Hello. Thank you for standing by. Welcome to the Third Quarter 2022 Enterprise Products Partners L.P. Earnings Conference Call. At this time all participants are in a listen-only mode. After the speaker presentation there will be a question-and-answer session. Please be advised that today’s conference may be recorded. I would now like to hand the conference over to your speaker today, Randy Burkhalter, Vice President Investor Relations. Please go ahead.

Thank you, Josh. And good morning, everyone and welcome to the Enterprise Products Partners conference call to discuss third quarter 2022 earnings. Our speakers today will be Co-Chief Executive Officers of Enterprise’s general partner, Jim Teague and Randy Fowler. Other members of our senior management team are also in attendance for the call today. During this call, we will make forward-looking statements within the meaning of Section 21E of the Securities and Exchange Act of 1934 based on the beliefs of the Company as well as assumptions made by and information currently available to Enterprise’s management team. Although management believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct. Please refer to our latest filings with the SEC for a list of factors that may cause actual results to differ materially from those in the forward-looking statements made during this call. And so, with that, I’ll turn it over to Jim.

Thank you, Randy. Today, we reported exceptional results for the latest quarter. We reported adjusted EBITDA of $2.3 billion for the quarter. We also generated $1.9 billion distributable cash flow, providing 1.8 times coverage. We retained $826 million in DCF, taking us to $2.6 billion for the first nine months. We achieved six operating records, including transporting a record 11.3 million barrels per day of oil equivalent in the form of NGLs, crude oil, natural gas, refined products and petrochemicals. We transported a record of 17.5 trillion Btus per day of natural gas. We also set quarterly volumetric records for NGL fractionation, ethane exports, butane isomerization and fee-based natural gas liquids. Earnings from our Midland Basin natural gas gathering and processing business and higher gross operating margins from our natural gas processing, octane enhancement and natural gas pipeline businesses were particularly exceptional for the quarter. Today, uncertainties in the global economic environment are weighing on the petrochemical industry, where sluggish demand is leading to reduced runs and destocking. There are some serious concerns about recession, especially in Europe, where the question isn’t whether they go into recession, but about the depth and length of the downturn. Meanwhile, on the other side of the globe, China’s GDP has taken a nosedive from double-digit growth over the past number of years to low single digits at best. Thinking back on my career, first with Dow and now at Enterprise, I can’t count the number of downturns I’ve been through. At Dow, the downturns were always painful, but here at Enterprise they always bring opportunity. In the current environment, while the uncertainties are real, the certainty that Enterprise will always deliver is real too. Moving to CapEx, year-to-date growth CapEx excluding our Midland Basin acquisition totaled $973 million and our current expectation for growth capital for 2022 and 2023 remains in the $1.5 billion to $2 billion range. We currently have $5.5 billion of organic growth projects under construction and we look forward to bringing our PDH 2 plant and our Frac 12 plant in the Midland and Delaware Basins along with our TW product system online in 2023. We’ve been traveling domestically since the end of 2020, and now we are back on the road traveling internationally. We are welcomed in every country we visit. Brent and some of his team just spent three weeks traveling across Asia from Japan to Korea to Singapore and India, and I joined them for some meetings in the last week of their trip. In the middle of a prolonged war in Europe, along with the outright weaponization of energy by Putin, a global energy and food crisis, and inflation worldwide, our country is better positioned than any other, thanks to our abundance of both energy and agricultural products. Notwithstanding that abundance, the critically low inventories of distillate in the Northeast United States were self-inflicted and could have been completely avoided by temporarily waiving the Jones Act. In our travels, executives in other countries no longer ask about the size of U.S. energy resources. They don’t ask about where we think price is headed or if we feel U.S. supplies will be competitive. Instead, in most meetings, we are asked if our politicians have a clue about the realities of the world’s immediate and longer-term needs for U.S. energy. Unfortunately, with the rhetoric that comes from our government and inaction on badly needed permitting reform for pipelines, transmission infrastructure, and mining, the probable answer to that question is no. Our government needs to understand that rhetoric matters. The United Nations has stated that there is a direct correlation between energy consumption per capita and quality of life. Much of India’s population lives in poverty. One of India’s most senior executives reminded me in our meeting that they have access to ample supplies of coal. Without access to U.S. resources, they are going to use any and all available resources to raise the standard of living for their people. Global coal consumption is predicted to hit an all-time high in 2022. And that’s a trend that could continue as Russian natural gas stays restricted. Meanwhile, in touch with reality, Europe recently declared both natural gas and nuclear energy as clean energy resources that will be needed for years to come, and Asia continues to be very clear about their long-term appetite for U.S. energy. We at Enterprise have been emphatic that it’s going to take all of the above to meet the world’s growing energy needs. That’s why in addition to traditional midstream services, we’re also focused on investments in lower carbon projects like carbon capture and sequestration and providing blue ammonia into export markets. U.S. hydrocarbons remain critically needed to support countries that live in energy poverty, and to support our closest friends and allies in Europe who are in an energy crisis. We currently export about 60 million barrels of oil equivalent every month. It’s clear that the world wants and needs much more of what we have. We’re back on the road traveling both domestically and internationally. We’re growing existing relationships and developing new ones and seeking new opportunities.

All right. Thank you, Jim. Good morning, everyone. Starting with the third quarter income statement, net income attributable to common unitholders for the third quarter of 2022 was $1.4 billion or $0.62 per common unit on a fully diluted basis. This compares to $1.2 billion or $0.52 per unit for the third quarter of 2021. Adjusted cash flow from operations, which is net cash flow from operating activities before changes in working capital, for the third quarter of this year was $2 billion. This is a 13% increase compared to the $1.7 billion generated for the third quarter of last year. We declared a distribution of $0.475 per common unit for the third quarter of 2022, which is 5.6% higher than the distribution declared for the third quarter of last year. This distribution will be paid on November 14th to common unitholders of record as of the close of business on October 31st. During the third quarter, we repurchased approximately 3.9 million common units at a cost of $95 million. For the first three quarters of this year, we repurchased approximately 5.3 million common units for $130 million. We plan to resume our program to opportunistically buy back up to $350 million of units in the near term. For the 12 months ended September 30, we paid over $4.1 billion of distributions to limited partners and bought back $255 million of common units in the open market. For this period, Enterprise’s payout ratio of adjusted cash flow from operations was 56%, and our payout ratio of adjusted free cash flow, excluding the $3.2 billion Navitas Midstream acquisition, was 70%. In addition, during the third quarter and the first nine months of this year, approximately 1.5 million common units and 4.7 million common units, respectively, were purchased on the open market by our distribution reinvestment and employee unit purchase plans. Total capital investments in the third quarter were $474 million, which includes $397 million for organic growth capital projects and $77 million for sustaining capital expenditures. Capital investments for the first nine months of 2022 were $4.4 billion, which included the $3.2 billion acquisition of Navitas Midstream, $973 million invested for organic growth capital projects, and $234 million for sustaining capital expenditures. Our total growth projects under construction remain unchanged from last quarter at $5.5 billion. We continue to expect our total 2022 growth capital expenditures to be approximately $1.6 billion and sustaining CapEx to be approximately $350 million. For 2023, we currently expect growth capital investments will be approximately $2.0 billion. Our total debt principal outstanding was $29.5 billion as of September 30, 2022. Assuming the final maturity date for our hybrid notes, the weighted average life of our debt portfolio is approximately 20 years. Our weighted average cost of debt is 4.4%. At September 30, approximately 93% of our debt was fixed rate. Earlier this year, we retired $1.4 billion of senior notes and redeemed $350 million of variable-rate hybrid notes using a mix of cash proceeds from a note issuance in September 2021 and commercial paper. Our consolidated liquidity was approximately $3.3 billion at September 30, including availability under our credit facilities and unrestricted cash on hand. With regard to near-term debt maturities, we have $1.25 billion of senior notes maturing in March 2023. We expect our free cash flow generation and liquidity position will provide ample flexibility regarding the refinancing of these notes. Adjusted EBITDA was $9 billion for the 12 months ended September 30, 2022. Our consolidated leverage ratio was 3.26 times on a gross basis. If you net out the partial equity treatment for the hybrid notes and reduce debt by unrestricted cash on hand, that number on a net basis was 3.1 times. Given the coordinated efforts by global central banks to increase interest rates to temper inflation and the likelihood of a global recession and just general volatility, we believe that it is prudent to remain at the lower end of our targeted leverage range of 3.25 to 3.75 times EBITDA. Lastly, we published our 2022 sustainability report in September. We encourage you to visit our website and review our discussion on the vital role of U.S. fossil fuels in supporting the pillars of modern civilization and providing a pathway for a better life for 2.5 billion who still live in energy poverty. With that, Randy, I think we can open it up for questions.

Josh, we’re ready to take questions from our listeners. I would like to remind everyone to please restrict your questions to one question and one follow-up please. Go ahead, Josh.

Thank you. Our first question comes from Michael Blum with Wells Fargo.

Thanks. Good morning, everyone. I wanted to ask about Permian growth heading into 2023. You had some comments last week from the majors. Obviously, you've got tight gas takeaway. Do you see that all impacting the pace of growth into ‘23 on the oil side and the gas side, I guess, for the Permian?

Yes, Michael, this is Tony. As we entered this year and during our analyst meeting, we mentioned that, considering our current momentum, predicting whether the growth from year-end 2021 to year-end 2023 would favor one particular year was challenging. However, I'm maintaining the estimate of a 1.5 million barrels increase in oil. As you noted regarding the comments from the majors, I'll choose Chevron as an example. The supply chain and labor challenges in the oilfield are significant. Chevron is forecasting to be at the lower end of their production target, especially as 2022 comes to a close. That said, we have seen a 60 rig increase in the Permian Basin year-to-date. Comparing the current rigs to those from 2019 or 2020 shows an improvement in efficiency, about 30% better, which is substantial. If I were to take a guess, considering that the August numbers from EIA indicated a 100,000 barrel a day increase from July to August, I would say we are looking at an increase, and that gives us a year-to-date jump of roughly 350,000 to 400,000 barrels, depending on the figures. Therefore, I feel confident stating that we are likely to see an increase of 500,000 to 600,000 barrels for the entire U.S. in 2022, and between 600,000 to 800,000 barrels in 2023. Summing these up brings us to a total increase of 1.2 million to 1.4 million barrels, and we plan to revisit this at our Analyst Meeting next year, but we are very comfortable with that range.

Great. Thanks for that, Tony. I have a related question: clearly, Waha's pricing has been quite weak lately. Could you share how much open gas pipeline capacity you have to take advantage of those spreads and how much of that you’ve already hedged? Thanks.

Michael, this is Brent Secrest. If you look at Enterprise’s capacity as it relates to Waha to Gulf Coast markets, we are between 350 million and 400 million a day of open capacity, or just call it outright capacity for Enterprise. And as it stands right now, none of that’s hedged for next year.

Great. Thanks so much.

Our next question comes from Jeremy Tonet with JPMorgan. You may proceed.

Hi. Good morning. Just wanted to pivot to the petchem business, if you could. We’ve seen a lot of commentary about the petchems talking about lower operating rates. It looks like we are headed for a bit of a down cycle here. You touched on this in your opening remarks, but just wanted to get a bit more color on what that could mean for EPD specifically here. I think we’ve talked about in the past how this might look like a six to nine-month destocking cycle. Is that still how you see it? And if so, I guess, how would that impact EPD? Do you see a big step down in petchem services next year or how should we frame the range of outcomes?

Let me give it to you, Chris. We don’t have the spreads between RGP and PGP that we had last year. However, the spreads we have today are more aligned with our historical patterns. Our octane enhancement business has performed well, and we’ve hedged 75% for next year at favorable rates. Additionally, we’re bringing on PDH 2 next year. Our ethylene and propylene distribution and export storage facilities are performing strongly and expanding. I personally believe that while propylene may soften, we are still expected to do quite well.

Yes. If you look at how we’ve built our splitter business over the years, it’s midstream services where 50% of our margin is fee-based; 25% of our margin is fee-based with exposure to the spread when it blows out. That’s what you’ve seen over the last year and a half. The last 25% is market exposed. Over the next six to nine months, we may continue to see weakness in destocking. We’ll see a reversion to what our historical split or profits have been. PDH 2 will add to that.

Got it. That’s helpful. Thanks. I just wanted to consider the context of capital allocation here, it seems like we have a bit of choppiness in the credit markets with investors still looking for greater return of capital on the equity side. I wonder how you see that shaking out amidst this background?

Yes. Jeremy, this is Randy. Good morning. You’ll continue to see us sort of all the above and try to do a combination of distribution growth and buybacks where it makes sense, again, opportunistically. We’re in good shape. We’ve managed our debt maturities very well. We issued longer-term debt. Our maturity ladder, we don’t have big maturities in any of the years coming up. So, I think we’re in good shape going into 2023 to handle that maturity when it comes due.

Got it. And as far as the return of capital to investors, buybacks versus dividend distributions, is there any change in thought, given…

No change in thought. 2022 marks our 24th year in a row for distribution growth, and we think next year, we’ll hit 25 years of distribution growth. Still, we’ll come in and do all of the above.

Jeremy, this is Chris Nelly. The one thing I would add is that talking to many investors, given the inflationary environment, they really appreciate the 5.6% distribution growth year-over-year. That’s helpful to many of our individual unitholders.

Our next question comes from Jean Ann Salisbury with Bernstein.

Just building on Jeremy’s question about Dow stating they’re going to cut polyethylene production by 10% to 15%. Can you provide your thoughts on what that means for U.S. ethane production and NGL prices? And if it could touch on some other parts of your business like LPG exports or discretionary ethane that maybe people don’t necessarily expect to be so petchem related?

I’ll start and then throw it to Brent and Chris, Jean Ann. I’m going to go to LPG exports. We’re doing well, aren’t we, Brent? On ethane exports, I’ve seen us go no less than 5 million barrels a month and up to 7 million barrels a month. Regarding ethylene and propylene, to the extent they go lower, it opens up export opportunities, more for ethylene and propylene. So those export docks growing in value as prices decrease.

Jean Ann on ethane in terms of recoveries, if domestic demand goes down, it’s still pretty strong. Tony, it’s around 1.9 million barrels a day. So, it’s still hanging in there. There’s going to be a lot of ethane recovered out of the Permian Basin. That’s going to help our Permian Basin NGL lines. On the discretionary ethane front, when you look at Rockies and other more challenged basins in terms of distance, that’s the barrel that’s likely to be on margin, probably for next year. On the ethane business at Enterprise, about 90% of our business is under take-or-pay contracts. Therefore, the ethane dock and Aegis and ATEX and those type of businesses are all fairly solid from a revenue standpoint. We may have some open spots for next year, but we’ll have some opportunity across our facilities.

And just following up on one of your comments there. You’d mentioned earlier that as gas prices widened in Waha, you might see significant ethane opportunity, such as more ethane being recovered—possibly even 100,000 barrels. I was just wondering if now that you’re seeing gas prices widen, if that ethane is starting to show up?

Absolutely. If you look across Enterprise’s operations, what’s going on doesn’t affect us as much as it does affect third-party processors. But you’re definitely seeing the effects. This month and toward the end of last month, we expect to see it for the balance of 2023.

One more thing. I’m convinced that some of what we export is being burned, especially in Asia. In fact, I know one company is doing this when they can land ethane cheaper than LNG.

Our next question comes from Michael Lapides with Goldman Sachs.

I’m just curious, the world has changed significantly in the last six or nine months. Credit markets are starting to get a little choppy out there, especially for some smaller entities, public or private. Just curious if the M&A landscape has become more attractive. I know you just did Navitas, but that was before the credit markets got choppy. I’m interested in how you think about the opportunity to use the balance sheet to acquire assets?

I’m thinking that we are building two more plants in the Midland Basin and two more plants in the Delaware Basin, and that’s a more efficient use of capital than going to pay a high price for acquisitions. We liked the Navitas deal. It’s worked well. But it wasn’t just a good deal; it was a strategic fit. What concerns some of us, at least me, is I’ve been through several second requests, and I don’t see anything we could buy that would require second requests.

Got it. In other words, sellers haven’t reached a point where pricing has come down significantly in the market?

Yes. Michael, I think it’s more, again, expanding on what Jim was saying, that we’re just seeing a lot of organic growth opportunities right now. When we were leading up to the Navitas transaction, we conducted a detailed review of all available opportunities in the gathering and processing world, and Navitas checked all the boxes for us. The transition has gone well, and we’re pleased. We continue to look at opportunities, but right now, we are simply seeing better returns on capital from organic growth.

Got it. Thank you, guys. Much appreciate it.

Thank you. One moment for questions. Our next question comes from Brian Reynolds with UBS. You may proceed.

Hi. Good morning, everyone. To start on the moving pieces in ‘23 CapEx, it seems like Shin Oak has gotten pushed to the first half of ‘25 from ‘24. I’m curious if you can talk about the moving pieces in CapEx, what’s potentially still under development, and what could provide some upside or downside to that ‘23 CapEx number of roughly $2 billion?

Brian, this is Randy. I think where we are with 2023 at $2 billion, it’s hard to see that moving materially higher. As for the only large project that we’re looking for more clarity on, it’s our offshore crude oil export facility, and we are still waiting for permits there. Even with that, it’s hard to see this number moving materially higher as we sit here today.

Great. And just a quick follow-up. Is there any fundamental shift in view with Shin Oak expansion being postponed a year?

Yes. This is Justin Kleiderer. I don’t think it changes our fundamental view. We now have a bit more time to act on the expansion. We still have the scoped expansion ready to go. We’re just taking a little more time to understand what’s appropriate for market needs and when it will be necessary.

Great. That’s super helpful. And then maybe just as a broader question, while ‘23 E&P budgets haven’t been formalized, curious if you could talk about Permian producer customers, what they’re looking at and how they’re considering ‘23, given the expected nat gas tightness. Are public and private players looking at ‘23 differently? Do you foresee flaring coming back materially in ‘23 or is that a thing of the past? I can see more fluctuating volumes while we navigate that nat gas tightness?

Brian, I’ll start out. This is Tony. I made the comment at the beginning of this call. If you look at what’s happened to Permian rig counts, it’s significant. There is a lot of momentum in the Permian. We hear it from publics and privates alike. There's been talk of a slowdown, but it’s hard to kill this kind of momentum. Brent, I’ll let you discuss your conversations with producers about privates, big privates, and public perceptions on this.

Brian, looking at the bigger privates, they still have a fairly robust growth plan. I heard some earnings calls last week from larger players in the Permian. They were more tempered than we had been hearing. The larger public companies were talking about more growth. In our system in the Midland Basin, we recognize we have timing and capital projects, but we anticipate about 23% growth from the natural gas side and processing side from ‘22 to ‘23. The Delaware Basin side is probably about 7% to 10%. This may be slightly delayed for our plants. Even for producers looking at gas prices in 2023, I didn’t check before entering, but we’re still around a $3 type number for producers to hedge. In the grand scheme, crude oil drives 85% to 87% of the economics. So, what the producers gained when able to achieve $4 or $5 type gas prices was indeed a gift. I don’t think it changes the perspective toward Waha, because it’s still a healthy number for 2023.

Our next question comes from Theresa Chen with Barclays.

Tony, I wanted to ask for an update on how much ethane you think is still currently being rejected in the Permian. I think the last update was 200,000 to 250,000 barrels per day, and how much can realistically come out?

Yes. That number changes from day to day. I’ll pass it to Tug or Brent. It fluctuates. My assumption is that the rejection number has decreased due to what’s happening with gas, but it varies a lot.

Some older plants are unable to recover as much as the newer plants. What can’t be recovered is probably around 50,000 to 75,000 barrels a day due to older technology.

With the spreads they have, I can’t imagine anyone purposely rejecting…

Looking towards the petchem side of things. I’m curious to hear your view on your customers in the international markets. Indeed, from a U.S. perspective, capacity utilization is down here, making feedstocks cheaper. Exporting makes a lot of sense. However, considering international markets and hearing about a reduction in production in Far East and European facilities, coupled with some prolonged maintenance due to poor margins, what does that mean for U.S. Gulf Coast exports of petchem feedstocks internationally?

This is Chris D’Anna. The entire petchem segment is weak globally right now. What that has meant for us over the previous months is that our ethylene export dock is full. Some months, the product goes to Europe; other months it goes to Asia. These petrochemical plants are trying to balance production to find the right operating levels. The short answer is that it means our dock is full, at least for ethylene. For propylene, we’ve had imports at times, and we’ve had exports at other times, creating some opportunities for us.

As previously stated, we can keep the ethane and LPG docks full.

Our next question comes from Chase Mulvehill with Bank of America.

I want to follow-up on some of the Permian growth expectations. I believe you stated that 600,000 to 800,000 barrels a day would be U.S. growth for next year. What would that translate into Permian growth? Also, how does that relate to residue gas growth—what’s the equivalent of that for the ‘23 number?

It’s heavily weighted towards the Permian. Other increases in oil are relatively minor. In terms of NGL growth, per million barrels, it’s approximately 3 billion cubic feet of gas from a drive perspective. The gas, both on the Midland side and on the Delaware side, appears to be getting a bit gassier, which doesn’t imply there’s less oil; it just indicates there's more gas present, which is why we're expanding our plants. This creates some pressure on producers for 2023 regarding takeaways at Waha.

Yes. I suppose that was my follow-up question: how quickly do you think that 1.1 billion fills once PHP and Whistler, those expansions come online towards late Q3 or early Q4? And additionally, do you still have 350 to 400 million a day open for the first half of ‘24 for the Flow Through?

I’ll answer the second question. This is Brent. It's still open in ‘24. Ultimately, those pipelines may not come on fast enough. I think during this tight daily market for Waha, we saw last week—and prior to it—when conditions are so tight, something going down will create significant challenges. I don’t think that’s the last we've witnessed of negative gas prices at Waha.

Thank you. One moment for questions. Our next question comes from Neal Dingmann with Truist. You may proceed.

Good morning, guys. My first question is regarding the upcoming projects. Looking at the projects listed, I know you’re talking to midstream and upstream companies facing typical supply chain issues and various delays. Could you provide general comments? You have a large number of projects coming online next year. Can you provide insight on how you feel about those projects? Most likely there are supply chain issues, primarily around electrical gear, but I believe we’ve mitigated almost all of those issues. Overall, we're positive about executing the projects we have listed.

Yes. Bottom line is we feel very good about these projects. There are still some supply chain issues mainly around electrical gear. However, I think we’ve managed to resolve almost every one of those. Going forward, the execution of these projects looks strong.

Graham, would you like to provide a bit of insight on PDH 2?

Of course! Regarding PDH 2, we’re still slated for mechanical completion in the second quarter of next year. The execution is going very well, and we are looking at coming in under our forecast for that specific project. We’re excited about it. Our teams did a fantastic job back in 2020 mitigating many supply chain issues that arose during the pandemic. To this day, we remain on schedule and may come in slightly under budget.

Thank you. One moment for questions. Our next question comes from Keith Stanley with Wolfe Research. You may proceed.

Hi. Thank you. That’s good news on PDH 2. I just wanted to clarify on the buybacks. Is the plan still to repurchase up to $350 million specifically in the second half of the year, or is the timeline more open-ended?

Yes, it could extend into next year. We’re looking to implement this opportunistically. We’ll see what the market gives us; there's a lot of noise out there with the Fed. We will attempt to accomplish this by year-end, but if not, we’ll carry over into next year.

Got it. And then just a quick question regarding the Eagle Ford crude contract impact in the third quarter. Should we think of that as ongoing or simply annualize that number going forward?

If you look at that contract—that’s a life of the lease contract. The deficiencies we experienced are still going to yield some fees related to how much production is there. If you examine the producer tied to that contract, they have fairly robust growth plans. As more volume comes in during '23 and '24, and they’ve shared their growth plans with us, you can expect to see some offsetting gains. I would think that this quarter is probably our worst quarter in terms of impact. By the end of the year, we’ll probably recover about 25% of what we lost, and that number should continue to rise.

Josh, this is Randy. We have time for one more question.

Our last question comes from Colton Bean with TPH and Company.

I just wanted to follow up on the natural gas segment, which saw a significant step up in earnings this quarter, but it didn’t appear to be from marketing. Can you walk us through the changes in the intrastate business and whether that’s a sustainable run rate going into 2023?

Are you asking specifically about our Texas Intrastate System?

The natural gas segment broadly, but based on the release, it seems the intrastate was key to most of the uplift. Any changes there?

We’ve seen increased demand or increased contracts from volumes primarily from power providers. We’ve also enhanced some of our transport contracts from Waha, as well.

If you look across our entire natural gas segment from Haynesville or anywhere around the Permian, you’ll see increases likely every month as we go forward, Colton. That’s a fairly healthy business at the moment.

Okay. Josh, this is Randy. That would end our call today. We’d like to thank everyone for joining us for our call. Have a good day. Thank you very much. Goodbye.

Thank you. This concludes today’s conference call. Thank you for participating. You may now disconnect.