All my questions have been answered.

[Operator:]

[Operator Instructions] Your next question comes from Mark Reichman from Simmons & Company.

[Mark L. Reichman:]

Yes, I just wanted to follow-up. On the Southeastern New Mexico crude oil gathering system expansion, my understanding was that project entails converting an existing refined products pipeline to crude oil service and then you were going to construct several new pipeline segments, expand the existing pipeline and build new truck unloading stations and crude storage capacity. So which of those elements has already been completed to date? And then what's the timing on executing the rest of the implementation? And then the second question is targeted towards, I thought that there were several potential projects with HollyFrontier that were being considered, one being an interstate crude oil pipeline between Cushing and HFC's Tulsa, Oklahoma refinery. So what's the status with those projects?

[Bruce R. Shaw:]

Mark, on the crude system -- Bruce again here. The gathering -- a few of the gathering lines on the west side of the system that bring crude in had been completed. We expect here, over the next 2 to 3 months, to have that piece of pipe that we're converting -- the dormant piece of product pipe converted so it can assist in bringing barrels from further away into the system. In terms of the -- some of the additional storage and some of the connections, for example, the connection will have to the Plains [indiscernible] pipe out there to the east. That's going to happen later in the summer, and that's what's driving the August completion date. So really, for now, we've got a few gathering connections in place and we expect to have this converted piece of pipe in service before the end of the spring, early summer, with everything being complete late summer. On the projects we talked about in the past, and I think I talked a bit about on the last call, none of the projects currently have either economic or industry fundamental support to go forward, including the crude pipeline project from Cushing to Tulsa or the product pipeline project from Cheyenne to Denver. I know we also talked about adding a crude-by-rail capability to our Southeastern New Mexico gathering system; that project's also on hold but one we can certainly pull off the shelf if we saw reason or customer interest enough to put that back on.

[Operator:]

Your next question comes from Michael Blum from Wells Fargo.

[Michael J. Blum:]

Just -- I wanted to ask about kind of the thought process behind the decision to use your available capacity on the revolver to redeem your notes. And the incremental interest cost savings, should we sort of think of that almost as a, sort of, a -- in lieu of an organic project that's a way, effectively, to generate incremental cash flow that would potentially support distribution growth? Just trying to think about the way that you came to that decision. And then, I guess, the second part of that would be, would you intend to keep that debt on the revolver? Would you plan to turn it back out at a more favorable rate?

[Douglas S. Aron:]

Michael, this is Doug Aron. A couple of thoughts there, one, ATP has really been in a fixed debt position, almost to the tune of 100% of our debt outstanding. In addition to the 2 notes -- senior notes we had outstanding, we've entered into a swap for a floating to fixed rate swap for almost all of what was drawn under our revolver prior to this refinancing. And if you look at a typical structure for really MLPs or even C Corps for that matter, some percentage of floating rate debt, we believe, makes some sense, particularly in this historic low interest rate environment. So our view is, right now, to take $150 million and have it be floating rate debt at a rate that's sub-2.5% or even 2.25%, is just -- it's a good decision for us. As those swaps wear off over time, perhaps, we'd look to refinance with some longer-term debt. But hard to imagine it being less than what the revolver is available to us. We absolutely don't view that refinancing in lieu of organic growth projects; the 2 are completely separate. It's more of a capital structure decision. And we are continuing, as Bruce mentioned, in a number of different areas, notably the Rockies from a crude perspective, but also this west Texas system, to look at organic opportunities to grow revenues and distributions for HEP.

[Operator:]

Your next question comes from Connie Hsu from Morningstar Financial.

[Connie Hsu:]

I just had a question on your operating leverage. I'm just looking at 4% change in revenue this past quarter that converted to roughly a 25% change in operating profit. So -- and I know there were some exceptional costs in that. So I'm just wondering if you could provide an estimate for the percentage of your operating costs that you think are fixed?

[Bruce R. Shaw:]

Connie, this is Bruce. I mean, we can kind of estimate that. Basically, most of our costs that we have in the pipeline business are going to be fixed cost. If you think about variable cost in our business, really, the only element of variable cost is going to be electricity, going to be power-related. So I would say, 85%, 90% of our cost in that range are going to be fixed costs. You have to be careful, sometimes, looking at our revenue line related to our profit line only because we have, as we have talked about, some of these contracts that have revenue recognition rules. We may receive cash flow and, of course, that's more of a distributable cash flow concept. But just want to caution you, especially with our reimbursable operating expenses and reimbursable revenue, that can also distort the picture a little bit. But in answer to your operating expense question, we are pretty fully fixed operating expense, 85% to 90% range.

[Operator:]

There are no further questions at this time. I'll turn this call back over to the presenters.

[Blake Barfield:]

Thanks, everyone, 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 first quarter results in May.

[Operator:]

This concludes today's conference call. You may now disconnect.