Holly Energy Partners L.P Management Discusses Q1 2014 Results - Earnings Call Transcript

May. 1.14 | About: Holly Energy (HEP)

Holly Energy Partners L.P (NYSE:HEP)

Q1 2014 Earnings Call

May 01, 2014 4:00 pm ET

Executives

Blake Barfield

Douglas S. Aron - Chief Financial Officer of Holly Logistic Services, L.L.C and Executive Vice President of Holly Logistics Services, L.L.C

Bruce R. Shaw - President of Holly Logistic Services, l.l.c

Analysts

Theresa Chen - Barclays Capital, Research Division

Cory J. Garcia - Raymond James & Associates, Inc., Research Division

Michael J. Blum - Wells Fargo Securities, LLC, Research Division

Mark L. Reichman - Simmons & Company International, Research Division

Operator

Welcome to the Holly Energy Partners' First Quarter 2014 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, Nicole. Thanks to each of you for joining this afternoon. I'm Blake Barfield, Investor Relations for Holly Energy Partners. Welcome to our first quarter 2014 earnings call. With us today are Bruce Shaw, President; and Doug Aron, Executive Vice President and CFO.

This morning, we issued a press release announcing the results for the quarter ending March 31, 2014. If you would 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, May 1, 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 financial measures. Please see today's press release for reconciliation to GAAP financial measures.

With that, I'll turn the call over to Doug Aron.

Douglas S. Aron

Thanks, Blake, and thanks, everybody, for joining us this afternoon. Last week, Holly Energy Partners announced a quarterly distribution of $0.5075 per unit. The quarterly distribution will be paid Thursday, May 15, to unitholders of record as of next Monday, May 5, 2014. This distribution represents a 6.3% increase over the distribution for the first quarter of 2013 and marks the 38th consecutive increase in HEP's quarterly distribution every quarter since our public offering.

For the first quarter 2014, Holly Energy Partners generated distributable cash flow of $41.8 million. DCF in the quarter was stronger than anticipated due to better-than-planned volumes on HEP assets serving HollyFrontier's Navajo refinery, which had been running at reduced rates earlier in the quarter.

Additionally, lower OpEx due in part to favorable adjustments to environmental accruals and the postponement of a turnaround at Alon's Big Spring refinery benefited DCF and net income in the period.

EBITDA was $57.9 million in the first quarter, up significantly from the $45 million in the same period of last year. Notably, first quarter 2013 EBITDA was negatively impacted due to longer-than-scheduled planned maintenance at the Navajo refinery.

Net income attributable to HEP for the first quarter was $24.1 million, an increase from the $18.4 million in the same time period of 2013.

Operating expenditures in the period totaled $22.8 million, including $1.2 million of reimbursable OpEx for which there was offsetting revenue.

OpEx, excluding reimbursable expenditures without -- or rather with offsetting revenue, was lower than most recent guidance of $24 million quarterly. This benefit resulted primarily from onetime reductions in environmental accruals and approximately $1.3 million in maintenance costs originally budgeted for the first quarter that we plan to spend later in the year.

Depreciation and amortization was $15.6 million in the quarter, and G&A expenses were $3.2 million, slightly above our expected quarterly range of $2.5 million to $3 million.

As a result of the minimum commitment structure in many of HEP's contracts, we recognized $9.3 million of deferred revenue in the first quarter, principally from shortfalls on the UNEV Pipeline. Quarterly revenues billed for volumes below minimum commitments on UNEV are typically deferred throughout the year and recognized annually in the first quarter.

The deferred revenue recognized in the first quarter of 2014 offset the $1.8 million of shortfalls billed in the quarter. At March 31, we had $4.4 million in deferred revenue on our balance sheet and anticipate recognizing $200,000 of deferred revenue in the second quarter.

Regarding Holly Energy's credit facility, as previously announced in March, we redeemed $150 million of 8 1/4% notes. The early extinguishment of this debt resulted in a onetime $7.7 million charge. At current market rates, we expect this will translate to approximately $8.5 million in annual interest expense savings and would anticipate roughly $9 million to $9.5 million in quarterly interest expense going forward.

At quarter end, following the redemption of the 8 1/4% notes, HEP had $300 million of 6 1/2% notes due 2020 and $538 million drawn on our $650 million credit facility.

Now I'd like to turn it over to Bruce, who has some comments before we open the call to questions.

Bruce R. Shaw

Thank you, Doug, and thanks again, everyone, for joining us today. In my brief comments this afternoon, I'd like to cover our CapEx spend in the quarter, as well as reemphasize HEP's plans for future growth.

And beginning with capital spending, our CapEx for the first quarter 2014 was approximately $18 million, excluding CapEx that was reimbursed by HollyFrontier. And of the $18 million, just under $1 million was for maintenance capital expenditures. The remainder of the spending included investment in our Southeastern New Mexico crude gathering project and the UNEV Las Vegas rack expansion.

In 2014, we expect maintenance capital to be approximately $7 million and expansion capital expenditures, excluding reimbursable CapEx, to be in the $40 million to $50 million range.

Now on the topic of future growth. As I underscored on our last call, HEP recognizes the value of visible future growth, so let me outline what's in the visible column at this point and also what we're doing to add more to that column. As Mike's press release quote today mentioned, we're seeing increased volume on our Southeastern New Mexico gathering system overall and from a few new expansion segments that are already in operation. Once the system is fully complete in August, we expect to generate approximately $10 million of additional revenue, with strong potential to build from that level.

Also, with UNEV's rack expansion in North Las Vegas, the UNEV Pipeline is ready to transport larger volumes once the refinery expansions in Salt Lake City are complete in late 2014 and late 2015. Together, these expansions will result in approximately 20,000 barrels per day of additional light product supply.

For each additional 10,000 barrels per day shipped to Las Vegas, UNEV, on a 100% basis, generates almost $12 million in pipeline revenue at the infinite [ph] tariff rate and over $17 million in pipeline revenue at the spot rate. So if UNEV ships 15,000 barrels per day of the refinery expansion barrels at the incentive rate, that will generate about $20 million in additional revenue, including pipeline tariff and assuming customary terminalling fees. And with very low incremental operating expense expected, HEP's 75% interest would receive about $15 million in additional EBITDA.

Finally, HEP's contractual rate increases based on the PPI and FERC oil index, depending on the contract, add about $6 million to $9 million per year to revenue. Taken together, we expect that these visible growth sources will increase HEP's annual EBITDA by over $30 million or about 15%.

In addition to ongoing evaluation of potential acquisitions, we're focused on adding to the visible growth column by pursuing newbuild projects that leverage HEP's and HFC's existing asset footprints and organizational capabilities. Our first priority in this area is to boost volumes beyond currently committed levels on our existing system and to capitalize on opportunities in new high-growth crude production areas.

Though we don't have a specific newbuild project greenlight-ed yet to discuss, we are initially focusing on potential gathering system projects in the Rocky Mountain region. Also, we're evaluating the construction of several new tanks at HollyFrontier's El Dorado Refinery, as well as additional pipeline connections that could increase the refinery's crude flexibility.

To conclude, I'd like to thank everyone of our employees on the HEP team for their continuing focus on safety, system reliability and customer service. HEP would not be what it is today or be ready for tomorrow's growth without their efforts.

Now Nicole, I think we're ready to take a few questions.

Question-and-Answer Session

Operator

[Operator Instructions] Your first question comes from the line of Theresa Chen from Barclays Capital.

Theresa Chen - Barclays Capital, Research Division

Question on the new projects under consideration. When do you think you would feel comfortable sharing more details about timeline or economics on these projects, the Rocky crude gathering project and the El Dorado tanks?

Bruce R. Shaw

Theresa, we think that kind of on a quarter by quarter basis and obviously as soon as we knew something, we would -- we'd be sure to tell everybody about it. Though on this particular project that we're -- a couple of projects we're looking into, I'd be surprised if we got to say August or September and didn't have more to say. Wouldn't be the first time I've been surprised but I would think over the next 3 to 6 months, we'd be able to better define that.

Theresa Chen - Barclays Capital, Research Division

Great, that's very helpful. And then touching upon what you said about the M&A outlook, can you just give us some incremental color on what you're seeing in terms of third-party acquisitions right now? Do you have appetite for that? Or are there assets out there that you're looking at that are attractive?

Bruce R. Shaw

I can certainly take that one. We continue to look at, as I mentioned in the comments, continue to look at third-party opportunities. We,, sometimes, will see more rather than less. I wouldn't say that currently we're really seeing a big difference in the opportunities that are out there in terms of assets that are for sale. But so far, we just haven't found something that's the right strategic fit at the right price. But we continue and have a good team of folks that look at that, and we'll continue to do so along with these organic projects that I talked about.

Douglas S. Aron

Theresa, I maybe would just add, this is Doug Aron, I would only add to that, that I think perhaps we saw the top of that market maybe 6 to 9 months ago and that we've seen some abatement to what we saw as exceptionally high prices. I mean, as Bruce said, obviously, we've not been able to announce anything yet, but I guess we're more optimistic about something in the next 12 months than we were in the previous 12.

Operator

Your next question comes from the line of Cory Garcia from Raymond James.

Cory J. Garcia - Raymond James & Associates, Inc., Research Division

One of the scenes that actually has been coming up on quite a few calls this quarter has been the lightening up of the crude stream, particularly now we're sort of starting to hear about it on the Permian as well. Just curious as to your thoughts given your New Mexico gathering footprint, if you guys are actually seeing a similar trend? And if so, is there the potential there for maybe a separate condensate-focused infrastructure or handling out there?

Bruce R. Shaw

Cory, this is Bruce. I think from what we know and we're seeing, we're probably too early to talk about a separate system or a new project focused on condensate. We have seen, as you get towards the south end of our system, some of the new production being lighter. What's interesting is you get -- and as you talk to various producers and get actually a little further south, down south of the Texas border, things get a little less light actually. So at this point, we are seeing sweeter crude. Obviously, the system that we're working to expand will give us increased capability around the lighter crudes, but I think it's too early for us to say anyway that we see a need for a new or separate investment to handle condensate.

Cory J. Garcia - Raymond James & Associates, Inc., Research Division

Okay. No, that's helpful. And I guess given some of the crude pricing dislocations, just talking sort of WTI Midland now, would you guys refresh my memory with regarding to the crude by rail terminal that I know you guys were evaluating at some point? Have you seen any producers come back and maybe knock on your door and saying they've been sitting with disconnects as long as they have now?

Bruce R. Shaw

No, we actually have not. We -- as we -- I think we've hit on this a couple of times since we originally talked about it where we wanted our desire to anchor that project, the most logical destination for crude by rail from our area would be out to West Coast refiners. And where that initial appetite when we announced the project was pretty strong because we're looking at $20 or $25 WTI-type spreads, they just hasn't materialized or didn't stick around. So the volatility at least gave refiners pause in a way that just didn't allow contracts to come through that would support that kind of investment for unit trains, at least from our point of view.

Operator

[Operator Instructions] Your next question comes from the line of Michael Blum from Wells Fargo.

Michael J. Blum - Wells Fargo Securities, LLC, Research Division

I guess just on the gross capital, the $40 million to $50 million that you referenced, is that a placeholder, or you have identified projects for that capital? And if so, could you kind of talk about them?

Bruce R. Shaw

Sure, Michael, Bruce again. About half of that capital is going to be spent to finish up the Malaga expansion project, what we call Malaga, our crude gathering expansion project. And a little bit of that is spent to finish up the Las Vegas rack expansion. The balance are on a few different projects that we've got spec-d, some that will be used to build a few additional storage, bit more storage capacity at a couple of the HFC refineries. But the majority of it right now is identified, so it's not really spec capital, it's finishing up the projects that we've already talked about in a little bit on additional storage capacity.

Michael J. Blum - Wells Fargo Securities, LLC, Research Division

Okay. And then in terms of the significant interest expense saving that you got with the refinancing, should we think of that now as effectively distributable cash flow that could be paid out?

Douglas S. Aron

I think the answer is partially yes, and at the same time, we want to be careful not to assume that interest rates will stay close to 0 forever. I think maybe what we said on the last quarter was that at the size of what we paid off on the senior notes in March, a refinance there didn't make a whole lot of sense. If there were an acquisition where we could do some refinancing, we'd maybe look at a bigger piece. But I'd say, for now, that largely say yes, most of that could be considered for distributable cash flow with some holdback exception.

Operator

[Operator Instructions] Your next question comes from the line of Mark Reichman from Simmons Capital.

Mark L. Reichman - Simmons & Company International, Research Division

I was just wondering if you could just go back. Earlier, you've kind of alluded to your expected ramp-up in revenues and cash flows associated with UNEV, the rack expansion and then the Southeastern New Mexico crude gathering system expansion. So recognizing that some of that capital has already been spent and already kind of reflected in your financing, could you just kind of walk us through the timing on that, kind of stairstep us? Because I'm guessing that a lot of that's probably more of a late '14, early '15 -- at least that's what I show. But nonetheless, that would be appreciated. Then also on the growth opportunities, I think in the press release you pretty much had kind of identified the Rockies. But what specific areas? I mean, it seems like most of the refiners these days realize that refining is kind of a low growth kind of a mature industry. So a lot of them like Phillips and others are focusing on their midstream, which is causing them to really be aggressive, and I think, looking outside their footprint. And with this added competition, kind of how do you think about your growth strategy and your organic versus acquired opportunities?

Bruce R. Shaw

Mark, it's Bruce. I'll take those in turn. On the revenue timing, if you look at the Southeastern New Mexico gathering incremental revenue, that's going to start towards the end of August, the beginning of September. So it'll kind of cover us for the last, call it, 4 months of the year, that -- when that $10 million a year roughly stream will begin. We're getting just a little bit of that, less than 10% of that, now only because we've connected a few gathering segments. But for all intents and purposes, count back kind of end of August, early September. On the PPI and FERC oil index increases, that, for us, roughly average out to whatever the PPI is going to be once you kind of sift all the way through the numbers. The majority of that increase takes hold for us July 1 of each year because that's when the HollyFrontier contracts contractually step up. So that $6 million to $9 million, assuming a 2% to 3% PPI increase, is coming from that -- coming at that time. On the unit pipeline increases, Tesoro has announced that their expansion will be finished before the end of 2014. In my understanding, that's 4,000, 5,000, 6,000 barrels a day. That's about 25% of that total Salt Lake City expansion. That happens late this year. So obviously, none of that is committed to the pipeline. We'd certainly expect some of that to come our direction, but that would be late 2014, early 2015. And then based on what HollyFrontier has said about the timing of their Woods Cross expansion, that's late 2015. The other 75% of that 20,000 barrels a day would, safest bet most conservatively, would be kind of early 2016 when that would start -- we'd start seeing that volume. So that's roughly how those pieces step out in time. On your question about the Rockies, we don't want to get too specific just for competitive reasons and just to keep options open. But it would be logical to assume we'd be looking at places where not only, well, where HollyFrontier currently has a refining presence and/or crude trading or crude purchasing presence. So not surprisingly, the Rockies contains the Niobrara and the Uinta and I would certainly include those at the top of the list of Rockies opportunities. And in terms of how we approach projects and/or growth given the new presence of a lot of the newly formed MLPs from our refining or HollyFrontier's refining peers, it's really -- there's really nothing really new here except that you continue -- we continue to build off the assets we currently own over in areas or geographies where we currently have what we feel to be a competitive advantage. So certainly, it's crowded the field a bit in terms of what was already a crowded field when it comes to essential acquisitions, but really doesn't change our thinking or strategy around how we approach organic projects.

Operator

If there are no further questions, I will turn the floor back over to Blake for 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 second quarter results in August.

Operator

This concludes today's conference call. You may now disconnect. Thank you for joining, and have a great day.

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