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Executives

Julia Heidenreich

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.

Matthew P. Clifton - Chairman of Holly Logistic Services LLC, Chief Executive Officer of Holly Logistic Services LLC and Chairman of Executive Committee

Analysts

Edward Rowe

Theresa Chen - Barclays Capital, Research Division

Steven C. Sherowski - Goldman Sachs Group Inc., Research Division

Jeffrey Birnbaum - UBS Investment Bank, Research Division

Holly Energy Partners L.P (HEP) Q2 2013 Earnings Call July 30, 2013 4:00 PM ET

Operator

Welcome to Holly Energy Partners Second 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 Julia Heidenreich. Julia, you may begin.

Julia Heidenreich

Welcome to Holly Energy Partners Second Quarter Earnings Call. I'm Julia Heidenreich, Vice President of Investor Relations. With us today is 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 June 30, 2013. If you'd like a copy of today's press release, you can find one in our website, www.hollyenergy.com. Before 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 law. 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.

Today's call may also include discussion of non-GAAP measures. Please see today's press release for reconciliations to GAAP financial measures. Also, please note that information presented on today's call speaks only as of today, July 30, 2013. Any time-sensitive information provided may no longer be accurate at the time of any webcast replay or rereading of the transcript.

And with that, I'll turn the call over to Doug Aron

Douglas S. Aron

Thanks, Julia, and thanks to each of you for joining our call this afternoon. Last Friday, July 26, Holly Energy Partners announced the 35th consecutive increase in our quarterly distribution to $0.485 per unit. This represents a 6.6% increase over the split-adjusted $0.455 per unit we declared in the second quarter of 2012. This distribution will be paid August 14, 2013, to unitholders of record as of August 5, 2013.

Our distributable cash flow for the quarter ended June 30, 2013, was $36.1 million, which compares favorably to the $34.5 million distributable cash flow in the second quarter of 2012. Net income for the second quarter was $21.3 million, an increase from the $19.1 million for the same period in 2012. Operating expenses of approximately $24.5 million for the quarter were higher than 2012 second quarter amount of $21.9 million, due in part to environmental charges of over $1 million in the quarter, as well as an increase in reimbursable expenses and employee additions.

The reimbursable portion of operating expenses, for which there is offsetting revenue, was approximately $800,000. Going forward, for 2013, excluding $2 million to $4 million of reimbursable expenses, we expect operating expenses to be in the range of $20 million to $22 million per quarter.

G&A expenses were $3.1 million for the period, slightly above our expected quarterly range of $2.5 million to $3 million. Depreciation and amortization for the quarter was $15.1 million, an increase from $14.2 million in the same period last year, due principally to a partial tank write-down at the El Dorado Refinery.

As a reminder, approximately 85% of ATP revenues, and therefore any common distributable cash flow, are supported by minimum commitments from major customers. Annual minimum commitment as of July 1, 2013, are approximately $259 million, including 75% of the UNEV minimum commitments or $65 million per quarter.

Now I'll cover a few details relating to shortfalls billed and deferred revenue recognized during the quarter. Under certain contracts, the payments we received for quarterly shortfall billings below minimum commitments are included in distributable cash flow for the current accounting period. However, those payments are classified as deferred revenue and not recorded as revenue on ATP's income statement until a future period in which the revenue can be recognized.

Deferred revenue recognition results primarily from shortfalls billed in prior quarters, for which clawback rights were either used or expired. Recognition of these deferred revenues can also occur when a pipeline systems given capacity limits a shippers future ability to ship great enough volumes to reach the necessary commitment level to receive clawback credit.

Specific to the second quarter of 2013, shortfalls billed for shipments below commitments totaled $2.8 million, offset in part by a $700,000 of total forfeitures recognized as revenue in the quarter. As of June 30, 2013, we have $7.4 million in deferred revenue recorded on the balance sheet. And in the third quarter of 2013, we expect to recognize approximately $200,000 of deferred revenue.

EBITDA for the second quarter was $47.3 million, adjusting to add shortfall billings and subtract deferred revenue. This quarter's EBITDA total would have been $49.4 million. As was indicated in the prior earnings call, we expect EBITDA going forward to be approximately $50 million per quarter.

With regard to the ATP's credit facility, as of June 30, 2013, we have $355 million borrowed, leaving $195 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 our President, Bruce Shaw, for a few comments before we take questions.

Bruce R. Shaw

Thanks, Doug, and thanks to everyone for listening this afternoon. I just have a few comments to add today. First about performance of our base business, second about projects and finally a recap of capital spending before turning to questions.

So starting with performance, we're pleased that volumes on ATP's pipelines and terminals performed at or above expected levels, primarily reflecting post-Q1 turnaround refined product throughput at HFC's Navajo refinery and Alon's Big Spring refinery, and continuing strength in Permian Basin crude production. Looking forward, ATP's revenues will also be helped by the PPI and FERC oil index-related increases that went into effect for most of our contracts on July 1. The blended impact of these increases will boost ATP's revenue by about 2%.

Our operating expenses would also have met expectations in the quarter had it not been for an overrun, mostly due to one of our pipelines -- damaged to one of our pipelines caused by an unrelated third party. The pipeline was not out of operation long and was able to make up for lost time, thanks to the timely reaction and hard work on the part of our on-site team.

Per 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 or early 2015. Until then, UNEV is supported by minimum commitments from HFC and Sinclair, and a GP giveback from HFC related to ATP's ownership interest.

Next, a few comments on our current growth projects. We're making good progress on the expansion of our crude gathering system in Southeastern New Mexico. We will complete early components of this expansion starting later this fall, with completion of all aspects anticipated by the first quarter of 2014. The top end of our current budget is in the $40 million range for the project, and we'll add at least $7.5 million of annual revenue.

We're also on schedule to complete enhancements to UNEV's product terminal in North Las Vegas. The project will enable the pipeline to better serve customers with peak volume shipments when the ARB is open, especially in the winter, by increasing the number of truck loading racks to 4 total truck bays.

We continue to evaluate several potential projects with HFC, including a new crude pipeline from Cushing to Tulsa; a new products pipeline between Cheyenne and Denver; and a crude by rail project connected to our gathering system in Southeastern New Mexico. The evaluation work is taking a little longer than expected, due in part to market volatility. And we'll update you when go, no-go decisions are made.

Finally, our CapEx for the second quarter of 2013 totaled about $11 million, including $2.2 million of maintenance capital expenditures. This brings our total CapEx through June 30, 2013, to just over $17 million, including approximately $4.5 million of maintenance CapEx. The majority of the expansion capital spent this year, so far, has been on the Southeastern New Mexico crude gathering system project. Our 2013 capital spending is forecast to be approximately $50 million, of which most will be spent on the crude gathering expansion, a smaller portion on the UNEV terminal, with the remaining $10 million balance for maintenance CapEx.

I'd like to finish my remarks by thanking the entire HEP team for their strong commitment to safety, reliability and customer service. Our 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.

And with that, I'll turn things back over to Paula. And Paula, if you could just repeat the instructions for questions please.

Question-and-Answer Session

Operator

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

Edward Rowe

Given the interesting feedback and insight from E&P companies, talking about the Niobrara and understanding the fact that it's still tough to see customers wanting to commit to long haul pipelines to Cushing, but do you guys see some opportunities for shorter-gathering pipelines within the area, given your asset footprint?

Bruce R. Shaw

Well, what I can say on that one is that, certainly, with the Cheyenne Refinery from an HFC perspective, we won't comment on HFC's take on that crude quality. But one thing we continually work with from an HEP perspective work with HFC on, is looking for areas where pipelines or logistics assets, in addition to the current footprint, would help that business. Right now, HEP doesn't own crude gathering assets in the Niobrara crude patch, but something that certainly logical we'd be continually evaluating.

Edward Rowe

Okay. Fair enough. With crude spreads significantly depressing, has this really changed your view on crude by rail projects within the Permian?

Bruce R. Shaw

Well, it certainly is something we need to factor in. And then I'd defer also to any thoughts Matt or Doug may have on that one. But the bottom line is we recognize the crude spreads. If you think about WTI to Brent, or WTI to LLS, they're going to be volatile. So we don't want to base any decisions just on kind of current market static spread, but it's certainly something we factor into that, that decision process.

Edward Rowe

Okay. And final last question. In regards to the product terminal enhancements at Las Vegas, given it's a relatively small capital cost and -- am I right it's expected to come on Q2 '14? And once it comes online, it should immediately drive incremental EBITDA for -- once it comes online at that time?

Bruce R. Shaw

Well, the terminal enhancements themselves have a small surcharge that would be related to throughput at the terminal. But the real upside for the UNEV pipeline and the terminal, besides seasonal winter surges that we can see in volume just because of the way demand works in the Salt Lake City market, really isn't expected until the expansions, the refinery expansions, are complete at the end of 2014 or early 2015.

Operator

Your next question comes from Theresa Chen of Barclays Capital.

Theresa Chen - Barclays Capital, Research Division

Just for the potential pipeline projects from Cushing to the Tulsa Refinery and also the Cheyenne to Denver project, have you given any ballpark estimate of costs or EBITDA contribution that they would bring? And what are the next steps from here?

Bruce R. Shaw

No. We've not given any capital costs or EBITDA estimates, mainly because we're still waiting to decide whether these projects are viable projects. So we want to, at first, make sure we emphasize they are still just under evaluation and not get anything baked into the future for HEP on these projects. But we'll update you on those as we have further information. I would say though that if they were to come to fruition, we certainly don't have no expectation that the ratio of capital expenditures to income that would be generated by those projects would fall outside of the normal range for HEP.

Theresa Chen - Barclays Capital, Research Division

Okay. Great. And also on UNEV, once the refinery expansion is completed, what kind of changes in volume do you anticipate?

Bruce R. Shaw

Well, consistent with -- since UNEV has been constructed and comments we've made, historically, right now, between HFC and Sinclair and their commitments, their minimum commitment is on UNEV for about 23,000 barrels a day. And all we can say about potential future shipments is that if you look at the expansion volume, in the refinery expansion in Salt Lake City, they're going to total 15,000 to 20,000 barrels a day between the project that HFC is working on at Woods Cross. And as we understand the project at Tesoro, there's no guarantee that all those volumes will fall in UNEV, but that gives you a potential increase range there of -- from current volumes to what those expansions could add.

Operator

[Operator Instructions] Your next question comes from Steve Sherowski of Goldman Sachs.

Steven C. Sherowski - Goldman Sachs Group Inc., Research Division

For your rail project to go through, where do you think crude spreads have to be? And what crude spreads are you looking at, is it primarily WTI, ANS?

Bruce R. Shaw

Well, let me answer the second question first. The real question on that project, driven by the ANS comment there is, can you lay crude in the California refiners would be hungry for at a cost that's competitive, obviously, with their current menu. So it wouldn't just be ANS, but that's one of the markers they use out there. And I think we're hesitant to give a direct number for what would make the project work. As you might imagine, part of the, looking at the viability and the economics of the project is making sure all the pieces fit together for a good project. One of those piece being the transportation cost, rail transportation cost to the West Coast. So I think, Doug or Matt, unless you had other comments on that, we'd probably want to hang on to that until we have more to say on a project, overall.

Steven C. Sherowski - Goldman Sachs Group Inc., Research Division

No. No. Understood. I guess, do you see your primary competitor being Bakken production for this project?

Bruce R. Shaw

As far as primary competitor, if something else laid in besides what's already out there?

Steven C. Sherowski - Goldman Sachs Group Inc., Research Division

Yes, yes.

Bruce R. Shaw

Bakken is certainly one of the competitive crudes. I think that Bakken rail and certainly some folks have announced and are moving Bakken at least to the Pacific Northwest.

Matthew P. Clifton

Bruce, the only thing -- this is Matt. The only thing I'd add is that, I think, clearly, if we were just looking at moving WTI to the West Coast, Bakken would be our competition. But the location in New Mexico that we are looking at exploring would provide access to WTI, WTS and Western Canadian select. So you'd have some flexibility to make a cocktail of an ANS-type look-alike and then rail it out.

Steven C. Sherowski - Goldman Sachs Group Inc., Research Division

Got you. Okay, that's helpful. And a quick housekeeping question. For your distributable cash flow, are there non-cash adjustments of $1 million, what was that? I mean, if you don't know offhand, I can Follow up with you later off-line.

Douglas S. Aron

No problem. We're just opening up our notes here, hang on a moment. We'll come back to you off-line, if that's all right? I'm not sure what...

Steven C. Sherowski - Goldman Sachs Group Inc., Research Division

Yes, absolutely.

Bruce R. Shaw

Where are you referencing that reference that -- the non-cash items?

Steven C. Sherowski - Goldman Sachs Group Inc., Research Division

It's in the press release, the second to last item.

Bruce R. Shaw

The majority of that -- looking at the notes real quick here, the majority that, as you know, we've got an income statement item. And part of the income statement item that subtracts from net income and also -- well, at least from net income, it's going to be the reflection of the GP giveback that's building up a potential profit-sharing around the UNEV project. So that is shown as a subtraction of net income. That's going to be the majority of that add back. There are some negatives, obviously, that add in there too. But that's the majority of that add back there on other non-cash adjustments.

Steven C. Sherowski - Goldman Sachs Group Inc., Research Division

Okay. Got it. And a quick question on the winter ARB. What months do those typically open up?

Bruce R. Shaw

Typical month -- you'll see it start opening in November and close in by late February, early March. It could have kind of a 4 to sometimes 5 months span.

Operator

[Operator Instructions] Your next question comes from Jeff Birnbaum of UBS.

Jeffrey Birnbaum - UBS Investment Bank, Research Division

Just quick question. I know at the first quarter call, Bruce, you'd commented that after all the maintenance work, the turnaround work in the first quarter that volumes on the pipes were at pre-maintenance levels. And so I was just curious if you could comment -- the volumes look pretty solid for the quarter, how they kind of progressed through the quarter and perhaps what the outlook was for the back half of the year?

Bruce R. Shaw

Sure. So the -- most of those -- the turnaround work was really completed by the end of March. So very little bit of volume ramp was seen over the quarter since the volume really kind of started strong in the beginning of April. So really, consistently good volumes throughout the quarter. And as far as the rest of the year outlook, the volumes that we're seeing now, we'd expect to continue to see. So no real change. That first quarter was the anomaly. The rest of the year ought to be pretty consistent barring any surprises.

Matthew P. Clifton

I think, Bruce, just to add. I think, in the second quarter, I think Alon maybe had a little bit of downtime that hit the volumes a little bit during the quarter, and they're back up. So if they can keep the plant up, we'd expect that to be a little higher on the third-party volumes.

Jeffrey Birnbaum - UBS Investment Bank, Research Division

Okay. Great. That's helpful. And then one more quick housekeeping item. You mentioned earlier, Doug, I think the reimbursable expenses in the second quarter were $800,000. Is that what you said?

Bruce R. Shaw

Yes. That's right.

Operator

At this time, there are no further questions. I would now like to turn the floor back over to Julia Heidenreich for any closing remark.

Julia Heidenreich

Thank you, all, for joining us on today's call. If you have any follow-up questions, we'll be in the office this afternoon. Otherwise, we look forward to sharing our third quarter earnings call in early November.

Operator

Thank you. This concludes your conference. You may now disconnect.

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