Pembina Pipeline Corporation (PBA) Q1 2015 Earnings Report, Transcript and Summary

Good morning. My name is Sharon, and I will be your conference operator today. At this time, I would like to welcome everyone to the Pembina Pipeline Corporation 2015 First Quarter Results Conference Call. [Operator Instructions] I'll now turn the call over to Mr. Scott Burrows, Pembina's VP Finance and Chief Financial Officer. You may begin your conference.

Thank you, Sharon. Good morning, everyone, and welcome to Pembina's conference call and webcast to review our first quarter 2015 results. I'm Scott Burrows, Pembina's Vice President, Finance and Chief Financial Officer. Joining me today is Mick Dilger, Pembina's President and Chief Executive Officer. For this morning's call, I'll start by providing a high-level review of our financial results, which we released yesterday after markets closed. Mick will then provide an update on Pembina's growth projects. Before closing remarks and Q&A, I will discuss our recent financings and financial position. I'd like to remind you that some of the comments made today will be forward-looking in nature and are based on Pembina's current expectations, estimates, judgments, projections and risk. Further, some of the information provided refers to non-GAAP and additional GAAP measures. To learn more about these forward-looking statements, non-GAAP and additional GAAP measures, please see the company's various financial reports, which are available at pembina.com and on SEDAR and EDGAR. Actual results could differ materially from the forward-looking statements we may express or imply today. I would also encourage listeners to review the news release, MD&A and financials we issued yesterday, which provide our full results for the first quarter ended March 31, 2015, as I won't go over each financial metric on today's call. This will allow us to move more quickly into question-and-answer period. Before I begin a high-level review of the first quarter, I want to first address the dividend increase that you saw in our news release yesterday. Our diversified asset base and fee-for-service business model provide Pembina with financial resilience even during low commodity price environment such as the one we're experiencing today. The solid results generated by the majority of our businesses, combined with our growing fee-for-service based cash flows over the next few years, led the Board of Directors to approve a 5.2% common share dividend increase. This new monthly dividend will be $0.1525 per share and will take effect as of the May 25 record date. This increase demonstrates our confidence in the stability in our cash flows and on our ongoing commitment to enhancing sustainable shareholder returns as we continue to grow and expand Pembina's business. Before turning the call over to Mick, I will quickly provide a high-level review of the quarter touching on each of the businesses. I'm happy to report that Pembina achieved solid operational results and continued to showcase financial robustness during the first quarter of 2015. Although on a whole, our financial metrics were lower this quarter compared to the first quarter in 2014, which was mainly due to the impact of suppressed commodity prices during the first quarter of 2015 compared to the significantly much higher commodity prices in the first quarter of 2014, we are pleased to report all-time highs for throughput and operating margin in both our Conventional Pipelines and Gas Services business. This is especially impressive given the environment that we were in, we are experiencing, and is demonstrative of the strength of the resource supply in the Western Canadian Sedimentary Basin, which are current -- which our current and growing business services. Another positive note is that our first quarter 2015 results are higher than our last quarter, being the fourth quarter of 2014, and is further demonstration of how our growing fee-for-service business will continue to provide stability in our cash flows and derisk our business. In Conventional Pipelines, throughput was up 14% and averaged 633,000 barrels per day during the first quarter compared to the same quarter last year. In February, the monthly average throughput reached the record of 652,000 barrels per day. The main driver for the increase was our Phase I Expansions which were placed into service in December 2013. Volumes gradually ramped out during the first quarter in 2014, so the first quarter of 2015 was more representative of run rate utilization levels. Higher truck terminal volumes and additional throughput from new connections and assets, including the Vantage Pipeline, also contributed to the growth and volumes. Further, we commissioned new storage facilities and pipelines, improving product batching efficiency also resulting in increased volumes. These factors contributed to operating margin of $98 million in the first 3 months of the year, which was 27% higher than the $77 million in the same period last year. We will see volumes further increase this year due to our recently commissioned Phase II crude oil and condensate expansion and our Phase II NGL Expansion, which is expected to be commissioned later this year. Mick will talk more about these projects in our growth update. Gas Services also realized higher throughput with average processing volumes increasing 29% in the first quarter of 2015 compared to the same quarter last year. Volumes were boosted because of our Resthaven facility, which was placed into service in October 2014, and our Musreau II facility, which was placed into service in December 2014. The strong operational performance lead to a 28% increase in operating margin, which came in at $37 million for the quarter compared to $29 million for the same quarter last year. In our Oil Sands & Heavy Oil business, we saw steady performance as expected, with operating margin coming in slightly higher over the first quarter of 2015 at $35 million due to additional interruptible volumes on the Nipisi pipeline. In the Midstream Business, operating margin was $113 million during the first quarter of 2015, which was lower than our first quarter of 2014. The decrease was largely due to our NGL Midstream Business, which was impacted by the significant decline in propane prices, where propane prices decreased by 50% quarter-over-quarter. Lower butane and condensate margins were also contributing factors to the decrease in this business. To a smaller extent, Pembina's crude oil Midstream business also contributed to the decrease in operating margin, which is mainly due to lower oil prices and narrow price differentials, slightly offset by higher volumes. Our Midstream results were also somewhat offset by an $18 million realized financial gain. Overall, I am pleased with the results so far in 2015, especially given the commodity price headwinds we are currently facing. Pembina plans to stay the course, and we remained confident current market conditions will not interfere with our medium-term goal of essentially doubling our EBITDA by $700 to $1 billion in 2018 depending on utilization rates as we bring our $5.9 billion portfolio of fee-for-service projects onstream. I will now pass the call over to Mick, who will give an update on how our growth projects are progressing.

Thanks, Scott, and good morning, everyone. I too am pleased with the overall operational and financial performance of Pembina during the quarter and the dividend increase our board approved. As Scott mentioned, subsequent to the quarter end, Pembina announced that we placed our Phase II crude oil and condensate pipeline expansion into service on April 24. The incremental 55,000 barrels per day added on to our Peace Pipeline will help alleviate volume constraints for our customers. I'm also very pleased to report that this project was completed on budget and with no lost-time employee injuries given the over 350,000 man-hours worked and over 1.8 million kilometers driven. I'd like to thank our teams for working so diligently on achieving such impressive execution as these projects are in no way easy to carry out. We are continuing to focus on completing construction of the NGL portion of the Phase II Expansion and expect it will be in service in the third quarter of this year. All regulatory and environmental approvals have been received and 70% of the total costs are secured. This project is tracking on budget. As part of our Phase III Expansion, we brought into service a 35-kilometer, 16-inch pipeline segment from Lator to Simonette in January. And subsequent to the quarter end in April, we also brought into service another 35-kilometer, 16-inch pipeline segment from Kakwa to Lator. Today, we have completed over 15% of the overall Phase III Expansion program, and it's coming along according to plan. Also on the topic of Phase III Expansion, we are continuing with our plan to construct new 24-inch and new 16-inch pipeline in the Fox Creek to Namao corridor. We expect these pipelines to have an initial capacity of 420,000 barrels per day and an ultimate capacity of over 680,000 barrels per day, which could bring our total capacity between Fox Creek and Namao to over 1 million barrels per day. The energy regulator, or the AER, has announced it has scheduled a hearing in July relating to this portion of the pipeline. According to AER guidelines, we expect to receive a decision within 90 days after the hearing is concluded, although my personal hope is to settle matters with stakeholders without a hearing. Our service date remains in late 2016 to mid-2017 timeframe depending on regulatory timing. We continue to progress our pipeline lateral program to aggregate new volumes on to our system by expanding our presence in Alberta and British Columbia. Subject to regulatory and environmental approvals, we anticipate our lateral in the Edson, Alberta area to be in service in mid-2016. We have also completed the Willesden Green-Alberta lateral and expect it to be commissioned later this month. Work is advancing on our Northeast B.C. expansion in Northeast British Columbia, and is expected to be in service late 2017 subject to regulatory and environmental approval. Previously announced in February, Pembina continues to expand the Vantage Pipeline system for an estimated capital cost of $85 million to increase mainline capacity from 40,000 barrels per day to approximately 68,000 barrels per day through the addition of pump stations and the construction of a new gathering lateral. The Vantage Expansion is supported by a long-term fee-for-service agreement with a take-or-pay component, and the gathering lateral is underpinned by a fixed return on invested capital agreement. Subject to regulatory and environmental approvals, we expect the expansion to be in service early 2016. In aggregate, Pembina now has approximately 760,000 barrels per day of crude oil, condensate and NGL under contract through our Vantage Pipeline, the recontracting of base volumes on our systems and our Phase I, II and III Conventional Pipeline expansions. Now on to Gas Services. During the first quarter of 2015, we continue to progress construction of our 4 gas plants currently under development. Our SEEP gas plant has all regulatory and environmental approvals, and we have largely contracted all engineering, fabrication and construction services. The plant site construction is 50% complete and is currently on budget and on time with an expected in-service date of the third quarter of 2015. Construction is also progressing well at the Saturn II plant, which is currently tracking on time for an in-service date of the third quarter of this year. I'm also happy to report that we anticipate this -- completing this project under budget. Our Resthaven Expansion, all major equipment has been ordered, and construction is expected to commence in the third quarter of this year. The associated gathering line is 50% installed, and all major river crossings completed. Pembina expects the gathering pipeline to be in service in mid-2015 and the plant complete in mid-2016. We have now received regulatory and environmental approval for the Musreau III plant, which is leveraging the engineering, design and execution strategy of our Musreau and Musreau II facilities. With all major equipment ordered and 40% engineering currently complete, we expect to bring Musreau III online in mid-2016. As I mentioned last quarter, I'm pleased to have previously reported that our Musreau II facility was placed into service in December 2014 and came in on budget and ahead of schedule by 1 quarter. Once these facilities come on stream, we expect our total gas processing capacity to reach 1.5 billion cubic feet per day, including ethane plus extraction capacity of 870 million cubic feet per day. Depending on gas composition, these volumes could result in 70,000 barrels per day of NGL that can be transported for additional total revenue on our pipelines, thus further support our Conventional Pipelines expansion plans. Moving on to our Midstream Business. At our Redwater site, all major equipment has been set for RFS II, module fabrication is finished and overall construction is currently 70% complete. The project schedule has slipped slightly, and we now expect to bring RFS II on stream in the first quarter of 2016 versus late 2015 as originally planned. Our RFS III overall project is tracking on budget and on time, with detailed engineering work underway and over 60% of long-lead equipment ordered. We have received regulatory approval and expect environmental approval later this year. Pending environmental approval, we expect RFS III to be in service in the third quarter of 2017. Once complete, our Redwater site will be the largest fractionation facility in Canada with a total of 210,000 barrels per day of capacity. Site preparation is ongoing at our Canadian Diluent Hub, or CDH. We expect -- we plan to phase in pipeline connections and storage once we receive further regulatory and environmental approvals, and we expect CDH to reach full connectivity and service offerings by mid-2017. Work is progressing at our storage and terminaling facilities in Toronto, Ontario, for a number of initiatives. We also signed a long-term agreement, subsequent to the quarter end, for one of our caverns [ph] at Redwater expected to be in service in early 2016. For our proposed West Coast propane export terminal at the Portland -- at the Port of Portland, Pembina's dedicated project team has conducted consultation with community, regulatory and special-interest group engagement and has completed 2 public hearings as well as significantly advanced detailed engineering design work to support a number of permit applications to be submitted through 2015. Subsequent to the quarter end, Pembina received an affirmative vote of the Portland Planning and Sustainability Commission to move the approval process forward to the Portland City Council. Based on current information with respect to timing, we expect a decision from City Counsel in mid-2015. Subject to receiving the necessary permits and approval, Pembina anticipates bringing the project into service in late 2018. The delay from the original and service date of early 2018 is due to additional civil work that was required on-site resulting from geotechnical factors. Overall, I'm very pleased with the progress we are making on executing our growth plans, and that on a consolidated basis our portfolio is generally tracking on time and on budget. I look forward to bringing multiple projects into service throughout the year, which will continue to grow our fee-for-service cash flows. Scott, over to you.

Thanks, Mick. So far in 2015, Pembina had 3 successful financings. In January, we issued $450 million of notes maturing in 2043 (sic) [2025] and $150 million of notes maturing in 2025 (sic) [2043]. And in April, we completed a preferred share offering for gross proceeds of $225 million. We also increased Pembina's unsecured revolving credit facility by $500 million to $2 billion and retained the accordion feature for additional $750 million at Pembina's option. As of May 5, we're approximately $245 million drawn on that credit facility. With our proven ability to access the capital market, Pembina continues to be well-financed with a clean balance sheet and maintains the financial flexibility to fund our $1.9 billion capital plan for 2015. In summary, we've had a good start to the year. Low commodity prices did impact our business for the first quarter. However, despite these challenging times, Pembina has performed exceptionally well, operationally, has maintained an impressive safety record and continued to make headway on capital projects. Given these achievements, we are able to increase our dividend by 5.2%. With the large capital program ahead of us, we are working hard to realize capital cost reductions of 5%, which would equate to $200 million to $250 million in savings on our remaining $5 billion of capital projects and further improve returns for our shareholders. Reiterating what Scott said earlier, Pembina remains steadfast in our goal of adding $700 million to $1 billion of incremental EBITDA by 2018 depending on utilization rates. And we continue to position ourselves to generate long-term shareholder value for years to come. In closing, I'd like to remind listeners that Pembina -- the Pembina's Annual General Meeting is scheduled for Thursday, May 8, at 2 p.m. at the Metropolitan Centre in Calgary. We look forward to seeing those of you who are able to make it. For those of you who are unable to attend, we will be webcasting the presentation. The details on how to access the webcast are on our website at www.pembina.com under Investor Center. With that, we'll wrap things up. Operator, please go ahead and open up the line for questions.

[Operator Instructions] Your first question comes from Rob Hope from Macquarie.

Maybe switching to the West Coast. If -- just wondering when we could potentially see the Portland project being sanctioned, given that we could get a positive announcement of City Council midyear.

Yes. We're relatively optimistic we will get a positive from the city. And that doesn't mean we're done the approval process though. And so the next step there is to assess the remaining approvals we need against the quantum of capital we need to invest to get those approvals. So I think it's just -- it's too early to say when we're going to be able to sanction that project. I just can't give you that exact timing yet.

Okay. And then maybe just on the economics surrounding that project. Do you have an estimated delivered cost that you can do propane on the tidewater?

We're just completing our class III cost estimate, so by next quarter, we should be able to provide some clarity on that. But a reminder that it is a fee-for-service type arrangement there, where we're able to charge out the fees for that project to the users.

Your next question comes from Matthew Akman from Scotiabank.

The dividend increase at this time, does that say anything about marketing that you feel the marketing business is sort of bottoming at a level that you have visibility? Or does it just say that you don't really even need so much marketing profit to generate dividend growth because of all the contracted growth in front of you?

Yes. The latter would be true. I mean, if you were at our Investor Day, Matthew, and you were -- we get up to 85% to 90% fee-for-service by 2018. And so the marketing upside, as it were, is not really factoring into the choice of dividend increase. I think what we're trying to do is signal the confidence we have in our fee-for-service growth and that we're hopefully heading towards more convergence between our dividend per share growth and our cash flow per share growth into the future.

If I could just ask a follow-up on marketing. Most of the marketing profit, as I understand it, has come from propane, at least on the NGL side, of course. With propane prices as depressed as they've been, in Edmonton especially, is that still a commodity that can be profitable from a marketing standpoint? And if so, is it going to be more of a sort of fee-for-service type profit? Or more commodity spread?

Well, in our frac businesses, there's, of course, 2 variables. One is, what we sell the propane for, and the other one is what we pay for extraction rates and power. Those are the primary inputs. So looking just at the propane price in isolation, I can't quite give you the answer. Suffice to say, we're not making a lot of money right now on propane. And if prices return to normal, we have upside. But we're not in a rush to get out of those businesses. We think that we are closer to the bottom end of the cycle. Although who really knows? And I think the signal that we continue to give the market is, as we contract and grow that business, it's all on a fee-for-service through RFS II and RFS III. So as I said, we're not rushing to get out of those commodity businesses. We like them, and when they make money, they make a lot of money. And we're -- at the -- we perceive at the lower end of the cycle, but going forward, we are providing that service as a fee-for-service offering rather than taking the commodity risk.

You're next question comes from Andrew Kuske from Crédit Suisse. Andrew M. Kuske - Crédit Suisse AG, Research Division: I guess the question is for Mick. And it just relates to your conversations with customers and how they have evolved in the last, say, 6 months. This -- obviously, in that period that we saw a dramatic fall-off in commodity pricing, and then we've seen a bit of rebound in the last 6 weeks. So could you just give us a sense of your conversations with the customers? Is it a sense of cautious optimism? Or they've more guarded at the stage, a bit doubt on the commodity rebound we've seen?

We have really not heard any -- a lot of stressful comments from them, whether it was right at the bottom or even positive comments more recently as things have improved somewhat. They are for the most part, especially the larger customers, just going about their business in the usual way. I think it's too early to say what the true reaction is, maybe we can have that discussion in the -- late in the third quarter or early fourth quarter when we see results coming out and how people are doing vis-a-vis their credit facilities and things like that. But so far, we're just moving forward with our plans. And the producers by and large seem to be moving forward with their longer-term plans. Andrew M. Kuske - Crédit Suisse AG, Research Division: Okay. This one also might fall into the too early to say category, but given the change of government, how do you think about just growth prospects? If there is royalty review process underway in Alberta when the government officially comes in? And let's put the changes -- prospective changes aside, do you feel there will be a potential bigger growth opportunity for your asset base in B.C. on the Montney side of the play in B.C. side?

Well, I mean, I think it's fair to say we were surprised with the amount of change in the government. And I, along with many Albertans, probably flipped on the NDP website to review what their platform was. And I didn't see anything too radical in there in terms of income tax changes, kind of brought us more into the what I would call average tax rates, provincial tax rates for corporations and for individuals. So that alone didn't scare me too much. The royalty regime. I think any new government would want to take a look at that. But I think it's important to remember for this government that the companies that really matter in terms of the oil and gas, the largest companies, they do have mobility of capital, and so they'll need the right economic environment to keep investing the billions of dollars in the province that they have been. But I think it's way too early to say that there's going to be mobility of capital. And so I'm cautiously optimistic that the basic tenets, other than the tweaks to the corporate tax rate, the basic tenets of the economy in Alberta will be unimpacted.

You're next question comes from Robert Kwan from RBC Capital Markets.

Just on the capital cost improvements that you talked about, or you first referenced in Investor Day. And then Mick, you had them in your comments here. The 5% target, I know were only a couple months removed from the Investor Day, but anything more to add? Directional color if you maybe looked at a few things? And either are you more optimistic? Less optimistic?

Robert, I'd say we're -- we are optimistic to date. We have seen approximately, call it, $30 million, $35 million in cost reductions. We also have indications on some of our line pipe ordering of potentially another $30 million. That hasn't been locked in yet because pipe hasn't been ordered. But we are starting to see some of those savings. So I would say that as a management team, we're pretty optimistic that we can achieve that $200 million.

Actually, I'd add that you will recall we have factored in 3% to 5% inflation. I mean, when we won these projects, the economy was red hot, and we, under the way we contract, do take the capital cost risk on a lot of these projects. So we did the right thing and baked a healthy inflation number and a historic inflation number, and we're just not seeing that. And so one way to think about it for you guys is if we just take that 3% to 5% inflation out of our cost estimate, then we're going to get there even without factoring in improved productivity and reductions in steel price. So I agree with Scott, we're cautiously optimistic that we can pull this off.

Okay, that's great. And then just looking -- last question here. Looking at the results here for the conventional pipe. You referenced higher non-firm service tolls, I'm also just wondering, was there any noticeable pickup in volumes? I.e., were you able to ship any non-firm service volumes on top of capacity that wasn't being used under take-or-pay contracts?

In terms of the volumes, we definitely were shipping interruptible volumes higher than take-or-pays. We also had higher volumes on a lot of our systems, even some of them that aren't contract, like our Drayton Valley System. So we did see an increase, not only in take-or-pay volumes, but also in interruptible volumes as well.

I guess where I'm going was, was it a material number? I.e. as you see people actually use the take-or-pay, will that eat into what we saw in the quarter here?

We wouldn't perceive that to happen. I think it's just going to be business as usual. I -- we don't really think the new contracts kicking in are going to measurably impact our volumes. What's going to measurably impact our volumes is the additional capacity that we're adding.

Your next question comes from Steven Paget from FirstEnergy.

Propane price crash in Western Canada, to some extent, has been a regional crash. Has Pembina been able to benefit from high propane price differentials? And how?

I think, Steven, I think some of the localized crash is due to the VAT quotient reverses, and there's higher cost to get to some of the those other markets. So I wouldn't say that we've been able to benefit from higher spreads. Even the Sarnia propane, which has been at a premium for most of 2014, that premium's come down quite a bit. And so I would say, no, we're not able to capture significant differentials.

There's been some discussion about what might happen if LNG in Northeast B.C. goes ahead. Would Pembina look to build some sort of NGL facility in Northeast B.C. that would bypass Edmonton? Or Redwater? Or would it continue to expand the hub at Redwater if necessary?

It's not impossible that, that could happen, Steven, but the economies of scale we have in Redwater and the access to the market is really quite outstanding. We did, a couple of years ago, look at -- because we have a presence out there anyway through Taylor, look at putting some frac capacity in B.C.. But we just couldn't find any suitable rail arrangements out of there. And so when we ran the math, it was just more feasible to continue the model that we've been building over the last number of decades. It's not impossible. I mean, it's intuitively obvious to take volumes that are already in B.C. and not bring them to Alberta and then take them back to export them. But once you -- when we did the math on rail and accessibility to rail, it just didn't work.

That's a very, very good detail. It is also that there is no -- it's not really possible to create underground storage in B.C.? [indiscernible]

Yes, it's all those things. And propane's only one of the commodities, remember. You also have to take your condensate, in some cases, your ethane and your condensate, and they all want to go to Edmonton. And so if you fractionate in, let's say in the Taylor area, most of your product still want to go to Edmonton. And so then, you have to shift spec-ed product in a pipeline to get it to Edmonton and not -- that creates a whole bunch of other problems. So notwithstanding, it seems intuitive. We did look at that a few years ago, and it just didn't work for us.

Your next question comes from Ollie Primak from CIBC.

I've got a couple of straightforward questions today. I guess, I'll start off. So first, with respect to Resthaven and Musreau II gas plants, is there any sort of ramp up in the cash flow profile?

Resthaven is, I think, it's 100% take-or-pay. So I think what you see is what you get there. All the capacity is spoken for and paid for. So there's not going to be ramp up there until the expansion comes into service. And Musreau II is, I believe, at 75 -- 100% contracted with 75% take-or-pay. And so the variability you'll see is, it's going to be no less than a take-or-pay revenue. But more than likely, somewhere between the take-or-pay 75% and 100% utilization. And so again, beyond that, nothing until the Musreau III comes on.

Okay. That's perfect. And recognizing it's still very early days with LVP expansions, what sort of utilization are you seeing in the Phase II expansions?

I'm not sure we're full, but we're-- we've -- in terms of the scope and capability of that pipeline, it is performing as we expected. And we did have significant volumes come on to the system. I don't know exactly the utilization of the entire system. Scott, do you know, anybody here know it?

No, I mean, we have seen a ramp up in volumes, because we did have volumes in apportionment and behind pipe. So we're pretty confident on the ability to move most of that product. We'll be able to say more on our next quarterly call.

Okay, perfect. And one more question if I could. I'm just wondering with the CDH, are there any -- can you comment on the status of any support for -- or contracts to support the CDH at this time?

Well, we're not really looking for contracts there. I mean, the contracts that we need are already on the pipeline. Realized, we have, I think, what, 680,000 barrels a day of contracted capacity now on the 3 phases put together. And to the extent that's condensate it's all being pointed at CDH. And so we're pretty sure the volumes will show up. The next step we're looking for there is our regulatory and environmental approvals as well as the distribution network to get that diluent to end-use customers. And in that regard, we have a small request for nominations, so we're asking industry where they want the Peace and other products that we'll have at CDH delivered. And that's really the next step. So it's -- we're not -- it's not going to be a take-or-pay type asset. It's going to be a fee-for-service asset. We get our comfort around the volumes being there because of the upstream commitments producers have made.

Your next question comes from Robert Catellier from GMP Securities.

You've touched on this a bit in responding to Andrew, but I'm wondering if there's anything you can say with respect to how you might change your capital allocation strategy in light of the new government and the perceived uncertainty that the royalty review will bring and the additional taxation.

Well, I mean, we're -- we don't have a lot of choice with the first $6 billion, that's all committed, and that takes us out into 2018. At which point, hopefully, our EBITDA will have doubled. And beyond that, we're -- I don't think we even contemplated changing our capital allocation strategy. I think we need to see what the government does and if the environment changes. Most importantly, we're going to need to -- we're in the service business, so we need to respond to our producers' needs. And if they decide to reallocate capital elsewhere, we'll respond to that. We're really a -- respond to where the capital or where the facilities are needed rather than dictate that.

Sure, that's make complete sense. I'm just looking, you talked about the $700 million to $1 billion, and that depends on part on utilization rates, that incremental ledge. And so I'm just wondering if you get, had any time to assess what your risk appetite might be to take on similar structure in areas like the Montney that might be disproportionately impacted by any royalty review. I know it's kind of speculative to look at that, but just generally, your appetite to take on projects that -- with that sort of volume upside.

Well, I mean, we're already actively growing our presence in the B.C., Montney, if I understand your question correctly. I mean, the Montney goes all the away from Fox Creek all the way up into deep into B.C. And then we have receipts. And our Northeast B.C. project is an example, it goes deep into the Montney. So again, if a major producer decides to drill more in B.C. because of the royalty regime in Alberta becomes less favorable, that's where we're going to have our receipts. And I think of note is our Phase III Expansion gives us a lot of flexibility as to where to take in those volumes. And generally, just hypothetically go down that line of thinking, if producers drill more in B.C., it's not the worst thing for Pembina because it's a longer haul. So it's a the higher toll for us. It's not necessarily immediate down sides. But again, our hope is that the royalty regime remains stable and sensible for producers to keep making that capital allocation decision in Western Canada and in Alberta.

We have no further questions at this time. Mr. Dilger, I'll turn the call over to you.

Well, thanks, everybody. Just, the AGM is on Friday. I think I misspoke and said it was on Thursday at the Met Center at 2:00 p.m. And hopefully, you can join us in person or dial-in. And in closing, thanks to our staff for bringing in Phase II safely. And thanks to shareholders for their ongoing support. We'll see you on Friday.

This concludes today's conference call. You may now disconnect.