Good morning. My name is Casey, I will be your conference operator today. At this time, I would like to welcome everyone to the Keyera Corp. year-end results 2018 conference call. All lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question-and-answer session. If you would like to ask a question during this time, simply press star, then the number one on your telephone keypad. If you would like to withdraw your question, you may press the pound key. Thank you. Lavonne Zdunich, you may begin your conference.
Thank you good morning, everyone. It's my pleasure to welcome you to Keyera's year-end conference call. With me are David Smith, President and CEO; Steven Kroeker, Senior Vice President and CFO; Bradley W. Lock, Senior Vice President and COO; and Dean Setoguchi, Senior Vice President and Chief Commercial Officer. We will open the call for questions once we complete our prepared remarks. Before we begin today, I would like to remind listeners that some of the comments and answers that we will be providing speak to future events. These forward-looking statements are given as of today's date and reflect events or outcomes that management currently expects to occur based on their belief about the relevant material factors, as well as our understanding of the business and the environment in which we operate.
Because forward-looking statements address future events and outcomes, they necessarily involve risks and uncertainties that could cause actual results to differ materially. Some of these risks and uncertainties include general economic market and business conditions, fluctuations in supply, demand, inventory levels, and pricing of natural gas, NGLs, isooctane, and crude oil. The activities of producers and other industry players, including our joint venture partners and customers, our operating and other costs, the availability and cost of materials, equipment, labor, and other services essential for our capital projects, contractor performance, counterparty risk, governmental and regulatory actions or delays, competition for, among other things, business opportunities and capital, and other risks as are more fully described in our publicly filed disclosure documents available on our website and SEDAR.
We encourage you to review the MD&A, which can be found in our 2018 year-end report that we published yesterday, and it's available on our website and SEDAR. With that, I'll turn it over to David Smith, our President and CEO.
Thank you, Lavonne, and good morning, everyone. Yesterday, we reported our 2018 year-end financial results. Even with the challenging industry environment, we focused on what we can control to deliver our strongest year ever. All of our key financial metrics achieved record levels. With confidence in our business outlook, we maintained our dividend track record and increased our dividend by 7% in mid-2018. Since we became a corporation in early 2011, Keyera has invested over CAD 5 billion and delivered a compound annual growth rate of approximately 9% for both distributable cash flow and dividends, both on a per-share basis. During 2018, Keyera achieved a number of operational milestones. With strong demand for our services, we handled record volumes at our Fort Saskatchewan fractionation facility, our Simonette Gas Plant, and through our condensate system. In addition, we carried out the largest capital program in our company's history.
Even with this increased activity, Keyera's employees remained dedicated to safety, achieving zero lost time incidents for the year. Keyera continues to execute successfully on our strategy, expanding and enhancing our integrated network of assets with disciplined capital allocation. We have CAD 2.1 billion in approved projects currently underway, mainly focused on establishing a strong position in the liquids-rich Montney and Duvernay development areas. The capital program begins delivering incremental cash flow mid-2019 when phase I of our Wapiti Gas Plant comes on stream. This begins the next phase of step changes in Keyera's growth as we expect to complete all of the projects in the CAD 2.1 billion capital program within the next 24-30 months.
Once all of these projects achieve their annual run rate targeted for 2022, we expect this capital program to earn an annual return on capital of between 10%-15%, consistent with our historical returns. I am confident that Keyera is doing the right things to continue to grow our business and bring value to our shareholders in the current industry environment. With that, I'll turn it over to Dean Setoguchi.
Thanks, David. Gathering Processing business unit generated operating margin of CAD 272 million in 2018, compared to CAD 275 million last year. Although natural gas prices continued to be challenged, results from our Gathering Processing segment were stable as producers remained active in liquids-rich areas of Alberta. For Keyera, this was most notable at our Simonette Gas Plant in northwestern Alberta, which processed record volumes in 2018. Overall, Keyera's gross processing volumes increased 5% over the prior year. With the completion of our development plans at our Simonette, Wapiti, and Pipestone gas plants, we'll have a significant position supporting Montney development in northwestern Alberta. Our three gas plants will provide 950 million cu ft a day of sour gas processing capacity and 90,000 barrels per day of condensate handling facilities.
Simonette, Wapiti, and Pipestone gas plants support some of the most attractive returns for producers who are actively drilling in the Montney. Keyera is focused on providing integrated midstream solutions for our customers, which includes offering a full suite of services such as NGL fractionation, marketing, a water disposal solution at Wapiti, and the most reliable, efficient, and environmentally responsible process for handling sulfur and carbon dioxide with acid gas injection facilities at each plant. As David mentioned, we expect the first major project, phase I of Wapiti Gas Plant, to be generating incremental cash flow by mid-year. This will be followed by the expansion of the Simonette Gas Plant by the fourth quarter of 2019, phase II of the Wapiti Gas Plant, and the Wildhorse Terminal by mid-2020, the Pipestone Gas Plant in 2021.
These projects are expected to add meaningful EBITDA over the next three years as they come on stream and volumes ramp up. The Liquids Infrastructure segment generated a record operating margin of CAD 324 million in 2018, representing a 14% increase over the prior year. This was primarily due to incremental margin from recent capital investments, such as the Norlite diluent pipeline, the Baseline Terminal, and increasing demand for many of our Liquids Infrastructure assets and services. Our condensate system supports oil sands production, and in 2018, we handled record volumes through our system. In early 2019, we added another shipper on the Norlite pipeline and Keyera's proprietary condensate system. This is the third new customer that has signed up for long-term service since Norlite became operational.
Our condensate hub is backed by long-term fee-for-service agreements with major oil sands producers to provide transportation and storage to meet their growing diluent needs. The system is attractive to producers as it provides them with optionality and flexibility, given all of our condensate receipt points and delivery options and access to our storage. In addition, our system offers built-in capacity and reliability with assets such as the new South Grand Rapids diluent pipeline. Keyera continues to pursue opportunities for our next growth platform. In the fourth quarter of 2018, we entered into a 50/50 joint venture with Wolf Midstream for the proposed development of an NGL and condensate gathering system called the Key Access Pipeline System, KAPS. This proposed pipeline system would include the construction of two parallel pipelines to bring condensate and NGLs from the prolific Montney and Duvernay geological zones to Alberta's NGL Hub in Fort Saskatchewan.
A final investment decision is expected to be made in the first half of 2019, subject to obtaining sufficient customer support. Our Marketing business continues to be a strong contributor to Keyera's success, delivering record results in 2018 with realized margin of CAD 296 million. Over the past five years, the Marketing segment has generated over CAD 1 billion in realized margin. Our marketing activities enhance returns from our fee-for-service business and provide an additional source of funding for our capital projects. Keyera's Marketing segment creates value by utilizing our integrated Gathering and Processing, and Liquids Infrastructure assets, including storage, fractionation, and transportation capabilities. We also upgrade low-value butane into high-value isooctane at our AEF facility. With that, I'll turn it over to Steven to discuss the financial results in more detail.
Thanks, Dean. As mentioned earlier, we had an outstanding year with each of our key financial metrics achieving record results. Net earnings grew 36% to CAD 394 million. Adjusted EBITDA increased 31% to CAD 807 million, and distributable cash flow rose 25% to CAD 638 million, representing a 14% increase on a per-share basis. All three of our business segments had an impressive year. Our Liquids Infrastructure and Marketing segments both generated record financial results, while the Gathering and Processing segment delivered stable results year-over-year. Our three business segments also had a strong finish to the year, delivering strong results for the fourth quarter of 2018. The Gathering and Processing segment generated operating margin of CAD 74 million, which included a one-time upward revenue adjustment for CAD 6 million. The Liquids Infrastructure segment earned CAD 84 million, reflecting the completion of the Baseline Terminal as the last tank came into service in October.
The Marketing segment reported CAD 106 million in realized margin. Marketing's impressive results were largely due to higher contributions from Keyera's isooctane and condensate business, plus our effective risk management strategy. The fourth quarter provided a good indication of the effectiveness of our hedging strategy as commodity prices declined sharply. As a result of this hedging strategy, we had CAD 67 million of realized gains in the fourth quarter on the settlement of risk management contracts. CAD 23 million of these gains were related to risk management contracts put in place to protect the value of our butane that is used to produce isooctane at our AEF facility. While this butane inventory value is protected and cash gains were realized in the fourth quarter, it will mean this higher-priced inventory will factor into isooctane margins realized in 2019 when the butane is consumed by AEF.
For 2019, we are maintaining our maintenance capital guidance of between CAD 100 million and CAD 110 million, which includes both turnarounds at certain gas plants and non-recurring expenditures at Keyera Fort Saskatchewan and AEF, as described last quarter. However, we have updated our cash tax guidance following the introduction of the Accelerated Investment Incentive announced by the federal government last fall. We now expect our 2019 cash taxes to be approximately CAD 25 million lower than our previous guidance and range between CAD 75 million and CAD 85 million. Our 2020 cash taxes are also expected to decrease, now estimated to be less than CAD 10 million. Keyera continues to execute on our growth capital programs. In 2018, we invested CAD 1.3 billion in growth projects and acquisitions. This program included the completion of the Baseline Terminal, the Keylink NGL Gathering Pipeline systems, liquids enhancements at our Simonette Gas Plant, and the Pipestone Liquids Hub.
All these projects are generating incremental fee-for-service cash flows. In 2019, we plan on investing between CAD 800 million and CAD 900 million, excluding acquisitions, to advance our capital projects at the Simonette, Wapiti, and Pipestone plants and the Wildhorse Terminal. Recognizing the dynamic environment that we operate in, Keyera has maintained a strong financial footing and is well-positioned to fund our current CAD 2.1 billion capital program. To date, we have funded approximately one-third of this capital program while maintaining a net debt-to-EBITDA covenant ratio of 2.6 x. This is significantly below our debt covenant limit. With respect to funding the remaining portion of this capital program, we do not plan on issuing common equity apart from the existing DRIP program and are comfortable operating at a net debt-to-EBITDA covenant ratio above three times.
As well, in the event Keyera and Wolf Midstream reach a positive final investment decision on the proposed KAPS project, Keyera believes it is well-positioned to fund our 50% ownership interest in KAPS. Most of the spending on KAPS is expected in 2020 and 2021, when our existing capital program is concluding. Assuming our current capital program is completed according to schedule, we expect KAPS will be funded without issuing common equity apart from our DRIP program. That concludes my remarks. David?
Thanks, Steven. Although our industry continues to face a number of challenges, Keyera's year-end results demonstrate demand for our products and services continues to be strong, while our Marketing services continue to create value year after year. We expect to deliver another year of strong financial performance as we kick off the next phase of our cash flow growth with phase I of the Wapiti Gas Plant. Market fundamentals are moving in our favor as more Natural Gas Liquids are being produced from the Western Canada Sedimentary Basin. As the year unfolds, this is expected to result in higher NGL fractionation fees, as well as lower butane prices in Alberta that benefit our isooctane business.
Keyera is well-positioned to profit over the long term as well as we continue to execute our strategy focused on maximizing cash flow from our existing assets, building a strong footprint in the liquids-rich Montney and Duvernay development areas in northwestern Alberta, pursuing high-return opportunities to expand and integrate our value chain into major U.S. liquids hubs, and improving market access by considering opportunities further down the value chain. On behalf of Keyera's Board of Directors and Management Team, I would like to thank our employees, customers, shareholders, and other stakeholders for their continued support. Our team is committed to delivering another year of strong financial performance, operational excellence, and project execution. With that, I'll turn it back over to the operator. Please go ahead with questions.
Thank you. As a reminder, if you would like to ask a question at this time, please press star followed by the number one on your telephone keypad. Once again, that's star then one if you would like to ask a question. And your first question here comes from Patrick Kenny with National Bank Financial. Please go ahead. Your line is open.
Hey, good morning. I appreciate the return on capital guidance. Just wondering if we can view the bottom end of that 10%-15% range as somewhat of a hurdle rate as you look to sanction future projects in the Montney and elsewhere. Perhaps if you can speak to what needs to happen to achieve the upper end at 15%. Does that assume 100% utilization of the facilities? Would that encapsulate any upside for Marketing?
Patrick, it's David here. I'll try and respond to that. The range that we're providing, it's an average and it's an aggregate, it represents a number of different scenarios that we look at with each one of our capital investment projects. I'm not sure we can be more specific about what the assumptions are behind the low and the high end of the range, unless we were to do it on a project-by-project basis, that's not disclosure that we're prepared to provide. What I can tell you is that when we look at a project, we expect it to stand on its own merits without the benefit of some of the upside opportunities that we often see when we're looking at the integrated value chain.
Got it. That's great. Just moving over to the KAPS discussions here and with respect to the level of interest from customers, I'm wondering if you can speak to some of the moving dynamics here since November. We've seen production curtailments, another Peace Pipeline expansion, and some new competition from private equity in the Wapiti area. Just wondering if the level of interest is still as strong today as it was back in November.
I'll take a shot at that and then Dean can chime in. I think we're very encouraged by the responses that we've seen. We continue to see drilling activity in that area continuing to be strong. When we talk to producers, particularly about condensate, but also about NGL mix, they tell us two things. One is that there's going to be more than enough volume to fill the incremental capacity that Pembina has been talking about, and that Keyera and Wolf are proposing. The second thing they tell us is they would dearly love to have a competitive alternative. For both of those reasons, we've been getting pretty good traction, I feel like our timing is pretty good.
Great. One last question, if I could, just on this most recent outage at AEF. Wondering if you could just walk us through what happened there. Is this a recurring issue at the plant, something completely new and unavoidable? Maybe, if you had an internal availability target for the plant going forward, that'd be great.
Sure. This is Bradley. We had a minor leak in the facility that occurred mid-February. When we assessed it, we found that we couldn't isolate it, so we were forced to take the facility down to deal with it. It's been repaired and turned back over to operations, and we're in the process of bringing the plant back up right now. As we indicated, we expect it to be back up by the end of the month, and we don't expect it to be a recurring issue.
Great. Any internal availability targets for the plant going forward?
I think we continue to target running at or above nameplate. I don't think anything that we've seen would prevent us from doing that through the remainder of this year.
Great. That's it for me, guys. Thanks a lot.
Your next question comes from Robert Hope with Scotiabank. Please go ahead, your line is open.
Good morning, everyone. Congrats on a good quarter. I want to first start off on your Gathering and Processing business. If we just look at the volumes at your plants, it seems like they were trending up through the end of the year. Just want to get a sense of what your expectations are for 2019 and, just given the drilling activities, is that kind of small increases in volumes in some of these plants a trend that could continue through 2019?
Robert, this is Bradley here again. I think, certainly the stronger pricing as you get into the back half of the year, drives some increased volume. I think that's somewhat expected. As we look out into 2019, the pricing forecast continues to be softer in the summer than in the winter. It's not unreasonable to expect a little bit of variability through the summer months, as opposed to the winter months. That being said, we're still seeing some activity behind our plants. Hopefully that's going to temper some of that variability that we might have seen in previous years. It's hard to say until we get into the spring, summer season.
All right, that's helpful. Then moving over to marketing, I realize there's a number of moving parts here, but when you look at what you've seen so far in Q1 versus Q4, is it fair to say that you're seeing some of the similar dynamics if we adjust for the butane contract realization?
Robert, I would say that in Q1, we'll have to adjust for a couple factors, one being our AEF facility being down for two to three weeks. The other factor being the higher feedstock prices, the butane prices for the first quarter until we get into the next contract year starting April 1. Then, notably R BOB and WTI prices are quite a bit lower than last year. I think until we get in the second quarter, you won't start seeing the benefits of, again, the low butane feedstock prices, which will be certainly an average of our new contract prices and the inventory that we still have available coming into the quarter as well.
The only thing I would add to that, this is Steven here, the only thing I would add to that is, again, because of our hedging strategy, we do look forward to try and hedge R BOB margins as well. We do expect to have some of that benefit as well, in Q1 and going forward.
All right. Then just maybe a broader comment, just given how weak butane has been in Alberta, even relative to where it's trading in WTI versus propane, is that a dynamic that is expected to persist through 2019? I'm just trying to get a sense of how much butane benefit on the pricing you could get in 2019.
I'll take that one, Robert. I think our outlook for the foreseeable future at least, is that NGLs in general, throughout North America are going to be in somewhat of an oversupply situation. I think what we've seen through 2018, is we've seen that prices in Western Canada get discounted just because of the transportation costs and more limited market outlets.
We don't see that changing very much throughout 2019. As we sit here today, that's our view. Having said that, as Dean mentioned earlier, we have a mix of term supply contracts as well as shorter-term, more spot-oriented pricing, and we have a mix of different pricing mechanisms on the butane. I think we see it as a positive for our isooctane business. I wouldn't assume that we're buying all of our butane at spot, I guess, is what I would say.
Okay. That's helpful. Thank you.
Your next question comes from Ben Pham with BMO. Please go ahead, your line is open.
Okay, thanks. Good morning. On your commentary on the frac fee outlook, is that also based on some of the conversations that you're having with your counterparties?
Yeah. I think the short answer, Ben, is yes. As you know, during Q1, we're in the throes of the annual recontracting, and some of our recontracting is for longer-term. Our commentary is reflective of those conversations.
Okay. Is there also anything to think about outside of NGL infrastructure as you look to potentially lock in higher frac fees?
I'm not sure what you mean by that.
I was just thinking a few years back when frac fees saw some compression, there were some Marketing side that you were able to offset some of that weakness. Does it essentially reverse then, looking the other way? I guess, in other words, does the volumes you're seeing sustain itself as your frac fees could go higher?
We think the utilization of our fracs will be very strong in 2019. As David mentioned, we think the prices are going to be a bit firmer than what they've been in 2018.
Okay. All right. The only last thing I wanted to check, some of the commentary around the funding and the debt EBITDA, there's some commentary around your comfort level being above three times. I wanted to clarify that. Is that more than three times because your business is much more visible now with take or pay? Or is it more three times during this growth phase and you want to get down to two to three long term?
Yeah, good question, Ben. Steven here. Again, the disclosure we tried to provide was that with respect to funding the growth portion, at times it may be above three, so we're comfortable being above three times while funding the growth program. Again, it always depends on a variety of factors, where you are in the capital program, where you are in the individual project cycle or the EBITDA performance. So we just wanted to give some more guidance to people that our historical range of two and a half to three is not something to be so anchored on while we're going through a growth phase.
I think it also speaks to the confidence that we have in the CAD 2.1 billion program that we talked about and the returns that we'll generate from that investment. Again, a third of that money was already invested in 2018 and previous, so we have 2/3 left to go, and we'll be wrapping up that cash flow profile from those investments.
Okay, good. That's great. Thanks for providing all the additional disclosures. It's very helpful. Thanks.
Your next question comes from Linda Ezergailis with TD Securities. Please go ahead, your line is open.
Thank you. I'm wondering if you could just help us understand that return on capital range, how long it might take to ramp up to the full run rate within the range, that 10%-14%?
Linda, it's David here. As I said earlier, it's a variety of different projects that will sort of achieve their annual run rate at different times. We picked 2022 because I believe the Pipestone project is probably the last one to sort of achieve its full run rate, and that would be in the 2022 timeframe. That's why we picked 2022 as sort of a target for that level of return.
Okay, thank you. Based on your outlook for North American NGL markets being kind of net long for the foreseeable future, how does that factor into any sort of decision to twin or expand AEF? What other factors might you consider, and when at the earliest might that happen?
It's something that we continue to look at, but it's not something that's imminent, Linda. As I always point out with AEF, we acquired that facility at what we think is somewhere between 20% and 25% of its replacement cost. The economics of twinning it are quite different than the economics associated with the original acquisition. Having said that, we're always looking at opportunities to enhance the production to debottleneck. We will look in the future at expansion possibilities. As I said earlier, it's not something that's imminent.
Okay, that's helpful. Maybe you could just elaborate as well a little bit more on the value proposition for customers that KAPS has. You mentioned a competitive alternative and capacity. Are there other attributes in terms of flexibility or customized services or potentially, some sort of cost dynamic that producers are looking for in your discussions?
There's a number of features of the proposal that we've been working on with Wolf Midstream and discussing with our customers. I think at this stage of the process, Linda, it would not be appropriate for me to get into the details. As you can appreciate, it's a competitive environment.
I appreciate that. Thanks so much. I'll jump back in the queue.
Your next question comes from Andrew Kuske with Credit Suisse. Please go ahead, your line is open.
Thank you. Good morning. Maybe just a broad question to start, and with the implementation of the crude production quotas in Alberta, what were some of the broad impacts you've seen on your business just in, I guess since January 1, since the implementation?
I would say that the impact on our business has been negligible, if any. We provide a service, and the services that we provide don't really change in terms of what the government has done.
Andrew, I think it's fair to say we were expecting perhaps a little bit of a drop-off in condensate demand. We really haven't seen that to any great degree. One thing I think that the condensate pricing in Canada has resulted in over the last few months is far fewer rail import barrels. That's the one part of our business where that has more to do with the price of condensate and the supply-demand for condensate, more so than the curtailments that were imposed on January 1.
Maybe just following up on that, when you think about the condensate market on a longer-term basis and then Enbridge's potential future actions on Southern Lights, what does that mean for your positioning within the marketplace?
Obviously, these are all factors that we watch very carefully. You've seen a significant growth in condensate supply from Western Canada over the course of the last two or three years, and we expect that that's going to continue. What we're expecting and hoping is that we'll see more crude oil export pipeline alternatives over the course of the next few years, which will provide, I think, some support for growth in bitumen production, which will provide support for continued growth in demand for condensate. That's another factor on the demand side. There's been lots of chatter about the possibility of Enbridge reversing Southern Lights, and that obviously will affect the supply-demand picture in Western Canada for condensate.
Our perspective on it, obviously, is something we watch carefully, but with our network, what we've tried to create is a lot of flexibility so that we are not as concerned with where the condensate's coming from, and our customers have access to barrels from a variety of different sources.
I think on the demand side, you probably saw that Enbridge announced that they expect the Line 3 expansion to be up and running by end of the year. I think that's directionally 370,000 barrels per day, again, which is supportive for increased bitumen production, but also condensate diluent and demand as well.
Okay, that's helpful. Then one final, more maybe nitpicky question. The 40% of the pipe that you bought, the raw gas pipe across the Willesden Green, how much would that cost to connect into your existing infrastructure, roughly?
This is Bradley, it would be small. The pipe really just fills a gap right now. The dollars would be very, very small.
Okay, great. Thank you.
Your next question comes from Robert Catellier with CIBC Capital Markets. Please go ahead, your line is open.
Hey, good morning. We're not accustomed to seeing Keyera put out a potential FID date on a project, as you have here with KAPS. What's changed to cause you to do that?
Robert, I think we feel like we're getting really close. We're not prepared to get into details, but I think, last fall, we were saying sometime in 2019. I think now we're getting more confident in seeing it in the next few months.
Okay. Dean made a comment about the funding assumption that there was a confidence level in the project execution to indicate that you can internally finance just with the DRIP. Is there another financing assumption in there, and I'm thinking perhaps preferred shares, or can you do this just with internally generated cash flow and the DRIP?
Yeah. Good question, Robert. There's no explicit assumption about having to use hybrids. Obviously, that's always a n avenue available to us if things change in terms of business environment or something like that, but there's no explicit assumption.
Okay. Finally, there was that Redwater case recently about well abandonment liabilities, and I'm just wondering what you're hearing from producers and what they're telling you about the impact of this on their activity levels. Specifically wondering if there's a shift of the spending, maybe to more treatment of those abandonment liabilities as opposed to new drilling.
Robert, I think the concern that I've heard expressed, and this is really more speculative at this point, the concern that I've heard expressed is just a concern about availability of debt financing. I think the concern is that the Redwater decision is going to cause lenders to be more cautious with their borrowing-based determination, and their willingness to lend at the same levels. As I said, I think this is more speculation at this stage. I don't know that there's been very much discussion on that. That's really, I think, more the concern that some producers have is just the availability of debt funding. We don't frankly expect it's going to have a huge impact in our areas, because most of our customers are living within cash flow right now. Access to incremental debt financing is not something that they're relying on.
As far as the level of spending, I think maybe what you were suggesting is that the companies would be spending more money on reclamation. I don't think that that's something that we expect to see in the near term. Most prudent operators have a program of abandonment for the wells that are subject to that requirement, and I don't see those programs being accelerated as a result of the decision.
Okay. That's good color. Just a follow-up question for Steven. I'm wondering if you're hearing any shift in tone with respect to the asset retirement obligations that Keyera has and how those are treated with respect to debt capacity.
No, we haven't heard anything really around that.
Okay. Thanks, guys.
There are no further questions in queue at this time. I will turn the call back over to Lavonne Zdunich for any closing remarks.
Thank you. This completes our year-end conference call. If you have any questions that you need to follow up on, please give me a call later today. Thanks for listening, and have a good day.
Ladies and gentlemen, this concludes today's conference call. You may now disconnect.