Par Pacific Holdings, Inc. (PARR) Q1 2019 Earnings Report, Transcript and Summary

Greetings and welcome to Par Pacific Holdings First Quarter Earnings Conference Call. [Operator Instructions] And as a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Matt Vaughn, General Counsel. Thank you. Please go ahead.

Thank you, operator. Good afternoon, everyone and welcome to Par Pacific Holdings first quarter 2019 earnings conference call. Joining me today are William Pate, President and Chief Executive Officer; Will Monteleone, Chief Financial Officer; and Joseph Israel, President and Chief Executive Officer of Par Petroleum. Before we begin, please note that some of our comments today may include forward-looking statements as that term is defined under federal securities laws. Such statements include, but are not limited to, those concerning plans, expectations, estimates and our outlook for the company. Any forward-looking statements are subject to change and are not guarantees of future performance or events. They are subject to risks and uncertainties and actual results may differ materially from what is indicated in these forward-looking statements. Because of this, investors should not place undue reliance on forward-looking statements and we disclaim any intention or obligation to update or revise any forward-looking statement. I refer you to the latest Forms 10-K and 10-Q of Par Pacific Holdings filed with the SEC for a more detailed discussion of the major risk factors affecting our businesses. Further information regarding these as well as supplemental financial and operating information, including reconciliations of certain non-GAAP financial measures to the most comparable GAAP figures can be found on our press release and our investor presentation on our website, www.parpacific.com or in our filings with the SEC. I will now turn the call over to our President and Chief Executive Officer, Bill Pate.

Thank you, Matt. We are very pleased to report adjusted EBITDA of $47.6 million and adjusted earnings per share or $0.13 in the quarter, reflecting the favorable contribution of our recent acquisitions. We achieved these strong results due to outstanding performance from all of our business units despite very challenging product cracks during the first two months of the year. The inherent balance of our expanded operating base was apparent during this quarter, a period in which medium sours like ANS traded at premiums to Brent and heavies traded above WTI on the Gulf Coast. With our two mainland refineries benefiting from advantaged inland crude oil access, we were able to achieve significant profitability in this difficult crude dynamic. Refining adjusted EBITDA nearly doubled over the first quarter of last year after adjusting for the prior year $13 million RINS benefit. Our team operated these refineries through a difficult winter season safely and with excellent operational availability. Our Wyoming refinery team was dealing with a foot of snowfall as late as last week. We had no major unplanned outages at our four locations. System-wide throughput increased from 92,700 to 162,300 barrels per day, an increase of 75%. Sales were strong as well. In Hawaii, we realized record on-island sales. The IES acquisition helped us meet increasing jet fuel demand in Hawaii. We expect jet fuel consumption to increase significantly this year with continued growth from commercial airlines in the Hawaii market. We also reached an agreement with the largest Hawaii utility to supply fuels to meet their needs. That contract was approved by the Hawaii Public Utilities Commission in April and became effective this month. We would not be able to supply these fuels and meet the growth of our contracted supply without the acquisition of the IES crude unit. Turning to the mainland, we are also pleased with the early contributions of our Washington acquisition. Our Tacoma refinery performed extremely well through the low-demand winter season despite weak gasoline cracks as well as WCS crude differentials that reached historic lows after the Alberta production curtailments. Asphalt and VGO sales provided a healthy contribution to the bottom line as those markets were relatively strong in the off season. Overall, our refining business segment is well positioned to benefit from an improving price environment. Increasing product cracks in April and May bode well for the second quarter, and the forward curve reinforces our confidence for the remainder of the year as the impact of IMO 2020 should have a positive benefit on distillate and LSFO cracks. The Washington acquisition also benefited our Logistics segment with most of the year-over-year growth in Logistics profitability related to that addition. In Retail, same-store sales were up 1.9% in the quarter reflecting the strength of our brands and efforts to drive more traffic to our locations. Retail adjusted EBITDA improved by over 60% year-over-year due to strong performance in Hawaii and a full quarter contribution from our eastern Washington Retail system. The synergies and contributions of our recent acquisitions continue to be in line with our expectations. We’ve already begun to realize commercial synergy opportunities and expect to further develop these opportunities in the coming months. Internally, we are making good progress on our Hawaii DHT, Washington renewable logistics, and Wyoming tank projects. All capital projects are proceeding on time and in accordance with the CapEx guideline that we previously provided. The Wyoming tank project is online now, the DHT should be contributing to the bottom line early in the third quarter and the Washington Logistics project should be fully operational by the end of the third quarter. In summary, I am optimistic that we will continue to generate strong cash flow for the remainder of 2019, which will enable us to repay debt, lower our cost of capital and increase our free cash flow per share. At this time, I will turn the call over to Joseph to further review our operations.

Thank you, Bill. In Hawaii, we operated both locations in the first quarter, and as a result, we set several financial and operational records. Refinery throughput was 113,000 barrels per day, consistent with our guidance. First quarter Singapore 4-1-2-1 was $6.88 per barrel on Brent basis. The elevated global waterborne crude differentials and the weak gasoline crack spreads were partially offset by a relatively strong distillate and fuel oil margin environment. Our realized adjusted gross margin in Hawaii was $3.74 per barrel in the quarter. As anticipated, the combination of our refinery configuration with the recently acquired crude topping location resulted in a lower margin yield profile on a per barrel basis. The lower cost structure and the higher throughput support the bottom line profitability. Production costs were favorable at $2.81 per barrel. Going forward, we are expecting cost structure in Hawaii to remain favorable due to the improved efficiency and economy of scale, but probably closer to $3 per barrel at the low end of our previously disclosed target. Our combined refinery yield matches very well with the demand profile in Hawaii and allows us to focus on the local supply needs with minimum exports. So far in the second quarter, Singapore gasoline crack spread has improved due to global supply interruptions and decent demand trends early in the driving season. On the other hand, as anticipated, the 3.5% sulfur fuel oil crack spread is trending down this quarter, potentially as an early indication of the IMO transition. As a reminder, approximately two-thirds of our produced fuel oil production is under 0.5% sulfur. The diesel hydrotreater project is progressing well, on time and on budget, with anticipated start up early in the third quarter. The DHT unit will allow us to increase distillate production from 50,000 to 55,000 barrels per day. After adding the 20,000 barrels per day of low sulfur fuel oil production, we’re expecting 65% to 70% of our production to follow distillate pricing through the IMO transition. In the second quarter, we are planning to run 115,000 to 118,000 barrels per day in Hawaii. And quarter-to-date, the 4-1-2-1 Singapore Crack Spread index has averaged approximately $6.70 per barrel. In Washington, our 5-2-2-1 index on ANS basis averaged $11.09 per barrel in the first quarter. Bakken crude oil, reflecting approximately two-thirds of our Tacoma crude slate traded at $0.06 per barrel discount to WTI, and WCS reflecting approximately one-third of our crude slate traded at $10.64 per barrel discount to WTI, both on FOB basis. Crude by rail was challenged by extreme weather conditions late in the quarter. As a result, refinery throughput was 37,200 barrels per day, slightly under our guidance range. Significant planned and unplanned refineries outages in the West Coast supported approximately $18 per barrel improvement in Pacific Northwest gasoline crack spreads between January and March. In the first quarter, adjusted gross margin was $8.88 per barrel. The high capture in Washington was driven by the unusual strength of VGO over gasoline. Production costs were $4.87 per barrel. So far in the second quarter, PADD 5 refining utilization rates have been under 85%. Our 5-2-2-1 index has averaged $20.20 per barrel on ANS basis. WCS and Bakken crude differentials have averaged $9.60 and $1.20 per barrel, respectively, under WTI. Our target throughput for the second quarter in Washington is 39,000 to 42,000 barrels per day. In Wyoming, our 3-2-1 index was $15.09 per barrel in the first quarter, driven by seasonal weak gasoline. Our refinery throughput averaged 16,000 barrels per day. We successfully executed our planned reformer catalyst regeneration on time and on budget. Estimated turnaround impact was approximately $1.3 million of missed opportunities and $300,000 in production cost. In April, we finished the construction of two large products tanks in Wyoming, which in addition to our rail strategy will provide greater flexibility to manage seasonal demand volatility. Our realized adjusted gross margin in the quarter was $14.55 per barrel. The relatively high capture was driven by favorable crude differentials and 100% operational availability during the very cold first quarter in the Rocky Mountains, kudos to our operations team in Newcastle, Wyoming. Production costs were $7.69 per barrel, including the turnaround impact. So far in second quarter, our Wyoming 3-2-1 Index is averaged approximately $27 per barrel, reflecting an improved gasoline margin environment. We continue to access and benefit from discounted pipeline and local crude oil production in the Powder River Basin. Our second quarter target throughput in Wyoming is approximately 18,000 barrels per day. And now, I will turn the call over to Will to review consolidated results and Laramie highlights.

Thank you, Joseph. Focusing on accounting items first, the largest item was the FIFO benefit of approximately $5 million for the first quarter within our Wyoming Refining results, as prices rose during the quarter. The Washington acquisition closed on January 11 and our results reflect a partial quarter contribution. Consistent with our approach at our other assets, Washington results are split between our Refinery and Logistics segments after establishing arms-length transfer pricing. Our Washington operations are presented on a LIFO basis, consistent with their historical presentation. There are a couple of other items worth calling out in our GAAP results. One, based upon preliminary purchase price accounting allocations, we recognized a benefit of $65 million related to releasing a portion of our income tax valuation allowance, tied to our acquisition of U.S. Oil & Refining. Two, there were approximately $5 million of debt extinguishment expenses for the first quarter related to closing and funding of the financings to facilitate the U.S. Oil & Refining acquisition. Our segment level results reflect strong contributions from each area, while we were able to continue to hold our aggregate G&A spend relatively flat year-over-year despite the growth in our underlying asset base. Total business segment adjusted EBITDA, excluding corporate expense was $59 million, an increase of roughly $35 million when excluding the 2018 RINs benefit. Refining segment contribution was $30 million, an increase of $24 million when removing the $13 million RINs benefit from Q1 of ‘18. Our Logistics segment posted a record $16.3 million of adjusted EBITDA during the quarter, reflecting a good proxy for our going forward quarterly run-rate, assuming steady operations at each facility. Our Retail segment was also a solid contributor with a segment contribution of $12 million, up nearly $5 million versus Q1 of 2018. In total, our Retail and Logistics segments made up 49% of segment adjusted EBITDA contribution, reflecting an attractive balance within our segments. In addition, corporate expense only increased by $500,000 compared to Q1 2018 demonstrating the inherent operating leverage in our combined system. Moving to the consolidated financing position, net debt to capitalization was 52% and total liquidity was $126 million compared to 40% and $139 million at the end of the fourth quarter. First quarter GAAP interest expense totaled $19 million, of which $16 million was cash interest. DD&A totaled $21 million. Cash from operations adjusted for borrowings underneath the J. Aron deferred facility totaled approximately $3 million during the quarter, which included a working capital investment of approximately $29 million. The majority of this working capital investment reversed in April. Capital expenditures totaled $18 million during the first quarter. Planned 2019 total capital expenditures and turnaround outlays remain consistent with previously communicated ranges between $100 million and $110 million. Moving to Laramie, during the first quarter Laramie generated approximately $20 million of adjusted EBITDAX and a net loss of $6 million excluding the impact of $3 million of unrealized gains on derivatives. Laramie’s LTM adjusted EBITDAX stands at $101 million. This concludes our prepared remarks. Operator, I will turn it back to you for Q&A.

Thank you. [Operator Instructions] Our first questions are from the line of Neil Mehta with Goldman Sachs.

Hey guys. Congrats on a good quarter here in the recent consolidation. My first question is just on the Northwest, obviously refining margins are exceptional here on the West Coast in the second quarter, are you guys running well, are you able to capture that margin uplift here in the quarter?

Yes, we are.

Alright. Well, that’s great. And then there is a follow-up question just on Hawaii here, OpEx came in a little bit lower than our expectations and just wondering what’s driving that and I am sure we carry it forward. And then the big picture question on Hawaii is, how do you think about this market over the next 3 years, let’s say a little bit of a longer term time period as supply gets rationalized, demand continues to grow, could this market flip from an import market to an export market?

I will start with the OpEx question. As I mentioned in the prepared remarks, we think the longer term cost structure is closer to $3 per barrel, which is lower than our historical cost, as we picked up some economy of scale and getting more efficient. Due to the acquisition, we had some timing components that gave us $2.81 this quarter, so we are looking at $3 going forward. And with regards to the market, I will let Will answer that.

So Neil, I think the best way to think about that is if you assume that the available margin for us on the Singapore 4-1-2-1 Index is, let’s say on average about $7. And we would typically think that our ability to capture that we would see about a $2 discount, which would give us really an adjusted gross margin available of about $5. And then as we have indicated, we believe the $3 of OpEx is the best way to think about the pro forma business, which would leave us about $2 a barrel of adjusted EBITDA. And again, all of that’s before growth, so before the distillate hydrotreater project and before the naphtha hydrotreater and Isom project. So that $2 a barrel kind of is the baseline off of our 40 million barrels of annual production, kind of gives you a sense of the starting point. And then the distillate hydrotreater project that should come online this year, which we have indicated is north of a 30% rate of return from our perspective than in the naphtha hydrotreater project, which is further out. I think each of those projects, it’s going to add additional margin for us. And then the market shifts I think will continue to happen over the next 1 year to 3 years. So I think that’s the best way to think about it.

I appreciate it. Thanks.

Our next questions are from the line of Matthew Blair with Tudor, Pickering, Holt.

Hey, good morning Bill, Will and Joseph, how are you?

Hey Matt.

Good morning Matt.

I was hoping you could share any thoughts or outlook on Bakken crude differentials going forward, we actually saw pretty strong growth in the Bakken last year and there has been announcements of a couple of pipeline expansions or potential new pipes, but it doesn’t seem like they come on for at least a couple of years, it’s a basin that’s already on rail, as it’s marginal take away, do you see a potential for Bakken diffs to widen out here in 2019 and 2020?

We will start – we think the take away capacity continues to be our biggest opportunity going forward on both Bakken and WCS or Canadian crude in general. And we are very excited about the potential outlook into that.

I think Matt you can look at the trend in the second quarter to-date, where you have seen the Bakken differentials a clear book for periods of time touched the $2 range. And then I think if you look closer to the field and you look at injections onto the DAPL pipe, you are at points in time getting that $4 discounts to WTI. So I think that’s a signal that as we come out of winter-fall, that production is looking for incremental home.

Terrific. And it seems like there were a few I guess political events that have the potential to impact you going forward, could you walk through the Washington crude by rail bill and then the Colorado local control bill and talk about whether you are expecting any impacts on your operations in those areas?

Let me – this is Bill I will start with the crude by rail and Will take the Colorado bill. Look the short answer is, I don’t think either of them will have certainly a substantial near – any near-term impact. The Washington crude by rail bill, as you know has been – is likely to be challenged by the state of North Dakota given the potential implications that it has with respect to the commerce clause. That bill as you know really revolves around vapor pressure and Bakken crude moving to Washington, which we do move a fair amount of crude. But they are – the way the bill is structured, it’s really only triggered to the extent that your intake increased substantially over 2018. And even then it will only be triggered in that, in 2021. And we think we have plenty of other options, should that come to pass. But I think it’s – there is going to be a lot of legal challenges to this before there is any impact on our operations. Will, you want to cover the Colorado bill.

And then with respect to Colorado and again I think there is more debate on the exact form of implementation. But I think from our perspective, our – the Laramie operations are in Western Colorado and then in principally in three counties in Mesa, Rio Blanco and Garfield counties. And each of those are in more rural areas and have historically been supportive of oil and gas development, when you have gone back and looked at the way in which those counties have tended to vote.

It sounds good. I am going to re-queue for a couple of more questions. Thanks.

Thanks Matt.

Our next questions are from the line of Mike Harrison with Seaport Global.

Alright. Good afternoon.

Hey guys.

Hi Mike.

I was wondering if you can talk a little bit about how your crude slate or your crude requirements are changing in Hawaii, looking both kind of in Q1 as you compare it to last year and then as you think about the rest of this year, any changes in kind of sourcing dynamics that you wanted to call out and could those end up being positives for the gross margin in Hawaii?

Yes. The new crude slate or the preferred crude slate now having both locations operating is slightly different to make the different production yields that match the demand profile in Hawaii. So, you will see us running more and more sweet and lighter crude. We’re probably shifting from 31, 32 API average toward the 34, 35. And our sulfur in average is probably down from 0.6% to slightly under 0.5%, not a big change. But bottom-line, we need to make this additional LSFO for the state of Hawaii needs and the crude will change accordingly. We still have the flexibility in certain market conditions to move around and to optimize crude sourcing and production yield accordingly.

Alright. Thank you for that. And then also I was just wondering on the DHT project, great to hear that it’s still on time and on budget. But just wondering on the timing and just kind of how we see that contributions flow through. Is it going to be the case that we’ll actually see throughput for the Hawaii assets increase in Q3 or is it initially going to be more of a shift toward distillates that we see first?

Frankly, with the expanded operations at our unit, I think that you’re not going to see a material change in throughput. What you’ll see when the unit comes online is an increase of our jet production, which we’re actually a fairly substantial jet importer today. And so it will allow us to back out some of our jet imports and manufacture jet barrels in the state.

Alright, thanks very much.

Our next questions are from the line of Jason Gabelman with Cowen.

Yes, thanks. I just wanted to follow-up on Neil’s question about kind of thinking about the Hawaii market long-term and ask it, I guess, in a different way. When you think about gasoline prices on the island relative to the Singapore benchmarks, I mean, are they pricing at kind of similar levels and what Singapore prices at a premium to that or at a discount? And then how do you see that evolving over the next few years? And I have a follow-up. Thanks.

Since both Joseph and Will got a cut at this, I’ll take my cut at it. My – Jason, I want to be careful about comments about any of our contracts, because there’s a lot of proprietary information that we want to be careful about sharing. But needless to say, with the change in the production in the state, most of the products today require some level of importing. And that importing sets up a dynamic, where we’re competing against importers and they’re going to be aggressive importers in the state. And so when I think about pricing – the pricing dynamic in general if we’re competing against importers, we have to be competitive with the Singapore market taking into account the logistics of moving that product to the state. And given our low-cost structure, the new unit we have in place, the balance in our system, I’m sure we’ll be a very competitive refiner.

Great. Thanks a lot. And just on the working capital, I want to make sure I heard that correctly. Did you say there was a $200 million build and most of that reversed? Did I hear that correctly, and if not, can you just clarify those numbers and kind of what that was related to? Thanks.

Sure, Jason, yes, it’s a $29 million build.

Okay, go ahead.

And again – that’s first, and again, that’s principally associated with the additional working capital tied to our increased activities in Hawaii post the IES acquisition. And then some timing at the end of the quarter within our Washington segment. So that – those are the 2 principal drivers.

Alright, great. If I could just sneak in another quick one, sorry. Is the DHT – is that just strictly for diesel or will you able – are you able to treat like resid or anything heavier or is it only diesel? Thanks.

It’s only distillate. So –

Okay, yes, just –

Meaning jet fuel and ULSD just to clarify.

Got it. Thanks a lot.

Thank you.

Our next questions are from the line of Tim Rezvan with Oppenheimer.

Hi, good morning, folks. Looking at the data you presented last night, I saw export sales in Hawaii were down about 5% of refined product sales. How do you think about optimizing that number going forward? Is the goal to export 0 or do you plan to be tactical if market opportunities open up? Just trying to understand how that could trend going forward?

Probably 0 is not a realistic assumption, but it is trending down and we will try to export minimum possible. I think 5% and under is a good assumption going forward, because we’re fortunate to have this perfect match between the combined refinery configuration and the demand profile in Hawaii.

Okay, okay, thanks for that. And then moving to Wyoming, you mentioned in prepared comments, tank construction in Wyoming finished in April. Can you talk about what kind of material changes that, that makes on either the run rates in the refinery? Does that mean first quarter and fourth quarter kind of run rates go higher or kind of how does that change what you’re doing there now that the tanks are there?

Yes. Wyoming is a seasonal business. It’s easy to move the barrels in the summer for good netback. It’s much more challenging to do so in the winter. And this is where you need commercial flexibility. In the past, we demonstrated rail activity that took it to other markets that are less limited in the winter, and now we have additional 100,000 barrels of product storage to park and to time our sales. This will result in a higher throughput in the off season.

You said higher throughput in the off season?

Yes.

Okay, okay, that’s all I had. Thank you.

Our next questions are from the line of Andrew Shapiro with Lawndale Capital.

Hi, thank you. I have a few, I’ll back out and hopefully give a shot at the other ones here. On the last call you discussed being able to sell over 100,000 barrels per day on-island. And is the 107,000 barrels per day the upper bound of what can be sold on-island or are there any initiatives you can enact to increase that even more going forward?

Andrew, it’s Bill. I think that – I don’t know if I characterized it as an upper bound, but it’s a pretty healthy number just given the market demand. I don’t think it would change materially. There certainly could be periods in time, we do have some bulk transactions even within the state that could boost the daily sales average in a quarter here or there. But it’s probably a pretty – it’s probably a good indicator of where we expect to be going forward.

Okay. And then how much net debt at Laramie? Is there any publicly referenceable value for Laramie as well just trying to get a feel for this now meaningful enterprise?

Sure. So, Andrew, the net debt balance at the end of the quarter was roughly $190 million. And the – there’s also a preferred stock that’s senior to our common position that’s roughly $44 million. So – and that’ll be included in our investor presentation.

Okay. And I didn’t – I don’t recall, did you mention are they on a 1-rig program or what are the – what’s the rig program for the current year?

They’re continuing a 1-rig program.

Okay, great. I have a few more back out in the queue, but hopefully, you can back to us.

Great.

Thank you. [Operator Instructions] Our next questions are from the line of Matthew Blair with Tudor, Pickering, Holt.

Hey, thanks for taking my follow-ups here. I guess just on the balance sheet, I think net debt to cap is in that 50% ballpark. Just wanted to see if that was a level you’re still comfortable with, and if so, do you have any targets you might be able to share on debt reduction either in 2019 or 2020?

Sure, Matt, it’s Will. I think we’re comfortable at the 50% level, but I think our targets may – remain consistent. We’d like to see our net debt to cap in that 30% to 35% range. And again, I think our principal allocation of excess free cash flow is to delever during the foreseeable future. So, we’d like to work towards that balance as quickly as possible.

Okay. And then can you share any outlook on Laramie for Q2? It seems like NGL prices have declined further compared to Q1 and Opal natural gas prices are also down quite a bit, but I know you have quite a few hedges too. So, I guess any early thoughts on how Laramie is trending in Q2 versus Q1?

Well, I think from a production standpoint it’s probably relatively consistent with Q1 with slight growth. And then I think on the pricing standpoint, again, I think just seeing lower prices for natural gas and natural gas liquids. That being said, I think we had some realized hedge losses at Laramie during Q1 that are unlikely to repeat in Q2. So –

Sounds good. And then lastly, I think, Bill, you mentioned that agreement with the Hawaii Public Utilities Commission, would that have any impact on your gross margins at Hawaii going forward either positive or negative?

Well, sure, it certainly will have an impact because they are now our largest customer. The margins going forward are probably pretty consistent with the first quarter though in terms of impact, because the contract with HECO, the local utilities is similar in many ways with the contract that we formerly had with the seller of the asset, IES. So, there’ll be some change, but I don’t expect it to be material in the near-term.

Thank you. Thanks.

Put it this way, due to the quality and the lower sulfur content, they will follow more of the distillate pricing than the fuel oil.

Sounds good.

Right, thank you. And our next questions are from the line of Andrew Shapiro with Lawndale Capital.

Hi, thank you for the follow-up opportunities. So, what do you see as any further consolidation or integration timelines for the IES and Washington acquisitions or is the digestion completed and if it is and you’re now more balanced, is there any particular areas of the energy space you view more attractive than others for further acquisitions?

Andrew, we usually don’t comment on M&A, but just in terms of the integration efforts with respect to IES, we still have some capital work that is taking place that will allow us to fully integrate the 2 sites and allow us to move crude and other products back and forth between the locations, that’s ongoing. We expect to have that concluded before the end of the summer. In addition to that in Washington, we still have a fair amount of integration work. We really recognize that we’ve owned it for just a quarter. The business is doing extremely well, but integration on that will probably take at least the remainder of the year.

Okay. And then I saw recent announcement just basically next week of an upcoming conference. Looking a little bit further out, where one could maybe make travel plans et cetera. What are your upcoming non-deal roadshows or investor presentations that you have on the calendar?

Andrew, it’s Will. We’ve got the Tudor, Pickering Conference next week in Houston, June 4th and 5th, we’ve got the RBC Energy Conference, we’re planning to attend in New York, and then the 5th and the 6th Bank of America Energy Credit Conference in New York.

Okay, great. Thank you.

Thank you. This concludes our question-and-answer session. I’d like to turn the floor back over to management for closing comments.

Thank you, Brenda. Thank you for joining us this afternoon. We’re pleased to see the contribution from our recent acquisitions in this first quarter. As we enter the summer driving season, we also look forward to the strong profitability and continued achievement of our organic growth objective with our newly expanded asset base. We’re confident that this new base will create significant long-term value for our shareholders. Have a good day.

Ladies and gentlemen, thank you for your participation. This does conclude today’s teleconference. You may disconnect your lines, and have a wonderful day.