NuStar Energy LP (NS) 2017 Q2 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Q2 2017 NuStar Energy L.P. and NuStar GP Holdings, LLC Earnings Conference Call. (Operator Instructions) As a reminder, this call is being recorded.

I would now like to turn the call over to Chris Russell. You may begin.

Thanks, Michelle. Good morning, everybody, and welcome to today's call. On the call this morning are Brad Barron, NuStar Energy L.P. and NuStar GP Holdings, LLC's President and CEO; and Tom Shoaf, Executive Vice President and CFO, along with other members of our management team.

Before we get started this morning, we'd like to remind you that during the course of this call, NuStar management will make statements about our current views concerning the future performance of NuStar that are forward-looking statements. These statements are subject to the various risks, uncertainties and assumptions described in our filings with the Securities and Exchange Commission. Actual results may differ materially from those described in the forward-looking statements.

During the course of this call, we will also make references to certain non-GAAP financial measures. These non-GAAP financial measures should not be considered as alternatives to GAAP measures. Reconciliations of certain of these non-GAAP financial measures to U.S. GAAP may be found in our earnings press release with additional reconciliations located on the Financials page of the Investors sections of our websites at nustarenergy.com and nustargpholdings.com.

Now I'm going to turn the call over to Brad.

Good morning. Thanks for joining us today. If you've been following NuStar for the last several months, you know that we had one of the busiest quarters in our history. Before I turn the call over to Tom to discuss this quarter's results, I would like to briefly review some of our accomplishments during the second quarter as well as provide a few updates on our Permian Crude System. On May 4, we closed on the purchase of Navigator Energy Services, LLC, which we now call our Permian Crude System for approximately $1.5 billion. With this acquisition, we now own the leading crude oil gathering, transportation and storage system in the Core of the Core of the Midland Basin. To finance this acquisition, we closed on multiple transactions during April. On April 18, we issued 14.4 million common units with gross proceeds of approximately $665 million. On April 28, we raised $550 million by issuing 5.625% 10-year senior notes and we also issued $15.4 million Series B perpetual preferred units for gross proceeds of $385 million. Our general partner, NuStar GP Holdings, LLC, also demonstrated its strong support for the transaction by agreeing to temporarily forgo the incentive distribution rights or IDRs, to which it would otherwise be entitled for any NuStar Energy LP common equity that we issue from the date we signed the acquisition agreement through the 10 quarters thereafter, which begins with the distribution for the second quarter of 2017. The waiver is capped at $22 million.

In terms of performance of the system since the deal was announced in early April, so far our Permian Crude System has far exceeded our initial drilling projections. In terms of rig counts, there are currently 39 rigs running on dedicated and interconnected acreage. This compares to 29 we forecasted would be running at the end of 2017. In fact, back in April, when we were evaluating the system, we weren't projecting 39 rigs until the end of 2018. Throughputs on the system have grown substantially from around 115,000 barrels a day in April, when we announced the acquisition, to an average of around 150,000 barrels per day in July, that's about 30% growth in 3 months. Our throughputs are growing at an impressive pace. They are ramping up a bit slower than we would expect based on the significant amount of rigs being added on the system. We believe this slower-than-expected ramp up is due to slow well completion rates. Even though many producers have dedicated frac crews, the lack of additional crews has caused an increase in drilled but uncompleted wells or DUCs. With that being said, based on our conversations with our customers and due to the amount of drilling currently taking place, we expect our throughput volumes on our Permian Crude System to continue to ramp up significantly in the back half of this year.

Due to this anticipated significant increase in volumes, we have accelerated several system expansion projects on our Permian Crude System. We currently plan to invest around $123 million in strategic capital in 2017 on these West Texas expansion projects. In addition, we continue to look at potential bolt-on acquisitions to our Permian Crude System, as well as continue to pursue the possibility of developing a larger takeaway capacity project, including a solution that would link our Permian Crude System all the way to our docks in Corpus Christi, Texas.

With regard to dedicated acreage for our Permian Crude System, dedicated acreage has grown from about 500,000 acres at the time of acquisition to about 514,000 acres today. We are working with several producers on additional dedications that we expect to be completed in the near term. And remember, we have about 500,000 undedicated acres that are immediately adjacent to the system, as well as nearly 5 million acres of areas of mutual interest or AMI. Additionally, our ship-or-pay volume commitments have increased to 92,000 barrels per day, up from 74,000 barrels a day when we announced the deal.

Shifting away from our Permian activities for a moment. During the quarter, we began to set in motion an exit from the last of our commodity trading operations, with the shutdown of our heavy fuels and crude trading businesses. Changes in these markets largely due to the proliferation of shale plays have made it increasingly difficult to generate profit from within the fuels marketing segment in recent years. For example, the success we experienced in the early years of our fuels marketing operations was centered around cheap rail supply of heavy oil from inland refineries. That source of supply has been reduced significantly as lighter crude slates from the shale plays are now being run through those refineries, resulting in reduced production of fuel oil blending components.

Based on our analysis, a closure of these commodity trading operations will significantly lower top line revenue, but should be EBITDA neutral to NuStar. Furthermore, the decision is in line with what we've been doing in the past 3 years, derisking our business and focusing on our fee-based storage and pipeline operations. Going forward, the only operations remaining in our fuels marketing segment will be our bunkering operations at our Texas City and St. Eustatius terminal locations as well as our Butane blending operations on our Central East pipeline system. And lastly, as you may have seen recently reported in major news outlets, on June 29, we received approvals on 3 presidential permits to move LPGs and other refined products across the Mexico border. These permits relate to our pending pipeline project with Pemex to supply northern Mexico with refined products. Although the project is currently delayed as we await signed the contracts, receiving approval on these permits was not only a major milestone for the pending construction of this project, it was also a major milestone for the energy industry as a whole. And we are proud to be part of that story.

So you can see, this is the transformative and exciting time for NuStar. After covering our distribution for 3 full years, we made the strategic decision to exchange short-term coverage for long-term distribution growth and moving forward with the Permian Crude System acquisition in the Core of the Core of the Permian shale play. And as we said at that time, as a result of this strategic decision, we do not expect to cover our distribution until the back half of 2018. We also noted that the second quarter will be disproportionally impacted by the transaction costs associated with the acquisition. And, of course, you can't issue 14 million new units without negatively impacting earnings per unit.

And finally, we're further derisking our business by exiting our heavy fuels, crude oil trading operations, which as I said before will be EBITDA neutral. Of course, this will have the effect of lowering top line revenues, so that's an adjustment you're going to want to make to your models for quarter-over-quarter comparisons going forward. So we are on track with our forward-looking plans that are paving the way for strong future growth in our earnings, assets and distributions. And we're very pleased with the progress we've made to date. This progress would not be possible without the short-term impact we're experiencing in some of our 2017 earnings results.

To give you more color on all of these items and to provide you with some additional detail on our second quarter results and 2017 projections, I'm going to turn the call over to Tom Shoaf, NuStar's Executive Vice President and CFO. Tom?

Thanks, Brad, and good morning, everyone. As Brad noted, on our first quarter call, we stated that we expected that our overall 2017 results will be negatively impacted by the large amount of debt and equity raise and the transaction costs incurred in the second quarter related to the Navigator acquisition. As expected, we incurred approximately $14 million of transaction costs in conjunction with the acquisition that had a disproportionate impact on the second quarter results. Distributions and interest expense associated with the financings of the acquisition combined with a turnaround and unplanned operational issues at one of the refineries we serve were the primary causes for the quarterly results that we experience.

For the second quarter of 2017, we reported net income of $0.05 per unit, EBITDA of $141 million and DCF available to common limited partners of $60 million, which resulted in a distribution coverage ratio of 0.59x. As Brad noted earlier, you can't issue $14 million of new units without impacting EPU. And the short-term drop in distribution coverage is a necessary part of our long-term growth plan. However, it was further impacted by the turnaround and unplanned operational issues at one of the refineries which we serve. Second quarter 2017 EBITDA in our pipeline segment was $87 million, $1 million higher than the second quarter of 2016, mainly as a result of 2 months of benefit from the Permian Crude System acquisition which was partially offset by the impact of turnaround and operational issues at the customer refineries I spoke about earlier.

Second quarter 2017 EBITDA in our storage segment was $88 million, up $7 million compared to the second quarter of 2016, due mainly to higher renewal storage rates, increased fees at our St. Eustatius terminal and our recent Martin terminal acquisition. When the impact of converting the refinery storage agreement to a lease is excluded, our storage throughputs actually increased approximately 25,000 barrels per day or 3%, which is mainly attributable to the Martin acquisition. You may recall from the first quarter call, starting on January 1, our agreement to provide refinery storage at Corpus Christi, Texas and Benetia changed from a throughput arrangement to a lease, which means the associated revenue is now characterized as storage terminal revenue on our financial statements.

So while the second quarter storage throughput volumes were down 54% or 390,000 barrels per day compared to the second quarter of 2016, that decline reflects an apples-to-oranges comparison. I'd also like to note that this will continue to be a reconciling item for the remainder of the year, but one of the benefits of making this change is that we will minimize our cash flow risk by eliminating our exposure to future refinery turnarounds and cutbacks during the contract term. Our June 30 debt balance was $3.5 billion, while our debt-to-EBITDA ratio was 4.6x.

This morning, NuStar Energy announced a second quarter Series A preferred unit distribution of approximately $0.531 per unit, and its initial Series B preferred unit distribution of approximately $0.725 per unit. Both of which will be paid on September 15. In addition, NuStar Energy announced a second quarter common unit distribution of $1.095 per unit, which will be paid on August 11. NuStar GP Holdings also announced the second quarter distribution of $0.545 per unit, which will be paid on August 15.

Now let me spend a few minutes talking about our projections for 2017. Now we expect our 2017 total EBITDA to be $600 million to $650 million. This EBITDA estimate assumes $110 million to $120 million of general and administrative expenses in 2017 that are not allocated to our segment results. Our EBITDA guidance has been reduced to lower than expected Permian Crude System throughputs, reduced vessel activity at St. Eustatius and lower throughputs on some of our other pipelines due to refinery operating issues and extended turnarounds at some of our customer refineries. Our 2017 internal gross spending is now estimated to be in the range of $380 million to $420 million due to a reduction in spending on our northern Mexico supply project, partially offset by additional expansion projects on our Permian Crude System. We continue to expect 2017 reliability spending to be in the range of $35 million to $55 million.

And with that, I'll turn the call back over to Brad for any closing remarks.

Thank you, Tom. As you will recall, over the past 3 years, we made a conscious effort to improve our coverage while systematically derisking our business. We worked hard to optimize our operations and position the company for future growth. In our strategic plan, we targeted the Permian Basin as the fastest growing shale play in the U.S. as our preferred location for that growth. We could not be more thrilled that we were able to find and acquire the premier gathering system in the Permian to execute on this strategy. As we said at the time of the acquisition, the future growth potential of these premier assets in the Core of the Core of the Midland basin will be well worth sustaining a below 1x coverage ratio in the near term and that we expect it to recover as early as the back half of 2018.

In the meantime, we are committed to maintaining our distribution. Based on the projections we've seen from the Permian as a whole and the drilling activity on our dedicated acreage to date, I am more convinced than ever that this is the right platform for NuStar's future growth. This acquisition is the culmination of a transformative 3 years for NuStar. But it is also just the beginning of what I, along with the rest of the NuStar executive team and our Boards of Directors, believe will be a period of significant growth for the company. We expect the Permian Crude System to be the base upon which, in future years, we will grow our cash flows, strengthen our coverage and ultimately, increase our distribution to our unitholders.

With that, we will open up the call for Q&A.

(Operator Instructions) Our first question comes from Gabriel Moreen of Bank of America Merrill Lynch.

Brad, maybe you can talk a little bit about, I think you mentioned the DUC count building behind Navigator, sort of where it stands right now, may be relative to expectations? And then, I guess, the second part of my question is around the completion activity, by your estimates, is that a function more of price? Is that a function more of crew availability? And I guess the confidence in the back half of the year ramp and visibility on that completion activity?

All right. I can tell you the DUCs are higher than anybody ever expected them to be out there, much higher than we thought they would be. We looked into it extensively with our customers and with others. And initially, I thought there might be a price component to it but we are not hearing that from anybody. All we've heard is straight up lack of completion crews. And that's been pretty much across the board. I have seen and we've heard from some people that they're expecting to get more crews in the second half of the year. So we should expect to see that number start -- the DUC number start to come down, which would translate into increased volumes.

Got it. And then in terms of accelerating the CapEx on the system in the $123 million, can you just talk about the interplay between accelerating the CapEx now versus what you'd have expected to spend in the longer term on Navigator?

Yes, I mean, all the CapEx we're spending this year was part of the $260 million that we said that we needed to spend. As we went forward, there's a very small amount attributable to a new customer. But there's -- what we're seeing is some of the well pads are coming on, they're put in 8 to 10 wells. And so you want to avoid any pinch points in the system and have everything up and running so you can capture the first flows. And so we're making the strategic decision to complete some of the debottlenecking ahead of when it might -- when we might have ordinarily thought it would be needed.

And then on the long-haul pipeline, it sounds like there is discussion going on -- you know in terms of what you think is the most sort of important next steps there? Is it really trying to find -- are you looking for a JV partner? Can you discuss sort of shipper interest and getting those commitments and, I guess, any timeline you think in terms of maybe the substantive update on an open season or something like that.

Sure, Gabe. This is Danny Oliver. Yes, we are continuing to develop that. We're open to partnerships with someone that might make some sense and add some value. We think it's still probably one pipeline that's going to get built. So -- and it's a very competitive environment. There's, as you know, probably half a dozen or so projects being touted out there, but I think if you can get 2 of the right partners together that both have something to add other than capital, I think it can get you over the line. And that's -- we're still pursuing that. I think something is likely to get done certainly before the end of this year. I think we thought it likely would have already been done. But many of the customers I think took a bit of a pause and relaxed a little bit when prices came off and wanted to see how the market was going to react in general on the drilling side. But as Brad mentioned earlier, they're adding rigs more aggressively than we anticipated even before crude dipped for a little while under the low 40s.

Our next question comes from Jeremy Tonet of JPMorgan.

It's Andy for Jeremy. First question, wondering if you can quantify the turnaround impact in the quarter and are you done with planned turn around for the rest of the year?

I think turn the turnaround for the quarter was probably about $6 million, I think, for the quarter. And the second part of your question? We're not done for the rest of the year. We've actually been informed that there's some unplanned turnarounds that could hit in the back half of the year. And that's part of the reasons why on the guidance, we dropped the guidance on EBITDA down a little bit because of these unplanned turnarounds that our customers are hitting us with. So we expect to see more of that towards the back end of the year.

Great. And sticking to South Texas and the crude system, have you started talking with customers about recontracting some of those contract roles next year? And maybe what was the South Texas crude oil volumes for the quarter?

Andy, this is Danny again. We are starting to have some conversations with those customers that are -- we've got about 50% of our MVCs coming up for renewal in August of next year. We are starting to have some conversations with them, but in the conversations they're not really engaging yet. We've got a full year. They want to see how things end up. We're obviously still collecting on our MVCs. Our actual volumes are below those MVC levels as we continue to see customers opting to ship on the higher tariff MVCs as opposed to ours because there's a relatively low tariff going to Corpus versus Houston. But for at least the next year, it won't affect revenues. We're forecasting everything at the MVC level.

Great. And then final question, is there any opportunity created by some of the dislocations caused by Venezuela that you see in your business? Or you're kind of completely removed from that?

Not really, we've got -- we do some business with PDVSA and they continue to pay us, make payments on the business that we are doing. So it hasn't really affect -- we've seen some lower vessel calls and things out of Venezuela lately, but overall not really affecting that business.

Our next question comes from Ryan Levine of Citi.

Just wanted to -- if you would be able to speak a little bit more around bolt-on acquisitions that you highlighted in the prepared remarks. Is there any dollar amount associated with those -- kind of benchmark us towards.

No, I mean, it depends on what comes on to the market and what's available. So we're out there looking for those acquisitions, but I can't give you an idea of how much of those would go for.

And if they were to be substantial, how would you able to finance those opportunities?

Combination of debt equity and preferred like we've been doing. We've got -- it's kind of what we tell everybody. We're about 50-50 on smaller acquisitions and CapEx programs and whatnot. So we've got access to capital markets and plenty of room on our bank loans. I don't think it would be a problem.

Okay. And then regarding the second half '18 coverage target, what are the key commodity price assumptions and rig count assumptions that you have baked into that. And is there any assumed recontracting on the south Texas system?

Well, I mean, as far as the back half of '18, I mean, we pretty much have the same crude assumptions that we currently have. And I think we've been running anything north of $40, on up to about $50 or so. And so where -- basically where crude has been landing over the last several months and where it is now is kind of what we've assumed going forward for the most part. In terms of recontracting the South Texas, no, I mean, we still have small volumes assumed during that time. We don't expect any large significant ramp up in volumes in South Texas. So it's pretty much status quo on that.

Okay, and then in Q2 of this year, would you be able to provide the EBITDA contribution from the Navigator transaction realizing it's only a partial quarter contribution?

No, I don't think we're really disclosing that right now on the Navigator piece. I mean, it was just a lot of costs associated, transaction costs and all that were -- that hit the second quarter, so not really disclosing EBITDA.

Our next question comes from Shneur Gershuni of UBS.

Just a couple of quick questions and some follow-ups. I guess, just kind of following up to the last question about you're covering the distribution second half of 2018. Was that always your expectation? Is it higher or lower than where you were when you provided guidance, I guess, at MLPA for -- post Navigator?

Yes, it's in line with what we have said before. I mean, when we first did the acquisition and even at MPLA, we were saying that we expect -- of course, you have all the financing costs and everything that you incur upfront and that with the expected ramp up in volumes and expected ramp up in EBITDA associated with Navigator, that it would be towards the back half of 2018 before we would actually start seeing cover again. And so I think we've been saying that since we actually announced the acquisition.

Okay. So when I triangulate some of your prepared remarks about the rig count being significantly better than expected, shouldn't that expectation improve or is it a DUC issue. I was just wondering, like, how we should think about your positive commentary about rigs being well ahead of schedule?

Yes. I mean, I think it's a DUC issue, like we talked about earlier. In our expectations, those ducks are going to be capitalized upon by the producers more toward the end of this year.

Okay. So it's really more of a DUC completion crews issue getting in the way of having a better expectation.

Say that again? I think what we are trying to say, this -- as far as these rigs coming on and translating into volume, this is kind of a lumpy process for producers. And what we're saying is immediately, like we're talking right now, the present. Those DUC have been an issue in getting them from a DUC to a completed well. But we are expecting some of that alleviate towards the back end of the year as the year progresses and we do expect a pretty significant volume ramp coming from that throughout the year. But as we said, at least currently, the DUCs have been a slight issue.

This is a double-edged sword. You'll also get benefit from not only the completion of the built DUCs, but also you still have 39 rigs, which as Brad mentioned, we weren't expecting 39 rigs until the end of 2018. So as long as those stay engaged, we'll be ahead on drilled wells next year as well.

Right. Which is really where my question was that (inaudible) why wouldn't your expectation improve given that the rigs are so ahead of schedule?

It likely could. You like to see these wells getting completed in...

And I would say, we're a very conservative management team. We don't get way out over our skis and we want to have some more visibility into 2018 before we begin increasing our forecast for the back half of 2018. Right now, we have a very solid forecast for 2018. Like we said, we plan to return to distribution coverage in the back half of the year. And I don't think it's really appropriate to go any further than that at this point.

Okay, that make sense. I just kind of want to understand given the comments. Following up on that, you know obviously 2017 G&A is impacted by transaction-related costs with respect to Navigator. If I remember correctly, your guidance pre-Navigator was about $100 million to $110 million for G&A for this year. How does that change on a run rate basis going forward? Should we be thinking $25 million a quarter, $30 million a quarter. I just kind of want to understand what's the permanent step change as we think about it back half of this year and then into next year?

The guidance -- this is Chris Russell. The guidance Tom gave for this year was $110 million to $120 million, but again that include that $10 million and -- to the portion of the the cost -- portion of the financing cost. So I think next year we'll be back in that $100 million to $110 million range and that should be a pretty good run rate going forward.

Okay, great. Just 2 more follow-up questions. Gabe started asking, I think, about the -- how discussions were going, I guess, Midland to Corpus? Do you need to wait for all those multiple open seasons to be completed before you have a negotiation about a JV? Do you get involved in the process now before the open seasons close? I was just wondering if you can sort of walk us through how to think about that role that works.

There's no reason to wait for open seasons to be completed to have those conversations. I think likely -- some of the more likely projects in my view aren't even in an open season.

Got it. And then finally, with some commentary out of Washington about potentially not taking crude from Venezuela. Would that have an impact on your (inaudible) contracts potentially? Or because of how it flows, it would not. Just wanted to know if you can give us a little commentary on that?

That would depend entirely on what the sanction would be, but no way to comment on that.

Yes. We don't anticipate that, that would cause a problem at our St. Eustatius facility. That crude is not heading for the United States through there.

Our next question comes from Selman Akyol of Stifel.

I guess just a quick follow-up question. In your press release, you referenced taking $14 million in transaction charges this quarter. So exactly, how much of that is hitting your G&A line?

$10 million is sitting in G&A.

For this quarter?

Correct.

Okay. And then also just in terms of thinking about the fuels trading? Is there any charges to be taken there over the rest of the year as we go through?

The fuel's trading, no.

This is Chris, real quick. I just want to clarify. The other $4 million for the financing cost, that's buried in interest expense. So $4 million...

So we should have looked at as a onetime expense, kind of, on a go forward basis coming out of interest?

Correct.

(Operator Instructions) Our next question is a follow-up from Jeremy Tonet of JPMorgan.

Just wanted to follow up on the EBITDA guidance to make sure I have it straight. Did guidance decreased from $620 to $670 to $600 to $650 for EBITDA? And if that's correct, is that just kind of like the DUCs that you were talking about their or is there any other factors in play?

A small piece of it is the DUCs, but the main driver -- as I said before, we have vessel turnarounds that are expected in the back of the year, pretty significant turnaround by one of our customers. So that's the key driver, and I think we had some St. Eustatius vessel activity with another one where -- we're seeing a little bit less vessel activity in St. Eustatius, so that's contributing as well. And again, this is -- the DUC are part of it, but kind of a small part.

Got you. And then just want to follow up on the transportation segment. The implied rate for the revenue kind of moved down a bit there. Is that just kind of mix shift with Navigator? Is that kind of like a new run rate or how should we think about that?

Are you talking about average tariff rate, Jeremy?.

Yes.

Yes, probably driven a lot by Navigator.

And that's kind of like a better run rate going forward here?

Yes.

To be honest, I'm not really exactly sure what you are referring to, we may have to just get back with you on...

PYes, we will go back and talk about average tariff rate.

Our next question comes from Matt Niblack of HITE.

First question is, really could you provide more color on how you're planning to finance all of this given deficit of retained cash and the relatively high unit price? I understand there is a big financing slug done earlier this year, but it looks like there should be a good chunk more that needs to be financed going forward?

Yes. So we don't really have any more equity planned for the rest of this year. We've got our CapEx guidance. We just put out there for you guys and based on that, the CapEx spend that we have planned for the remainder of the year and going into '18, we don't think we need any more equity. So that's the good news there with the higher -- with the lower unit price. We plan to finance -- most likely in the back half of the year, we may have another small bond issuance or preferred, but mainly we're going to -- what [we are kind of] going to be using our revolving credit facility. So it's going to be a combination of those things.

And is the idea then to have leverage creep up a bit in the interim and then Navigator ramp, some other growth projects ramp that you will just naturally delver through growing EBITDA and then revolver can ultimately be financed with debt?

Yes, we are still exactly as we planned. Back at the Navigator acquisition, we said that we would be starting off around the 4.5x, 4.6x debt-to-EBITDA. As I announced today, we closed the quarter at 4.6x. We do expect that to ramp up closer to 5x over time as we get to the back half of the year because of some of the CapEx that we're talking about and then coming back down again and we expect to be back down to more normal levels by the -- by midyear 2018.

And then second and my last question. Any thoughts on simplifying the GP, LP structure. It seems like GP trades perpetually at a discount to where it probably should relative to the growth prospects. And I just wonder given the liquidity and given all the things you've going on, it wouldn't make more sense to somehow simplify that structure?

Yes, we get asked that question almost every day. So we continuously look at it. It's certainly on our radar screen. We don't have any imminent plans to do that, but we understand the dynamics there and we constantly look at it.

There are no further question. I'd like to turn the call back over to Chris Russell for any closing remarks.

Thank you, Michelle. Once again, I'd like to thank everybody for joining us on the call today. If you have any further questions, please feel free to reach out to NuStar's Investor Relations Department. Thank you.

Ladies and gentlemen, thank you for participating in today's conference. This does conclude the program, and you may all disconnect. Everyone, have a great day.