Title

Presentation

Antero Resources Corporation misses on earnings expectations. Reported EPS is $0.5 EPS, expectations were $0.54.

Operator: Greetings, and welcome to the Antero Resources First Quarter 2023 Earnings Conference Call. At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation. As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Mr. Brendan Krueger, CFO of Antero Midstream, VP of Finance. Thank you, Mr. Krueger, you may begin.

Brendan Krueger: Thank you. Good morning, and thank you for joining us for Antero’s first quarter 2023 investor conference call. We’ll spend a few minutes going through the financial and operating highlights, and then we’ll open it up for Q&A. I would also like to direct you to the homepage of our website at www.anteroresources.com, where we have provided a separate earnings call presentation that will be reviewed during today’s call. Today’s call may contain certain non-GAAP financial measures. Please refer to our earnings press release for important disclosures regarding such measures, including reconciliations to the most comparable GAAP financial measures. Joining me on the call today are Paul Rady, Chairman, CEO and President; Michael Kennedy, and Dave Cannelongo, Senior Vice President of Liquids Marketing & Transportation. I will now turn the call over to Paul.

Paul Rady: Thank you, Brendan. I’d like to focus my comments today on our company’s operational performance during the quarter. During the first quarter, we set a number of new company and industry drilling and completions records, which highlights our exceptional team and high-quality asset base. Let’s begin on Slide number 3 titled Drilling and Completion performance. The chart on the left-hand side of the slide highlights our lateral footage drilled per day. During the first quarter, we achieved three of the top 10 lateral feet drilled in a 24-hour period. This included a world record of 12,340 lateral feet drilled in a 24-hour period. The chart on the right-hand side of the page illustrates our completion stages per day.

We set a new quarterly record at almost 11 stages per day, including a single-day record of 16 stages per day. These completion records are referring to a single completion crew. Across the two crews, we have averaged 22 completion stages per day. These are extraordinary achievements from both our drilling and completion teams who continuously look for ways to improve our operations. I will note that the increase in efficiency during the first quarter results in being pulled forward. During the quarter, we completed 31% of our 2023 budgeted completion stages. Now let’s turn to Slide number 4 titled Antero Well Performance Versus Peers. In addition to the drilling and completion records, we continue to be very encouraged by the well productivity we are seeing.

The chart on the left-hand side of this slide shows that Antero’s liquids productivity continues to get better and better each year. Average liquids productivity has increased 87% since 2018. The chart on the right-hand side of the page highlights well productivity trends versus our peers since 2020. As illustrated on the page, Antero’s average cumulative equivalent production per well is 20% greater than the peer average over this time. This is an important distinction for Antero. With many companies having already drilled their best acreage, our long core inventory life continues to deliver stronger results each year. Next, I’ll discuss Slide number 5 titled Low Decline Rate Leads to Lower Maintenance Capital. As we enter the fourth year of a maintenance capital program, our base decline rate continues to move lower.

This analysis from a third-party highlights that Antero’s one-year and three-year decline rates are the lowest of our natural gas peer group. Touching briefly on our cost outlook, we are beginning to see service costs roll over for rigs and completion crews. We’re also seeing a decline in costs for raw materials, such as tubulars, fuel and sand. The combination of cost deflation, drilling and completion efficiency gains and a lower decline rate is expected to result in lower overall maintenance capital requirements in 2024. Lastly, I would like to comment on our organic leasing efforts. During the quarter — the first quarter, we invested $72 million on land. As previously communicated, this represents just under half of our 2023 land budget of $150 million.

Our leasing efforts are primarily focused near our current development plan, where we are achieving these excellent drilling completion and well performance results. This land investment in the first quarter adds the equivalent of over 50 incremental drilling locations, mostly in the liquids-rich core of the Marcellus. We say equivalent locations as the organic leasing investment adds both absolute locations as well as lengthening our current locations. For example, our 2023 wells drilled are expected to average 14,500 feet in the lateral, a 7% increase from the average in 2022. Now to touch on the current liquids and NGL fundamentals, I will turn it over to our Senior Vice President of Liquids Marketing & Transportation, Dave Cannelongo for his comments.

Dave?

Dave Cannelongo: Thanks, Paul. Liquids prices have rebounded from recent lows in early Q1 and fundamental data is pointing to continued recovery throughout this year, especially for the propane barrel. While lack of cold weather and several PDH outages resulted in high propane inventories this winter, a resurgence in international demand has pushed more barrels into the global market in recent weeks. Slide number 6 highlights that U.S. propane exports have already increased 20% year-to-date at 1.6 million barrels per day compared to 2022’s average of 1.35 million barrels per day. Additionally, the propane exports hit an all-time weekly high at 1.85 million barrels per day in April, according to EIA data. The increase this year is the result of the post-COVID recoveries in demand and the Chinese economy reopening.

Looking at the macro infrastructure picture, this year is expected to be a pivotal one for the LPG market, which stands for liquefied petroleum gas, namely propane and butane. As shown on Slide number 7, we expect record deliveries of very large gas carriers, or VLGCs, which are the largest sized marine vessels that can carry LPG, roughly 550,000 barrels per ship. The market will also see significant increases in Chinese petrochemical demand for LPG, driven by PDH capacity additions this year and in 2024. On the shipping side, the market expects deliveries to 46 new VLGC ships during 2023, which equates to a 300,000 barrel per day increase in shipping capacity based on average round-trip voyages from the U.S. Gulf Coast to China. On the left-hand side of Slide number 7, the chart shows that 11 new VLGCs have already been placed into service year-to-date.

These capacity additions have already helped reduce the Baltic rate from $94 at the beginning of 2023 to $75 today. The additional VLGCs are expected to reduce shipping rates further and narrow the spread between Mont Belvieu and international pricing, resulting in a tailwind for Antero’s C3+ realizations. Turning to Slide number 8. The U.S. is still expected to be the incremental global supplier of NGLs to meet increasing international demand. Recently announced OPEC+ additional crude production cuts are expected to lower LPG from the Middle East, continuing to solidify the U.S. to be the incremental NGL supplier to the world. These recent OPEC+ oil cuts, if achieved, could limit OPEC+ LPG supply by an additional 8% or 3 VLGCs per month from May of 2023 to December of 2023.

The chart on the left-hand side of the slide shows that while the rest of the world supply growth in NGL production is expected to be roughly flat from 2022 to 2024, the U.S. is expected to grow 11% during that period. I’ll note that we believe that this U.S. growth estimate could prove to be too high given the year-to-date reductions in liquids-rich-focused drilling rigs. We have seen 27% and 19% declines in liquids-rich-focused rigs in the Appalachian Basin and the Eagle Ford, respectively, since the beginning of the year. Even with U.S. supply growth, third-party providers show that there is expected to be unconstrained LPG export capacity through the end of 2026 based on existing dock capacity and recently announced expansions as shown on the right-hand graph of Slide number 8, which is supportive for Mont Belvieu pricing.

While Antero certainly benefits from the uplift in Mont Belveiu prices, the majority of Antero’s NGL exports are transported through the Mariner East system. And Antero’s firm capacity on that system and unique pricing flexibility give us additional opportunities to take advantage of price spreads and arbitrage opportunities. Turning to China on Slide number 9. We have seen a recent recovery in utilization rates at existing PDH units and continued plans to add more capacity in 2023 and 2024 to meet post-pandemic demand growth. A PDH is a propane dehydrogenation facility that takes a feedstock of propane and converts it into propylene, a key building block in the plastics industry. The chart on the left-hand side of Slide number 9, and shows that planned expansions over the next two years will nearly double kinase PDH capacity for 2022 levels, resulting in over 500,000 barrels a day of potential new propane demand or about 5% of the overall global propane demand.

With limited supply growth coming from the Middle East and other areas, as we have discussed, China will increasingly depend on U.S. LPG imports to serve these plants. This trend is already evident with 50% of total Chinese LPG imports coming from the U.S. in March of 2023, according to third-party ship tracking data. Anetro is extremely well positioned to benefit from increasing global NGL demand over the long term, with over 50% of our NGL volumes being exported in all of our NGL volume currently unhedged. With that, I will turn it over to Mike.

Michael Kennedy: Thanks, Dave. Following our successful debt reduction program, Antero entered 2023 in the strongest financial position in company history, further strengthening our position as our low free cash flow breakeven level. Turning to Slide number 10 titled Free Cash Flow Breakeven. We thought it was important to revisit this slide as it is critical to our natural gas macro views. As a reminder, slide provides a look at the natural gas peer group and the required NYMEX Henry Hub price for each of the peers to achieve an unhedged free cash flow breakeven position in 2023. As illustrated on this page, as a result of higher maintenance capital costs, limited liquids revenue uplift and widening basis differentials on natural gas, we estimate that most Haynesville companies are not able to generate free cash flow in today’s pricing environment.

We’ve already begun to see a moderation of activity from these producers through the gas-directed rig declines in recent weeks. We expect this downward trend in rig counts to continue through 2023. As you can see on the left-hand side of this slide, Antero’s free cash flow breakeven price benefits from a significant liquids uplift and the premium natural gas pricing we receive by selling our gas out of basin. Turning to capital returns. Slide number 11 illustrates the steady and consistent progress we have made in our share repurchase program over the last year. During the first quarter, we purchased $87 million of our stock. Since the inception of our share repurchase program at the beginning of 2022, we have now purchased over $1 billion of our stock or approximately 10% of our shares outstanding.

Now let’s turn to Slide number 12 titled Antero’s Differentiated Strategy. As I just discussed, our focus on liquids development provides significant benefits to our free cash flow breakeven. In 2023, we expect 45% of our total revenue to come from liquids. This focus on liquids is further highlighted through the 17% liquids production growth we delivered during the first quarter compared to the year ago period. This liquids growth compares to a 3% decline in natural gas volumes during that time. Our differentiated strategy continues with the chart in the middle of the slide highlighting our ability to sell 100% of our natural gas out of basin, including 75% of the LNG corridor. With no exposure to local markets that often trade $0.50 to over $1 back of NYMEX, we are able to capture premium prices to NYMEX.

The chart at the bottom of the slide shows our commitment to reduce absolute debt since 2019. This commitment has resulted in $2.4 billion in debt reduction during that time and a leverage profile of just 0.5x. Also acting as a cash flow tailwind, our royalty agreement with Martica ended on March 31, 2023, increasing our net royalty interest and wells drilled by 3.75%. This will result in lower cash flow distributions to Martica each quarter going forward, assuming the current strip. We anticipate the majority of that cash flow to revert back to Antero in 2025 based on today’s commodity prices. We are committed to our return of capital policy, which targets returning 50% of free cash flow to shareholders. Based on current strip prices and our current enterprise value of approximately $8 billion, we trade at a PDP 15 valuation.

So using our free cash flow to buy back our stock is an attractive option. In closing, the successful execution of Antero’s differentiated business strategy positions us to excel across many commodity price cycles. Increasing NGL demand through the reopening of China provides a bullish backdrop to NGL prices as we move through the year. On the gas macro, we continue to expect moderated activity from producers and basins that are outspending cash flow at today’s prices. We expect this moderated activity lead to significant volatility in pricing as natural gas demand grows materially in 2024 and beyond, with the second wave of LNG export facilities coming online. Looking ahead, we are well positioned with a peer-leading balance sheet, product diversity with nearly half of our revenue generated from liquids and significant exposure to U.S. LNG demand growth.

With that, I will now turn the call over to the operator for questions.

Operator: Our first question is from Subhash Chandra with The Benchmark Company. Please proceed with your question.

Subhasish Chandra: Congratulations on the drilling records. Just trying to think through what this might mean as the year goes on with 31% of the completions in the first quarter. How do you think about, say, fourth quarter, if you’re running such a strong pace, do you sort of stay within budget, within the wells guided? Or do you sort of take advantage of the efficiencies and drill through them as we close out the year?

Michael Kennedy: Yes. No, good question, Subhash. We’re obviously a bit ahead of schedule on the completion pace. So right now, our thought is we would just have less completions in the fourth quarter and stick to the budget.

Subhasish Chandra: Okay. And a follow-up, I guess, is a couple of basin questions. If there’s an update on the Shell Cracker? Is it fully functioning at this point? And then MVP, how you think of that impacting the basin? Is there more gas coming or more rerouted gas as a consequence?

Michael Kennedy: On the Shell, they’re still in the commissioning phase. So they’re not up ramped up to full volumes, and we’ve completely risked that in our production guidance. Our gross wellhead volumes are obviously ahead of expectations, but we have risked the ethane volumes as if the commissioning of the Shell Cracker continues throughout all of 2023. On MVP, we don’t sell any locally, as you recall. So we don’t follow it that closely. I just — and it seems that it’s been delayed past 2023. So we don’t see really any impact from that.

Operator: Thank you. Our next question is from Bertrand Donnes with Truist Securities. Please proceed with your question.

Bertrand Donnes: With your mineral acquisition and the 50 locations that you tacked on, it seems like you’re more comfortable just kind of replacing your inventory as you drill through it. But do you have any thoughts on M&A in the basin? Is there any driver to make companies come to the table? Or is it really — everybody is going to kind of wait and see? And then as LNG demand comes on, we might have a mix of people that can get to the Gulf Coast and those that can’t, and maybe that forces M&A?

Paul Rady: Yes, that’s true. Yes, we do look inside the basin. You see our focus on adding the premium acreage to just continue to replenish our inventory. Yes, there are a number of competitors in the basin that are somewhat trapped that they are selling at the local index and can’t go to the premium market. So, whether that results in a distressed case on their part or not, we’ll see, but we look at everything within the basin.

Bertrand Donnes: Okay. Sounds good. And then shifting gears a little bit. You guys always got a lot of nice slide on propane and butane and what the markets look like. But I was wondering if you could expand on maybe ethane. I know prices are kind of depressed right now, but some of your peers have gotten kind of bullish maybe towards the end of this year or next year. Some of the debottlenecking happens, maybe some exports pick up. So I just want to know if you guys have any thoughts on that.

Dave Cannelongo: Yes. For our ethane recovery volumes, about 40% to 50% depending on the quarter right now is linked to Mont Belvieu. And so I think some of those bullish outlooks are really around Mont Belvieu pricing and frac spread pricing. Most of our other volume, it’s not Mont Belvieu linked as gas linked. And we’ve — as we’ve discussed previously in calls, we bake in a premium to gas to have a long-term contract for those types of customers. But on the Belvieu side, we’ve seen the same predictions. Obviously, recoveries of ethane in Texas have been near max for quite some time. Production is growing down there. But so is demand for ethane in the U.S. Gulf Coast domestic side as well as on the export side. We do believe there’ll be quite a bit of ethane export growth here in the coming years.

So certainly, the potential, if you look historically, ethane has traded more like an oil product than as a gas product prior to the shale revolution. It’s really been the recent years it has traded more similarly to gas. But yes, that potential is there is that the demand for ethane at those types of facilities is very sticky. They’re building crackers that can only consume ethane. So that’s the kind of demand you want to have, both domestically and internationally.

Bertrand Donnes: Got it. Got it. And then I don’t want to take a real third question. This is just kind of a follow-up. The comment about maybe just letting the number of completions be that and not going over your CapEx even if you have kind of efficiencies. Was that comment also applicable to next year? I think some of your other peers would likely choose to let their volumes go up and then others are letting their production volumes fall year-over-year. So I just didn’t know if that applied to ’24 as well. Is the maintenance program, the target next year as well? Or is maybe there’s some leg room?

Paul Rady: So there’s always a wiggle room, but no, we’re really pretty determined to stick to our maintenance cap for 2024 as well. So it may turn out the way it does in 2023 that we move through our completions more quickly, but we’ll still stay under the under the budget constraints.

Michael Kennedy: And I would also add on the 2024 maintenance capital level, it’s at a lower level than the 23 capital because of these efficiencies, those really drive lower costs. Plus we are seeing a rollover in the service costs and raw materials. And as each year that we are at maintenance capital, our decline rate lowers by about 1%. So that you’ll need less wells as well to keep at that maintenance level.

Operator: Thank you. Our next question is from Umang Choudhary with Goldman Sachs. Please proceed with your question.

Umang Choudhary: My first question was around optimal capital structure and your free cash breakeven. I mean we are likely going to be in a volatile gas price environment as we haven’t really built to gas storage even as demand has increased. So I have a two-part question for you. First, would love your thoughts around any actions you can take to further lower your free cash flow breakeven, especially given your plans to be unhedged going forward? And second, any thoughts on building cash on the balance sheet and on optimal leverage ratios, which can allow you to be more opportunistic in a low commodity price environment?

Michael Kennedy: Yes. Good question. We’re attacking the breakevens by really focusing on the highest liquids opportunities we have. And that’s why you see our breakevens are so low. It’s because we’re drilling 1,275 to 1,300 Btu wells that are heavily liquid focused. So that’s how we’re really thinking about lowering our breakevens on the natural gas side. So — and then on building cash, we wouldn’t build cash. You saw last year, we would have an opportunity to have, but instead of doing that, we are active in the open market repurchasing our debt, our bonds. Some of our bonds become callable to in the first quarter of ’24. So we would call those bonds instead of building cash. And if all that was not available to us, we’d be buying back our shares. So have no plans on building cash on the balance sheet. We’ll use it to either pay down our debt or buy back shares.

Umang Choudhary: Quick follow-up there then. Would you be willing to use a credit facility to do share repurchase? Or would you prefer the credit facility remains low to preserve liquidity in the case of severe your outlook?

Michael Kennedy: Yes. No, we wouldn’t lever up to buy back shares. We’re very steadfast in our debt reduction goals and want to get as low as possible. So we would not use our credit facility to buy back shares. We’d rather keep it low.

Operator: Thank you. Our next question is from our Arun Jayaram with JPMorgan. Please proceed with your question.

Arun Jayaram: Yes. I want to maybe ask Dave, in terms of C3+ pricing, the futures market is kind of embedding, call it, low 50% range in terms of WTI in terms of — ratio relative to WTI. Do you think that’s a fair outlook for the near term? And how does this potential reduction in shipping costs, how do you think about that influencing demand globally for C3+ is making it cheaper and perhaps the ratio relative to WTI if we get into a better demand environment?

Dave Cannelongo: Yes. I think it’s actually for the near term, let’s just call it into this summer of ’23, I think levels are probably pretty in line with where we would expect them to be, just given the high propane inventory absolute levels that we’ve seen here through March and April. I’d say as we move through the year, that’s where we see the upside, we expect exports to continue to be quite robust. And that’s where you’ll see propane inventory start to move down in the five-year range — closer to the five-year average with the potential to be below the five-year average by the end of the year. And that’s where you can really see that the propane price start to appreciate in the percentage of WTI for our C3+ barrel improve.

We continue to expect some strong values for isobutane this summer, some of what we saw last summer. And value for octane appears to be there again in the market. So I think we’ll continue to see some tailwinds from that as well. But really with C3 making up over 50% of our C3+ barrels, focus is really going to be on the demand side of the equation and seeing those exports start to pull down inventories.

Arun Jayaram: Great. And just my follow-up would be just on the capital efficiency front. You guys did an average of 11 stages this quarter, which for us is — we tend to think of a good quarter is doing eight stages. So that’s a pretty impressive number. So how does that — is that influencing yet your thoughts on the CapEx budget? Which I think the midpoint in terms of the D&C CapEx guides $900 million. And do you think this is a level of completion efficiency that can be sustained? Or did everything just go right this quarter?

Michael Kennedy: No. We’re sticking to the $900 million, like you referenced, Arun. And in that in our thoughts, we’ve moved up our assumptions. I think we were assuming eight to nine stages a day, and we achieved 11. So now we’re assuming around 10 stages today. So we’re not assuming the 11 continues, but we are assuming better performance and increased performance and think that will occur throughout the year.

Arun Jayaram: Okay. Can I sneak in one more, Mike?

Paul Rady: Sure.

Arun Jayaram: I just wanted to get a sense. You guys do a lot of great work on the kind of the macro picture. And one question we’d be getting from investors and just perhaps thoughts on the timing of Golden Pass in 2024. I know you don’t operate that. That’s an ExxonMobil project. But do you have any intel or thoughts on the timing of that project? It’s pretty important for the supply-demand balance to think about gas next year.

Paul Rady: Let me pass that question to Justin Fowler, who is our Vice President of Natural Gas Marketing and Trading. So Justin?

Justin Fowler: We just continue to hear on our side that Exxon and the Qataris continued to fast track Golden Pass. So the first train size that is expected to come online is around 750,000, 800,000 a day, and we’re thinking that’s going to be sometime in 2024. So that’ll just start to take more guests into the liquefaction corridor. And then they will continue to ramp up another two trains. And again, everything that we’re hearing, they’re working to fast track that project.

Operator: Thank you. Our next question is from David Deckelbaum with TD Cowen. Please proceed with your question.

David Deckelbaum: I was hoping maybe you could quantify a bit or talk directionally about the maintenance capital progression to ’24 and then ’25. And I suppose there’s also, I guess, a theoretical impact of lower free cash breakeven at the corporate level from some of the Martica adjustments over time. I guess as we sit today, given some of the efficiencies that are happening and then it seems like there’s some pressure on costs coming down in the field, how do you think about like percentage-wise a decline in maintenance spend into ’24 and then beyond that? Or is it really the visibility beyond ’24 is dictated by base decline progression at this point?

Michael Kennedy: They all go into it, and they’re all tailwinds for us, David. I would — when you think about it in the kind of 10% to 15% range year-over-year decline ’24 versus ’23. So that’s pretty significant. And then that continues to be about the level that you need in the out years. It continues to trend a bit down as maintenance capital needed for a lower decline declining base, as you continue to put year after year of flat production in the wedges that continues to decline from there.

David Deckelbaum: If I could just follow up on the land budget, I know there was the expectation, obviously, this would be the largest quarter in terms of land spend, but I guess, as — have you seen more opportunities on just some of the land side coming to you as the market has been softer? Or is there really no correlation between that type of market and what we’re seeing on the spot screen?

Michael Kennedy: Yes. No, we knew that first quarter was going to be a large one because a lot of these deals that you land take 60 days to close. So we knew in November and December, we had some large packages that we were able to execute on. We’re going to close in January and February. Right now, the pipeline is as the budget suggests that you don’t have those large packages. So it should come back into that $25 million level a quarter type of pace, which is more normal for us.

Operator: Thank you. Our next question is from Kevin MacCurdy with Pickering. Please proceed with your question.

Kevin MacCurdy: As it relates to service costs, can you remind us what your philosophy is on contracting term? And how that might play into lower well cost for the back half of this year and into next year? And I was going to ask you to provide a range of potential impact, but it sounds like you just did. Did you say that maintenance CapEx would be down 15% next year?

Michael Kennedy: At 10%, I said 10% to 15%, but I would start with 10% in ’24 and then maybe it trends to 15% in the years after that in ’25 compared to ’23. Yes. So our contracts on the completion side, they expire. They’re generally annual contracts. They expire at the end of ’23. There are openers in them based on commodity prices, and we are obviously, with the low — natural gas price below those commodity price kind of openers. So we’ll just have to see how that goes in ’23. The rigs, they are generally 12 to 18 months. We try to stagger them so we don’t have all the rigs coming off at once. So it’s a mix of late ’23 and first and second quarter of ’24 for the rigs.

Kevin MacCurdy: Great. I appreciate that detail. And then apologies if I missed this in your presentation or your release, but can you let us know how many wells you turned in line and how many wells you completed in the first quarter?

Dave Cannelongo: Well, it’s about 80% for the year. I think it’s probably about even on the well turn lines, maybe low 20s.

Operator: Thank you. Our next question is from Subhash Chandra with The Benchmark Company. Please proceed with your question.

Subhasish Chandra: Mike, just a follow-up on the inflation or the deflation question. How much do you think you’d attribute to being in a gas basin and seeing some perhaps excess deflationary there? Or how much do you think this is just across all services and materials?

Michael Kennedy: I’d say it’s the latter. Right now, what we’re really thinking will occur in ’23, it’s more on the raw material side. And that would be across basins, but it’s more on the tubulars, it’s more on sand costs, it’s more on fuel. And that’s regardless whether it’s gas or oil basin, you’re going to capture some of those cost decreases on the service costs. We are now seeing some decline in rig counts and completion crews being used in our basin. So, there’s some spot fleets becoming available, and that should eventually lead the lower service cost. But right now, we’re not seeing it for this quarter.

Subhasish Chandra: Right. Got it. So that 10% to 15% number, if you had to wait, how much of that was raw material dependent versus service dependent? Is there a number you can throw out there?

Michael Kennedy: Yes, that 10% for next year does not assume any service cost decrease. That’s really more just looking at the raw material costs and then looking at lower well counts because our decline rates go down.

Operator: Thank you. There are no further questions at this time. I would like to turn the floor back over to Mr. Brendan Krueger for closing comments.

Brendan Krueger: Thank you for joining us on today’s call. Please reach out with any further questions, we are available. Thank you.

Operator: This concludes today’s teleconference. You may disconnect your lines at this time. Thank you for your participation.