Diamondback Energy Inc (FANG) — Q2 2019 Earnings Call Transcript

Thank you, Josh. Good morning. And welcome to Diamondback Energy Second Quarter 2019 Conference Call. During our call today, we will reference an updated investor presentation, which can be found on Diamondback's website. Representing Diamondback today are Travis Stice, CEO; Mike Hollis, President and COO; Kaes Van’t Hof, CFO. During this conference call, the participants may make certain forward-looking statements relating to the company's financial condition, results of operations, plans, objectives, future performance, and businesses. We caution you that actual results could differ materially from those that are indicated in these forward-looking statements due to a variety of factors. Information concerning these factors can be found in the company's filings with the SEC. In addition, we will make reference to certain non-GAAP measures. The reconciliations with the appropriate GAAP measures can be found in our earnings release issued yesterday afternoon. I'll now turn the call over to Travis Stice.

Thank you, Adam. Welcome everyone. And thank you for listening to Diamondback's second quarter 2019 conference call. Diamondback continued to execute in the second quarter of 2019. We produced record EBITDA per share from 7% quarter-over-quarter production growth while lowering the midpoint of our capital cost guidance and increasing the midpoints of both our full year production guidance and estimated completed well count for the year. Diamondback has now grown earnings per share at 11% quarterly CAGR and EBITDA per share by 9% quarterly, since our IPO in late 2012. Based on second quarter numbers, Diamondback now generates more annualized EBITDA per share than our IPO price seven years ago. Diamondback continues to focus on per share metrics with shareholders now owning more production, cash flow, and earnings per share than prior to our acquisition of Energen a year ago even in the face of a lower commodity price environment. Diamondback's per lateral foot well costs, which include every dollar in bringing our operated wells to production and the first six months of production-related costs thereafter, are down 7% year-over-year in the Midland Basin and 16% year-over-year in the Delaware Basin. As a result, we are narrowing the midpoint of our 2019 capital budget and increasing the midpoint of our operated completions, which implies over $110 of improved capital efficiency per completed lateral foot versus our initial budget presented in December. Our operations organization continues to drive material costs out of the business with expectations for continued tailwind due to improved efficiencies and service cost deflation. With respect to the Energen acquisition and subsequent integration, Diamondback has now completed every major strategic objective and exceeded our stated synergies presented one year ago when we announced the deal. In the second quarter, we completed the IPO of our midstream business Rattler, raising over $720 million net to Diamondback. We also recently announced the dropdown of over 5,000 net royalty acres to Viper for $700 million of gross proceeds, including $150 million in cash. Lastly, we recently completed the sale of the conventional central basin platform assets acquired via the Energen acquisition. As a result of completing these objectives, Diamondback immediately commenced our stock repurchase program by repurchasing $104 million of stock in the second quarter after reducing our consolidated net debt by $400 million quarter-over-quarter. We intend to use the majority of the remainder of these proceeds, along with increasing free cash flow from operations, to continue our stock repurchase program. Our balance sheet is strong with both absolute debt levels and leverage metrics low, and we will continue to return capital to shareholders via our share repurchase program and dividend. At current valuations, we continue to feel the best use of our free capital at Diamondback is buying back our own stock. With respect to oil realizations, we believe the worst of our widest basis differential quarters are behind us. And we now expect to realize greater than 95% of WTI pricing for the second half of 2019. By early next year, we expect to realize oil prices at parity with greater than WTI, as our existing commitments convert to the Gray Oak and EPIC pipelines and receive grant or coastal pricing. With our recently announced commitment to the Wink to Webster pipeline, we will have full exposure to the Houston and Corpus Christi local refining and export markets by 2021, removing in-basin pricing risks from our future business model. In closing, Diamondback continues to execute on the promises presented at the time of the Energen acquisition, and our business is nearing a significant free cash flow inflection point in the second half of 2019 and into 2020. We may no longer be maximizing growth within cash flow, but we are not sacrificing growth in 2020 as we expect to grow at industry-leading rates for large cap E&P and deliver over $750 million free cash flow at $55 oil due to our best-in-class cost structure, asset quality, and operating metrics. With these comments now complete, operator, please open the line for questions.

Thanks. Good morning, guys. Travis, I flipped through the slide deck here, it's pretty apparent that you have really checked the box, and a whole bunch of aggressive objectives over the last year. Really just kind of wanted to get your thoughts on what's on your mind now and kind of what's your refreshed strategic to-do list look like as we sit here today? Thanks.

Thanks, Mike. Yes, our strategic objective there are not really any new ones. We're going to maintain our commitment to execution and capital efficiency; that's part of our core business practices. We're continuing at the board level to grow the dividends, and we've committed to this free cash flow return to shareholders in the form of share repurchases. So while we've checked off some pretty significant objectives, those were one-time events in the first seven months of this year. We're committed long-term to this shareholder return program and we're pretty confident we'll be able to deliver on it.

Okay, thanks. And maybe the follow up on that, you just mentioned to that $750 million of free cash flow in 2020 with industry-leading growth still in the works. What would get you to maybe dial down that growth a little bit and to up the ante on free cash flow? Just kind of curious just to hear maybe your philosophical thoughts on that growth versus the free cash flow balance. Thank you.

It's not an exact science, the way that we look at the future. If commodity prices roll over further, we're certain we're going to look at our forward model and make adjustments accordingly, probably in the form of dropping one or two rigs. But our future is really bright, Mike. With the way that we continue to execute with our overall cash costs in the mid-8s right now, we're profitable significantly on every barrel that we produce for long life from this current oil price. So we're pretty confident. We've got a lot of still exciting things to deliver in the future. And I think the future at Diamondback is really bright.

Travis, going through the release about your low capital cost continued to be notable. And so I guess my question is around those. How do these factor in when allocating capital between thinking about production growth versus buyback or other shareholder initiatives?

Neal, it's not really an either or; I think it's an and. And I think we're one of the few companies that can do both. We can still grow, and we can repurchase shares and further returns to our shareholders. So we don't pivot on that. We actually look at a way to combine both growth and returns for our shareholders.

I have a follow-up question regarding the spacing shown on Slide 10. It seems to me, when comparing this to some previous presentations from years past, that your assumptions haven't changed much over time. I'm curious if there might be any opportunities for down-spacing, or if you are satisfied with the current strategy. Given the increased scrutiny in this area, could you provide any insights about your assumptions and how they may have changed or are expected to change?

Neal, I went back into the same thing. I want to see how long this slide deck has been in our, or this slide had been in our slide deck. And I think it goes back like four years. And I think I've said a thousand times it's easier strategically to add locations than it is to take away locations. And we've always been conservative in our spacing assumptions, and we don't really have any plans right now, especially as commodity prices continue to decline, to look at any reasons to increase well spacing. This is one of those things where we've been pretty steadfast in our strategic development objectives on spacing. It's been underpinned by our annual reserve reports. And we would pay attention to other spacing results that go on in the Permian basin. And we try to learn from those as well, without exposing our shareholders to down-spacing risks. So, I'm very comfortable with our spacing assumptions.

Good morning all, and congrats on a strong update.

Thank you, Derrick.

Perhaps for Travis, your capital efficiency and now disclosure standard, there's last night's release, are peer leading. What in your view makes your organization so successful at cost control?

Derrick, we've received that question from various perspectives over the quarters, and it's not due to just one factor. It's really a mix of many elements. We recently completed an operational review in preparation for this quarter, focusing on our drilling operations. We analyzed the connection time, which is how quickly the pipe is connected, and found that we trimmed down by roughly 0.7 minutes per connection for every well drilled with 20 rigs in the second quarter. That adds up to about a dollar per foot for each well, across five wells with 20 rigs. This attention to detail in our cost management truly sets our operations apart. We believe in inspecting what we expect—that’s one of our key principles. Our business is fundamentally about turning rock into cash flow, and measuring every part of that process is crucial for maximizing efficiency. The operational machine we have in place is impressive. Without it, we wouldn't have achieved these strong results, especially after completing $10 billion in acquisitions last year. It's noteworthy that our drilling, completion, and expense costs are now lower in total, after integrating with Energen, compared to Diamondback's standalone costs from a year ago. This indicates a smooth integration process, all while we met the corporate objectives I mentioned earlier, and added over 300 employees to our team. Achieving these results in this quarter is truly remarkable for our organization. Our economics have never been better, we are more profitable, and our operational capacity has increased. Overall, we are performing exceptionally well. Despite the challenging market conditions, we are confident in our cost structure, execution capabilities, and capital efficiency. We will continue our development plan, supported by our strong organization.

I agree, Travis, quite an impressive feat. As my follow up, perhaps for you Mike, as you think about and compare your D&C costs between the Midland and Delaware Basins. Where do you see the greatest room for improvement in your Delaware costs?

Yes, Derrick, you captured it perfectly. In the Delaware Basin, we're currently in the third to fourth inning. In Midland, we are around the fifth inning and approaching the sixth. In Midland, we're fortunate to be picking up dimes in quarters. In Delaware, as you noticed, we achieved a 16% reduction in our cost per foot. That area is witnessing the most significant changes and improvements. Looking ahead, our organization is not going to stop learning and adapting, and what we're implementing in Midland can be applied in Delaware and the other way around. These two teams are working closely together. Overall, we will keep integrating efficiencies into our operations. As Travis mentioned, there are also positive factors related to commodity prices and activity levels. We're noticing some easing in service costs as well. All these elements combined suggest that we can expect some positive developments in the upcoming quarters.

I really had a housekeeping question. Can you talk about the next step for you guys to achieve investment-grade status and the potential timing of that?

Gail, we're having active dialogue with the rating agencies. I think with us being over 280,000 barrels a day, this business qualifies as an investment-grade company. Our debt certainly trades like it's an investment-grade company. We just need an upgrade from either S&P and Moody's so upgraded us both. After the acquisition, we've executed on everything we said we're going to do post-acquisition. And I think this business is on its way to becoming an investment-grade company whether or not the ratings get there or not.

Thank you...

Gail, we also added the fall-away provisions to our credit facility in the early spring, and that results in our credit facility becoming unsecured once one other agency upgrades us, including our Fitch rating today.

Travis, in the past you talked about using some of your free cash flow to replenish inventory. I think you've really talked down corporate M&A a lot obviously since the market over the last few months. But just interested to hear if the asset market is open, if maybe bid/ask is too wide here. But if you can pick up acreage at attractive prices?

Well, I think you've always heard us say that we'll do accretive deals. But there is a reason in my prepared remarks I said that I think the best M&A opportunity for us right now is repurchasing Diamondback shares. And so that's really the corporate focus. But we do have an obligation to look for deals, but they've got to be massively accretive. And like I said just to reiterate, our focus is on repurchasing our own shares right now.

I had a question on unit expenses in 2Q. We saw gathering and transportation LOE, both reverse course after some pretty big declines. Can you talk about anything one-off that happened maybe in 2Q, or how we should think about a more normalized trend going forward on those cash OpEx items?

So in the quarter, we have the full effect of the Central Basin platform. That acreage was closed on July 1st. So our LOE should trend down here in Q3 and Q4. We've been hinting towards the upper half of our 4.25 to 4.75 guidance for the rest of the year on LOE. Gathering, processing, and transportation, that moves around a little bit quarter-to-quarter. I still think the midpoint is a good number there.

Could you provide a follow-up on a few earlier points? Regarding the $750 million in free cash flow for 2020 that you mentioned, what is the estimated CapEx budget associated with that? Does this suggest a slight increase from the second half of 2019 levels, or is it indicative of a continuation of current activity?

If anything, it would be a very, very moderate increase versus current activity levels. We're running 8 frac spreads today. We will run 8 frac spreads all year. And we're going to exit the year running 8 frac spreads. We don't anticipate having any frac holidays at the end of the year. We're going to have 2019 running 8 spreads and probably enter 2020 running those 8 spreads. So I think for us now the questions are at the margin, right? We are completing 300 and 320 wells this year. I don't expect a material change from that number to the upside or the downside pending a major commodity price change.

And then you reduced debt a little bit in the quarter and obviously, you are in a strong financial position. But at a high level, what do you think is the right level of debt for your company? Is it a conservative leverage metric at $750 a barrel oil price? Should we expect further debt reduction going forward? Or do you feel like you're in a pretty good place?

Ryan, I feel really good about how much debt we've reduced over the last couple of quarters. I really, on an absolute basis but also on a leverage metric basis, feel like we're in really good shape. Right now, with the amount of cash proceeds that we have and the free cash flow profile of the business, buying back our stock at these depressed levels is probably a better use of capital for us, while still maintaining a fortress balance sheet.

Thanks, good morning guys. So on Slide 12, you mentioned additional potential savings from infrastructure efficiency attributable to Rattler Midstream. Can you elaborate on that specifically?

The numbers mentioned, 735 in the Midland Basin and 1,131 in the Delaware Basin, represent gross figures. A key advantage we have with Rattler is that we capitalize on the initial six months of water production in both basins, which is part of our equipment and operational expenses. Rattler's margins are benefiting us by saving about $30 per foot in the Midland area and around $75 to $80 per foot in the Delaware region.

And Mike, in the operational update, it was mentioned that you completed a pair of Jo Mill wells this quarter. Can you provide more details on the zone across your footprint, and how do you intend to layer in these completions going forward?

We are currently concentrating on the Northern and Midland Basin. This quarter, we have staggered drilling between Middle Spraberry and Jo Mill, and we plan to drill even more in the upcoming quarter. As we continue our development throughout the Northern Midland Basin, we are incorporating Middle Spraberry and Jo Mill into our plans. Looking ahead, that will be our approach, as the wells are performing well and competing for investment alongside our other zones, and we anticipate continuing this strategy in the future.

I was curious about the larger discrepancy this quarter regarding drilling versus completion. I wanted to know if this was the expected plan for the quarter or if it was just a timing issue. How should we consider drilling versus completion in the latter half of the year?

We have drilled approximately 170 wells so far this year and completed 150. We anticipate completing around 300 to 320 wells, which is in line with our guidance. Our rig count has slightly outpaced our completion count, so you may notice a reduction in the number of rigs we operate in the latter half of the year. However, we will maintain our completion pace with eight operational spreads for the remainder of the year.

And for my follow up, Travis, you mentioned buybacks being most interesting use of free cash flow right now. So just wondering as we look into 2020, you guys starting to build a track record of building the dividend that's having some growth there. So just wondering should we still assume that growing that annual dividend is still going to take precedence over accelerating buybacks, or how you guys look to balance the two while understanding that both of those are goals for your guys?

Again, it's not an either or and I think you've heard us say consistently that the board feels that the dividend is the primary form of shareholder return.

Just wanted to ask a couple of questions as we go into 2020, you basically hit all the goals that you wanted to in '19, and this is a pretty busy year for you guys on the corporate side with the Rattler IPO, but then on the dropdown. As we go into '20, should we be thinking that this is starting to be, for lack of a better word, a more boring execution model? Or should we still be looking for things like drill-cos and other things that you've endeavored in the past to pull some value forward? I guess how do you square those with some of your ambitions of being this free cash growth engine?

David, if 2020 turns out to be a dull year for Diamondback, it would mark the first time in our company's history that we've experienced such a year. Based on our past performance, I anticipate many exciting developments for Diamondback. While I cannot specify what those developments will be just yet, I am confident that as we continue to showcase strong free cash flow and improve our execution and capital efficiency, particularly here in the Permian, we will encounter new opportunities. I may not know exactly what these opportunities will entail, but I believe that as long as we maintain our focus on execution and our organization continues to perform, we will have chances to pursue. It will be up to us, alongside management and the Board, to evaluate these opportunities and determine which ones will provide the greatest value for our shareholders. So while I can't predict exactly what will happen, I do expect that there will be something worthwhile.

I guess like just on the completion side, and you highlighted costs perhaps coming down in the service side in the back half. Are you looking at other applications like some of the e-fracs and things that we see maybe more headline oriented these days. But are you looking at those with any sincerity at this point going into next year?

David, absolutely. So the answer is going to be, yes. Every new technology or application that we can vet and make sure that we're going to save money on the dollar per foot, and not hurt any efficiency in the production of the well. So e-frac, we have an e-frac crew coming in the latter half of this year. We will utilize dual field capability on several of our frac fleets and drilling rigs. Again, we are always looking at what's out there. We're watching what everyone else is doing well. So we will be typically a very, very fast follower; a lot of times we won't be on the exact leading edge. But there's again, we don't want to put our shareholders at risk for that. But at the end of the day, yes, that dollar per foot and the efficiency and capital efficiency is what we're looking for. So the great thing is, as we are slowing down as an industry, a lot of these things are coming available that have been working for other folks and now they are available and we'll take them up. So we're getting some of these crews that are coming in hot, and probably doing the same thing with rigs. We have got to complete the different rig fleet today than we had a year ago. And I think you are seeing some of the capital efficiency metrics same because of what we are doing now.

Travis or Mike, it seems like the rigs have been split fairly evenly between the Midland and Delaware Basins the past couple of quarters. Do you see that split holding fairly evenly into 2020? Or how do you look at the allocation of capital as we get a little bit closer to next year?

We take a look at that almost on every well decision. But I think just for planning purposes, I think just assuming that you're going to have an acreage split with rigs on either side of the basin is a good planning assumption.

I know it's not a major part of your focus, but it seems you're planning to drill a well in the limelight area in the third quarter. If successful, how active could that area get for Diamondback in 2020?

If that area is successful, it will likely compete for capital. The footprint we have there is suitable for probably one to two rigs, and it will be beneficial for Rattler as well. We will wait to gather some data before making capital decisions. However, it could be a favorable location for a partner rig for several years.

I just had one, and Mike you kind of hit on the services side. I mean as far as the pricing of services, I mean how much more do you think there is to really get given that's been pretty beat up obviously. And also, I guess you probably switch a lot of rigs. But do you see much more on the upgrading, whether it's on push your crews or rigs left as you move forward?

Jason, again, these guys on the service side have been squeezed pretty hard. Again, it's in their wagon up to someone that's going to be very consistent in a fluid commodity price environment provides them with both an operational and a financial hedge. So we're getting some benefit there as well as the size and sales. So, us being able to stay steady is really helping those guys out as well. Don't see a whole lot of softening just because again we want our partners to be there at the end of the day, and we needed them and they're a very big part of the success we've had. So we're working with those folks and they work with us on a high end of commodity price. We work with them on the low end of commodity price. But no, it is softening a little bit just because the activity levels are dropping so much.

I guess just a quick one on my end, a lot have been addressed. As you think about the size and scale of the repurchase program. Should we think about the free cash flow as the cap on that? Or given some of the asset sales and the liquidity you have. Should we anticipate seeing potentially even higher amounts of repurchases relatively to the free cash flow you're talking about?

I think through 2019, the rest of 2019, we're going to use a mix of free cash flow profile and proceeds from the asset sales to continue the buyback program. As you move into 2020, I'd say free cash flow becomes more of the big governor at that point. We've completed all these one-time proceeds, the stocks still, in our opinion, very cheap and we're continuing to use our capital to buy back shares in this market.

And then I guess just coming back a little bit on the whole growth versus free cash flow question. How the big picture approach the optimization as you think about 2020 and beyond, but the optimization of growth versus free cash flow in the capital allocation decision? I'm just curious kind of more about your process as opposed to the outcome.

I think it's a process which we've done at the margin for us now. I mean, we are a company that maximized growth with cash flow for the last four years. So growing the cash flow is not a new concept to us. The big changes that we can grow and deliver free cash flow, and we have no intention of slowing that growth to maximize free cash flow or vice versa. It's going to be a symbiotic relationship for a long time. We are going to keep rolling, maybe it's at a rig or keep the same rig count as this year, doing more with the same capital, and growth is the output next year with free cash flow also being the output.

Just a couple quick ones. One, I first want to commend you all from obviously stepping up and buying back stock and hopefully, we'll see more from you all and the rest of the industry, especially with where some of these equities are trading. But maybe this one is for Kaes, as you all think about the buybacks here over the next quarter or two. Is there, you know, in your conversations with the rating agencies. Is there any push back from them to investment grade with the amount of buybacks you are doing?

No, I mean, I haven't seen a lot of pushback. I think a lot of the one-time proceeds that we've received already about $1 billion were the one-time proceeds, they're all seen as very credit positive. So we've checked those boxes and we've also checked the production box and checked the capital efficiency box. So I haven't had a lot of pushback on that front. And for us right now, investment grade is a corporate objective but for us buying back stock at depressed values is a more significant corporate objective.

And a quick second one is on your ownership of VNOM; obviously, you guys strategically took more equity in that ownership with all recent drops. Can you give us a big picture view of your thoughts behind that investment here going forward? And where you all want to shake out with that ownership over time?

Yes, I mean, I'm excited that Diamondback now owns pro forma for the drop back up to 60% of VNOM. I think it's a great relationship between the two; the relationship between Diamondback and Viper, certainly differentiates Viper's multiple and allows both companies to do smart deals like the deal that we announced last week. Diamondback has not sold one share of Viper over the past four years. And in fact, we've increased our ownership, so via share count. So we're happy with that ownership. We get a significant dividend at the Diamondback level from Viper on an annual basis and that relationship will continue to be very strong.

Just a question on the marketing side here, so I think you guys said that you will be at 95% or a little bit better on oil price realizations in the second half of this year versus WTI. Just trying to get a sense, is it maybe a little bit lower in the third quarter or kind of a big boost comes in the fourth quarter. Can you give us any differentiation between 3Q and 4Q on that?

Yes, I believe that the third quarter is close to the 95% range, and the fourth quarter will see a slight increase. It's important to note that we have now secured take-away for all of our major production across the company, a significant improvement from a year ago when we had no take-away capacity. We've certainly navigated through the toughest periods of wide differential quarters. Moving forward, we plan to sell all of our crude either through the dock in Corpus where we have reserved space or to a refinery in Houston. We're quite optimistic about our marketing position in the oil sector.

Okay, that's great. And I guess could you comment on any initiatives on the gas or NGL side? Obviously, it was a rough quarter in the second quarter for gas price realizations. Are you guys working on anything maybe to get that gap out of basin to other markets going forward?

Yes, we have very few time rides across our position. We do have some time rides from the Delaware that we're planning to exercise to get some different pricing exposure. For our Midland Basin and Northern Delaware gas production, we aim to hedge and protect ourselves accordingly. Since gas constitutes a small percentage of our production and revenue, our focus is on hedging that price to achieve a reasonable realized price, avoiding the negative realizations we faced this quarter.

And I guess just on the well cost side, obviously, you guys did a tremendous job of reductions here post the Energen deal. I know it's kind of hard of course to sort of project forward. But you certainly discussed at length your relentless focus on efficiencies here. I mean would you guys potentially foresee the absence of any changes in service costs? I mean, could we be sitting here a year from today and be talking about another 5% to 10% reduction in well costs?

Leo, Mike's guys are obviously the best in the business and that's why we hammered this cost discussion so hard in this deck. I see a lot of notes out about six-month fumes and IPs across the basin; no one is talking about what these wells cost to get out of the ground. I mean, the cost structure that we have differentiates us into someone that can grow and return free cash versus someone who outspends cash flow. That's how important those differences are. So I expect Mike and his team to continue to drive costs out of the business. We certainly have some service cost tailwinds hitting us right now, and those should continue into 2020.

Can you talk to how you see the rates of return in the Midland Basin versus the Delaware Basin? I realize you kind of haven't given a split in terms of activity. But just how you see those rates of return comparing? And then post the cost reductions, you've highlighted how the Energen locations in the Delaware compare relative to legacy Diamondback locations?

I'll share the locations in the Vermejo area, which is the top area in our portfolio and was a key asset from the Energen acquisition. The wells there are exceptional, resulting in the highest rates of return in our portfolio. I still believe, Brian, that while it costs more to operate just outside the basin in the Delaware, the extraction happens more quickly and offers a higher average unit revenue per foot. In contrast, the Midland Basin doesn’t deliver as much hydrocarbon recovery, but operates at a lower cost. Therefore, we consider both areas to have similar rates of return when we allocate our capital. You can see that our spending is balanced with rigs operating similarly on both sides of the basin. While the numbers aren’t exact, we believe they are roughly equivalent.

Can you elaborate on your thoughts regarding the options available in 2020, specifically in terms of share repurchase compared to investing for growth, and how fluctuations in commodity prices during economic cycles might influence those decisions?

Brian, I think it's somewhere around what our budget was this year, either plus the rig or minus the rig absent a very negative commodity take between now and end of the year. So we are very focused on at least hitting that $750 million of free cash at $55 WTI next year. If WTI is lower than that, we will have to look at where service costs are and where our wells cost are, and see what free cash flow comes out of the model. But like I said earlier, there is not a huge delta between our current thinking and where we are in our current pace and where we are going to be in 2020, which allows this business to grow significantly but also buy back a lot of stock. And if the stock remains depressed, we will continue to buy back stock with free cash flow and our one-time proceeds that we have executed on this last quarter.

Thanks again everyone for participating in today's call. If you've got any questions, please contact us using the contact information provided.