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Pembina Pipeline Corp
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Good day, and thank you for standing by. Welcome to the Pembina Pipeline Corporation 2021 First Quarter Results Conference Call. [Operator Instructions] Please be advised that today's call -- conference is being recorded. [Operator Instructions] I would now like to hand the conference over to your speaker today, Cameron Goldade, Pembina's Vice President, Capital Markets. Please go ahead.
Thank you, Crissy. Good morning, everyone, and welcome to Pembina's conference call and webcast to review highlights from the first quarter of 2021. On the call with me today are Mick Dilger, President and Chief Executive Officer; Scott Burrows, Senior Vice President and Chief Financial Officer; Harry Andersen, Senior Vice President and Chief Operating Officer, Pipelines; Jaret Sprott, Senior Vice President and Chief Operating Officer, Facilities; Stu Taylor, Senior Vice President, Marketing & New Ventures and Corporate Development Officer; and Janet Loduca, Senior Vice President, External Affairs and Chief Legal and Sustainability Officer. I'd like to remind you that some of the comments made today may be forward-looking in nature and are based on Pembina's current expectations, estimates, judgments and projections. Forward-looking statements we may express or imply today are subject to risks and uncertainties, which could cause actual results to differ materially from expectations. Further, some of the information provided refers to non-GAAP measures. To learn more about these forward-looking statements and non-GAAP measures please see the company's management discussion and analysis dated May 6, 2021, for the period ended March 31, 2021, which is available online at pembina.com and on both SEDAR and EDGAR. I will now turn things over to Mick to make some opening remarks.
Good morning, everybody. I hope you're all doing well and enjoying the recovery of our sector. As you may have noticed from the introduction and as we announced yesterday, Pembina has recently undertaken certain executive changes. Two of Pembina's long-standing officers; Paul Murphy, Senior Vice President and Corporate Services Officer; Jason Vion, Senior Vice President and Chief Operating Officer, Pipelines, retired at the end of March. As a result of these retirements, Janet Loduca has been promoted to Senior Vice President, External Affairs and Chief Legal and Sustainability Officer; and Harry Andersen has been appointed to Senior Vice President and Chief Operating Officer of Pipelines. On behalf of everyone at Pembina, I congratulate Paul and Jason on their retirement and thank them for their decades-long contributions to Pembina's success. I congratulate both Harry and Janet, and I'm excited to work with them in their new roles. As Scott will discuss more fully in a moment that in the first quarter 2021, Pembina delivered strong financial and operating results, reflecting increased commodity prices and sales and rising volumes on many of the systems and facilities. As we have talked about for each of the past few quarters, we continue to see steady increases in physical volumes on our systems, and we actually reached prepandemic levels in April. With many systems previously operating near take-or-pay level throughout the second half of 2020, Pembina is beginning to realize the anticipated benefits of its operational leverage or torque, with incremental volumes providing higher margins. Stronger commodity prices also drove higher sales volumes and margins in our marketing business. Strong fundamentals in marketing were, however, offset by realized losses from our -- our hedging program. In conjunction with strong first quarter results, Pembina is celebrating a few recent developments. The first is the start-up of our Prince Rupert terminal, or PRT. Dry commissioning of PRT was completed in March, and we have begun loading propane onto vessels in April. So far, 2 vessels have departed PRT destined for international markets. I'm also pleased to announce that we have entered into a 1-year agreement with a subsidiary of Mitsue, whereby they will purchase substantially all of the post commissioning cargoes shipped from PRT with the propane being primarily destined for Northeast Asia. It has been years in the making and the start of PRT represents a major step forward in providing new market solutions and helping add incremental value to the commodities our customer sell. Alongside Pembina's unit train capabilities, PRT will link the rest of our natural gas liquids infrastructure in Western Canada with growing demand markets throughout the world, with the majority of the increased value flowing to those customers within Pembina's marketing pool. PRT has been a real ESG success story as well. Working together with the community, government and First Nations, Pembina was able to transform and repurpose a contaminated site on Watson Island, B.C. and now moves propane off the West Coast. Pembina invested approximately $12 million in remediation activities, and together with the city of Prince Rupert, removed a toxic and abandoned pulp mill replacing it with key income-generating assets that will have lasting benefits for all stakeholders and that the community can be proud of. Secondly, we are also pleased to have signed our first renewable power deal representing another concrete step towards delivering on Pembina's carbon stand by lowering the emission intensity of each of our businesses. We have signed a long-term 100-megawatt power purchase agreement, or PPA, with a subsidiary of TransAlta Corporation that supports development of 130-megawatt Garden Plain Wind project in Alberta. The PPA provides significant benefits to Pembina, including securing post -- sorry, cost competitive renewable energy and fixing the price for carbon of the power Pembina consumes. Further, the PPA is expected to generate approximately 135,000 tons of CO2 equivalent emission offsets annually or an estimated total of 1.8 million tons of C02 equivalent emissions offsets. Initially, Pembina will use the offsets to reduce its own emissions with the option to sell or bank future offsets for other uses. The combined emissions reductions available from the PPA and cogeneration facility currently being constructed at the Empress facilities represent approximately 7% of Pembina's 2019 reported greenhouse gas emissions. Pembina has committed to reducing the carbon intensity of each business it operates. And by the end of 2021, we'll have taken on concrete action in this area by publishing 5-year emission targets. Finally, Pembina, through its joint venture Veresen Midstream safely completed the start-up of the Hythe developments at the existing Hythe gas plant. After a challenging 2020, I'm pleased to see us deliver a strong start to the year with positive momentum developing on many fronts. With that, I'll pass it over to Scott.
Thanks, Mick. Pembina reported strong first quarter adjusted EBITDA of $835 million, consistent with the same period in the prior year. The first quarter was highlighted by increased marketed NGL volumes and higher margins on NGL and crude oil sales, combined with new assets placed into service and facilities and higher supply volumes at the Redwater Complex. These positive factors were largely offset by lower interruptible volumes on certain systems and pipelines, an increase in realized losses on commodity-related derivatives and higher general and administrative costs and other expenses, largely driven by an increased long-term incentives, offset by lower salaries and wages and lower acquisition-related costs. The increased mark-to-market and long-term incentives was driven by an increasing share price in the first quarter of 2021 compared to a decreasing share price in the first quarter of 2020. Fundamentally, our marketing business was particularly strong this quarter, excluding the realized impact of commodity-related derivatives, first quarter adjusted EBITDA in marketing and new ventures improved $140 million or 368% relative to the first quarter of 2020 and $97 million or 120% compared to the fourth quarter of 2020. The underlying marketing business improved significantly. However, our frac spread hedges and other commodity-related derivatives offset some of the increases. Pembina reported strong earnings in the first quarter of $320 million, consistent with the same period in the prior year. In addition to the factors positively impacting adjusted EBITDA, as I previously noted, earnings were positively impacted by a decrease in net finance costs due to lower foreign exchange losses. Earnings were also positively impacted by a decrease in current tax expense as a result of lower taxable income and a reduction in the Alberta corporate tax rate. Earnings were negatively impacted by an unrealized loss on commodity-related derivative financial instruments in the first quarter of the current year compared to significant gains in the first quarter of the prior year and a lower share of profit from Ruby. Total volumes was 3.5 million barrels per day in the first quarter, down only slightly from the same period in the prior year. Lower interruptible volumes in pipelines due to reduced upstream activity in 2020, partially offset by higher supply volumes at the Redwater Complex, higher seasonal volumes on Alliance pipeline and higher interruptible volumes on the Ruby pipeline. While volumes in the first quarter were down slightly over the first quarter last year, the real story, as Mick noted in his opening comments, steady rise in volumes over most of 2020 and now into 2021, with physical volumes in April reaching prepandemic levels. Given the year-to-date results and the outlook for the remainder of the year, Pembina is reiterating its previously disclosed 2021 adjusted EBITDA guidance of $3.2 billion to $3.4 billion. Pembina's 2021 capital program is fully funded by cash flow after dividends and towards the middle and upper end of the guidance range, excess cash flow will be available for debt reduction, dividend increases or opportunistic common share repurchases. During the first quarter of 2021, the timing of certain cash payments and receipts resulted in a draw on working capital and consequently, no excess discretionary cash flow was available. As the year progresses, Pembina will continue to assess the optimal allocation of excess discretionary cash flow based on the outlook for new capital investments beyond 2021 and the prevailing price of Pembina's common shares. Finally, I am pleased to note that last week, DBRS Limited upgraded its ratings to BBB high in respect of Pembina's senior unsecured medium-term notes. This upgrade further validates the strength of Pembina's balance sheet, something we have worked very diligently to maintain, in particular, over the past year. I'll now turn things over to Mick for his closing comments.
Thanks, Scott. The improvement we have seen in commodity prices resulted in a strong first quarter, but it also supports our constructive view of the future activity in the WCSB. We continue to believe that a post-pandemic economic recovery will drive higher activity in the basin, which we believe is only beginning. Higher prices are allowing our producer customers to generate higher-than-expected cash flow which is currently driving the aggressive debt reduction and shareholder returns. Ultimately, we expect producer to sanction new drilling activity and Pembina is well positioned to capitalize on that activity. Particularly to serve growing volumes in the Northeast B.C. Montney and Alberta Duvernay areas. New infrastructure, including the Trans Mountain pipeline expansion, LNG Canada, Enbridge's Line 3 replacement and Pembina's and other third-party NGL export terminals are expected to collectively improve relative pricing for Canadian hydrocarbons and support the future growth in the WCSB. As well, the government of Alberta's continued and increasing support in commitments related to the petrochemical industry, including various incentive programs are expected to drive higher ethane, propane and butane demand in Western Canada. We have named these factors collectively Advantage Canada, and we expect them to generate ample opportunities for Pembina. These opportunities include the reactivation of the currently deferred Peace Pipeline Phase 8 and 9 expansions and the expansion of Prince Rupert terminal as well as our $4 billion portfolio of unsecured brownfield and greenfield projects. We continue to look at 2021 as a turnaround year with Pembina returning to its traditional growth trajectory by 2022. Before we wrap things up, I want to inform you that once again this year, in light of current circumstances related to pandemic and associated health and travel restrictions, Pembina will not be holding its annual Investor Day in our typical May-June time slot. We continue to evaluate our options for holding this event either virtually or in person in the fall of this year. We do, however, hope you can join us for our annual meeting of shareholders, which will be held today at 2:00 p.m. Mountain Time, 4:00 p.m. Eastern Time. Again, this year, it will be a virtually-only meeting conducted via live audio webcast. Participants are recommended to register for the virtual webcast at least 10 minutes before the presentation start time. For further information on Pembina's virtual AGM, please visit the shareholder information page under the Investor Center tab at www.pembina.com. We would once again like to thank all of our stakeholders for their support. With that, we'll wrap things up. Operator, please go ahead and open the line.
[Operator Instructions] Our first question will come from the line of Matt Taylor with Tudor, Pickering, Holt & Co.
I wanted to start first with your bullish comments there on physical volume improvement and customer behavior. Can you help bridge the gap with what you're seeing and hearing from customers on new capital being put to work at the drill bit versus what investors are seeing in terms of producers still at maintenance levels? Is the torque you're seeing and expecting coming from certain areas or customers?
We're seeing growth in Northeast B.C. in the Cardium. Our NGL business volumes are quite good at Redwater. And so you're seeing it throughout. I mean, we did reach prepandemic levels in April. Certain areas, Drayton Valley being very strong. And of course, that all feeds our marketing business as well.
Okay. Great. And then just as a follow-up to that, too, it looks like your EBITDA guidance is predicated on levels compared to last year versus new growth. So can you just frame how this torque fits into that EBITDA guidance? And then -- and even potentially restarting projects?
When we set the guidance, we had a much different price deck. And I think most people on the globe would be pleasantly surprised that the price of oil is in the mid-60s, and propane price, I think, is $0.90 at Belvieu and gas prices are sneaking up on CAD 3 up here, CAD 2.70, I think it is. So we're seeing something we don't see very often, which is all 3 volume streams working at the same time. Normally, at least one isn't working or many times, 2 are not working, and we're seeing all 3 working. And so notwithstanding, I think the sense you have is people are mainly focused on debt reduction. I would agree with that. But people are starting to return to the drill bit quietly. And we think that will accelerate as people meet -- I'm reading the very lovely reports of our customers, and they're paying down debt in record amounts. And their share prices are going up, which makes me think they're only going to buy back their shares for so long before they return to growth. And they've been we've been assessing where to grow. And so I think we can assume they know exactly how to maximize their capital deployment. We think that's coming later in the year and into next year. And we sit with still a good amount of capacity. We're just kind of breaking through that take-or-pay level. And it's going to go to us. So we are pretty excited about where we are in the first quarter. I mean, yes, we were slightly overhedged. I wouldn't do anything differently. We put on those hedges in the second wave of the pandemic, I think that was prudent. I think you guys pay us to be careful and we were. But a lot of those -- well, over half of our hedges were discretionary, not part of our nondiscretionary program. Those all end at the end of the quarter. And we're pretty optimistic being at prepandemic volumes and sensing the build starting to happen with -- if these prices keep up, it's going to get exciting.
Mick, maybe just to clarify your comments there, like my understanding is that guide is looking at 2020 levels, and if there's an incremental interruptible in the system or various other pieces of your business that see improvement. So is it really what you're framing here is torque that gets you to the top end of the guide and beyond as opposed to the level that looks achievable, at least from your base business perspective thus far this year?
We thought long and hard about what we would say about the guidance range. I think it's just not prudent in the first quarter to be looking out to the fourth quarter. This is a very uncertain world. We're really pleased with where we are in the first quarter, both from a volume and from a pricing perspective. I think our marketing business is very well situated, but we just don't think it's prudent to predict in this world that you're going to go through the top end of the guidance range. So we've stayed in within the guidance range. We're comfortable there.
Yes. Matt, maybe I'll just add a couple points of color. I think unhedged, the first quarter would have set us up nicely to move into the upper half of that range. Mick pointed out, obviously, we had some incremental discretionary hedges that lowered that a little bit. As we look forward, we're still facing a few headwinds like FX. Obviously, FX has come down pretty materially from the budget. And so that's a headwind. And you got to remember that the back half of the year, we'll see lower contributions from Ruby with those contracts generally rolling off midyear. Now I think that's offset by, as Mick said, the strong physical volumes throughout April. We've also seen the commodity curve generally been in backwardation through most of the year. But every month, we move along, it tends to get pushed out a month or 2, so I think our view is that the commodity curve should continue to remain robust throughout the back half of the year. But that's slightly different than what the current forward curve is showing us in backwardation. And of course, we still have our focus from 2020 on maintaining costs and keeping those cost savings in 2021. So I think we're feeling pretty optimistic, but it's just a little too early in the year to revise guidance.
Our next question comes from the line of -- from Jeremy Tonet with JPMorgan.
Just wanted to dive in, I guess, a little bit to the moving pieces here. I was wondering for hedging, if you could provide a bit more color on what's locked in for the back half of the year, just how much open versus hedged at this point? And how do those hedges look, I guess, relative to the strip? I mean, as you noted there, I think there was, what, $88 million of upside that would have been captured without hedging, and of course, it's prudent to hedge, but just trying to get a sense for how the back half of the year could look versus the current strip given your hedging book?
I'll turn it over to Scott in a minute. The hedging program at the highest level is really just the nondiscretionary program that we have, which is kind of half of our NGL business and excluding Aux Sable. So we stopped the discretionary -- or sorry, the nondiscretionary part effective this quarter, realizing that commodity prices are looking much more robust than we anticipated, say, in the fourth quarter of last year. Scott, do you want to add anything to that?
Yes. Sure, Jeremy. When you look out, based on the current strip, we still have the frac spreads in place that we put in place in 2020. So those are obviously underwater. And again, just as a reminder, for the rest of the year, it's only on the frac spread business. The winter storage or Aux Sable are unhedged. Based on the current strip, we're looking at forecasted losses in the neighborhood of $20 million to $25 million, on the NGL side of the business.
Got it. That's helpful. And then with -- the corporate expense is a bit higher than what we expected this quarter. I guess, what should we be thinking about as a run rate? I appreciate there was some LTIP noise, some retirement noise in there that made it a bit higher, but just thinking about what's kind of normalized at this point?
Yes. Jeremy, I think in the first quarter, obviously, as you pointed out, there's the mark-to-market on some of the incentives. And by way of background, ease to provide a sensitivity that a $1 change in our share price is roughly $1 million of G&A, just as a sensitivity. And so with the share price going from $32 to $38 at quarter end, that obviously had an impact on the quarterly results. We also had some onetime consulting fees that we're working on as we work through some of our optimization initiatives. So there's a few -- there's a little bit of noise in the quarter. On the long run, we're probably looking at roughly $40 million per quarter -- sorry, yes, $40 million per quarter on the corporate costs.
Got it. Okay. So it doesn't seem like corporate is really that different maybe than what you budgeted for the year? Because if I'm looking at just pipeline and facilities segment, that's $800 million for this quarter. And if I annualize that without even thinking about marketing, that gets you 3.2%, the bottom end of the range. And if you talk about the kind of the improved producer outlook branded there are some roll-offs, but it seems like quite well positioned within the range. So just wondering, is this first quarter kind of match your -- what you were expecting here? Or are there any kind of benefit that maybe wouldn't repeat in subsequent quarters?
I think, again, I would just want to temper what I'm about to say that it's early in the year. But we think volumes are going to continue to build and marketing is going to continue to improve and that we'll be able to manage our G&A at kind of budgeted levels, which I think, is around $300 million total for the year.
Yes. Jeremy, I should -- we just got to make sure we're talking apples-to-apples. My $40 million was roughly corporate. We also have, obviously, G&A within the businesses. So on an absolute basis, aggregate, it's about a $60 million to $65 million per quarter.
Our next question comes from the line of Ben Pham with BMO.
On your wind project, you announced with TransAlta, I'm just curious, how do you weigh or consider the relative difference between building the win yourself versus getting somebody else to do it? Because you've done some of the co-gen stuff in-house. So I was curious how you look at that relative difference?
We just look at it like any other project. With that particular project, as you know, you may not know, we have a small wind project already that we got with Veresen. I think it's 20-megawatt project. We look at like any capital allocation decision. We're learning, we're studying it. We do have an option on that wind farm to participate up to 50%. But at this time, we've decided not to allocate our own capital to it. But we do have a huge demand of power. So we have big economies of scale. We can develop strategic relationships for wind power. And then we're leaving open the auction to participate in that and self-supply to a point. But at this point, it has not attracted capital. All right.
And there is some reference to rising power costs in the quarter, so that's the Alberta power price. Can you remind me, is that -- do you recover that in your business? Does it win your EBITDA instead? And then maybe just an overall comment on inflationary pressures you're seeing any sort of protections you have there?
Yes. Generally, our variable costs, well, almost to a very large degree, our variable costs flow through. The only place they don't are in our extraction business, where -- like our straddle plants where we warehouse that power cost and that's one of the reasons we're building cogeneration at all of our big plants as we can lower, both our emissions and our -- and take kind of control over our future prices and have electricity aligned with gas pricing rather than with grid pricing.
And then what about trade labor, steel, as you start to build the Peace expansion? Is there anything to consider on inflationary pressures potentially?
Not right now. Really, the -- if you think back about our largest projects like Phase 7, we bought the steel prepandemic, so that was sitting -- the pipe was sitting in inventory, recall, we had invested about $300 million. That was largely for the tangibles. And so that was all hedged at yesteryear's pricing. And most of our big projects are completely locked in. So we locked a lot of that cost in at a very favorable time actually on the heels of Keystone XL being canceled. We -- our skilled staff locked in a bunch of costs on that, Harry?
Then on the steel side -- that's a good answer, Mick. On the labor side, we're seeing, frankly, a really positive trend from our end. We have our contracts in place with 2 mainline contractors on the 2 spreads for say Phase 7, and we've seen really directionally good pricing on both the mainline contracting and then the HDDs that need to happen as well. So very happy with it as we sit here today.
Your next question comes from the line of Linda Ezergailis with TD Securities.
I'm wondering, as we look at the energy transition, I think most people view some of the political and economic constraints is dictating the pace as to be more of an evolution than a revolution. But I'm wondering if there might be some opportunities to accelerate your journey through either potentially acquiring, divesting or repurposing certain parts of your business or assets. I'm thinking specifically of maybe carbon capture or hydrogen. And maybe even purchasing late-stage development technologies or expertise that you might not have currently. Can you comment on what you might be seeing out there that would kind of fill out some of the blank spaces in your long-term strategy and vision?
Sure, Linda. We're thinking a lot about that. We don't really think we bring anything to solar that -- what things does Pembina bring to solar, not much. To wind limited again. And hence, we're partnering with people rather than building wind ourselves. But when it comes to carbon capture, we are running a pilot at Redwater, that's early stages to capture the CO2 from Redwater to see how all that works. We do currently already produce hydrogen. So that's within the skill set. So the whole -- that whole field of electric generation from gas and then sequestering it and we're good at all parts of that. A carbon capture system is really an aiming train that we have and operate the transportation, I think, through pipes that speaks for itself. And then the injection, the industry has been injecting acid gas for decades. So we're really good at that. So we have all the skills. And you're right, we do have a great footprint, great right-of-way that we can leverage. So we're thinking a lot about that. And when you think about supplying CO2 to EORs, most of the great EOR targets are within our footprint. And so if -- whether we do it or someone else inject CO2 into the Cardium, which is one of the best reservoirs are up in Swan Hills or down in Bonnie Glen area. That all gets returned tripped on our facility. So we kind of have an advantage in that area, and we're -- it's one of the things to spending a lot of time on right now.
Maybe also on a slightly separate note. You mentioned that you're reviewing your hedging profile. There's a lot of change going on in the industry, and there's a lot of change in your asset mix as well with your recent LPG export capabilities being quite notable on that front. Can you talk about how the hedging might evolve to reflect all of these changes going on? And whether that might create opportunities to either increase your exposure as you integrate along the value chain to commodity prices or reconsider your financial guard yields and the level of contracting that's appropriate.
We like our guardrail still. We just recently finished a strategy session with our Board. They're very supportive and I look forward to the AGM kind of reviewing all that this afternoon. But those guardrails served us really, really well. I mean, we pretty much hit our midpoint of our guidance and set -- if you zoom out, we actually had a record year for EBITDA last year, and that's really the diversification, the guardrails and all those things. So very pleased with how that served us. And sometimes, it bites you like with our first quarter hedging losses. But we get paid to produce steady and growing dividends, and we're good at that. And that's why people buy the stock. So we're going to keep going. As it relates to hedging and Rupert, recall, only 1/4 of those volumes are our proprietary volumes, 3 quarters through our marketing pool, our producer volumes. So they're the ones who are going to get this great pay price. We'll get some. They'll get a lot. And we differentiate ourselves, I think, from competition by bringing customers markets, customer volumes to markets rather than just our own. And that will start to flow through, and there's going to be some smiles on people's faces when they get the pay netback. So there isn't really a ton of incremental hedging to do there, on Rupert. From our perspective, it's just a nice diversification beyond Edmonton, Sarnia, Conway and Belvieu, just have this brand-new new market. And our off-taker reflects the way we want to go, it's to slowly go more global and have some demand for customers.
Our next question comes from the line of Robert Kwan with RBC Capital Markets.
To start with the conventional pipeline system. And first in the near term, you talked about record volumes in April. I'm just wondering if you can square up because I know you report revenue volumes, but how did physical volumes look in Q1? And how is that squaring up with your comments for April?
Yes. So on a physical basis, Robert, I think we saw a pretty steady increase throughout the first quarter, especially in March, where we saw volumes just about get back to prepandemic volumes. We've seen that strength continue throughout April. In fact, April physical volumes were in the neighborhood of, call it, 2% to 3% above where we saw in March. And actually, April physical volumes on the conventional system, were almost back to all-time highs, in line with where we exited 2019. And in April, volumes were above where we saw any monthly volume in 2020. So we're continuing to see strengths on the conventional pipeline system.
Yes. And just a reminder, Robert, like we're -- those are only attracting a small fixed cost burden. As you know, the variable costs flow through, and every barrel gathered is a barrel marketed. So we've got great torque here from this point forward.
And Mick, I think that's probably what you were getting at. So not only do you have the physical volumes on the pipeline system, but what percentage of those incremental volumes? Do you have that further torque of their feeding into Redwater, I'm not sure if the contractual take-or-pay levels are similar but as well, the ability for you to take that barrel and then make a bunch more money marketing in such.
For oil, it's very highly correlated. Almost every role that we bring in is a barrel marketed, for NGL, not quite as much. But I think 1/4 of the barrels roughly coming out of the back end of Redwater belong to us as well as all the frac spread barrels, right, at Empress, at Taylor, and so there, we're fully exposed, and this is a good time to be exposed. Go ahead, Jaret.
Robert, it's Jaret here. I just wanted to add that we're also seeing a fundamental shift on where our customers are ultimately drilling. They're moving away from that really volatile oil, very liquids-rich condensate into the gassier space with AECO and Chicago pricing staying strong. And with that, we're also seeing record 30-day and 180-day IPs on the gas side. Like, if you look at any reports now, they're just phenomenal rates, like $15 million, $20 million a day for a sustained period. So with that, what's not changing is the richness of the NGLs in the gas. So the more gas that we're seeing through our physical processing plants. I think roughly on a quarter-to-quarter, Q4 to Q1, we saw an incremental $200 million a day of physical volume going through our gas processing assets. Obviously, with the frac spreads being very strong, we're seeing a lot of NGLs come. Obviously, those obviously flow through conventional into Redwater and then ultimately, through our marketing business, which that's kind of that torque that Mick was talking about. So you're seeing the 2 things, the change of the types of wells and the increase of the volume.
Got it. Can you talk about within conventional as well the discussions that you are having with customers and specifically thinking about how you bring back Phases 8 and 9. You did mention that the customer contracts are still there. But can you also frame the discussions? Are you seeing any slippage now that caps is going forward? And if you have any comments as well with respect to the Northeast B.C. Connector project filing and what that might mean for you?
We're advancing key conversations, Robert. And we'll stay with the guidance we provided earlier this year that by the second half of the year, we'll be able to say something about Phase 8, 9 as well as the Rupert expansion. But we are on track to make some comments like that later in the year. It's just a little bit too early.
Just generally speaking, are you seeing, though, the outlook is more of a rising tide or more of a 0 sum game?
We are very comfortable that we can announce those projects later in the year and that they'll be very well anchored.
Robert, the way I think about it is it's really threefold. Jaret absolutely nailed it when he talked about HVP volumes started. So that's the first piece. We -- on the conventional system, we really started to see early in the first quarter, a rise in HVP volumes across all our systems. And then what came secondly was a corresponding rise in LVP volumes. And if you have a look at Drayton Valley in particular, they are just above in April prepandemic levels. So it's been really positive. The third thing we've been watching is we've been watching how volumes respond because we're right in about the middle of breakup. And the volumes have been really strong throughout the middle of breakup. And then the fourth thing is in our customer conversations, customers have been focused on getting to their take-or-pay levels during the first quarter. And conversations are now starting to return to additional volumes above that. So we feel really positive directionally for those 4 reasons, where we're going. And I think we also feel confident speaking into the mic, in the back half of the year in Phases 8 and 9.
Yes. The one intricacy that maybe people don't fully understand in Northeast B.C. is the system that reaches into the heart of NEBC is a cost of service system. And so as the customers fill that, their per unit tolls drop. And so that system gets ever more competitive. It used to be a pretty expensive system when PETRONAS anchored it, what, 5 years ago. And now it's getting super competitive as it fills and as we consider looping it for not a lot of money. So the customers up there are creating their own future and driving down their own fees. And so that's a key pipe, and it's a really key competitive advantage that customers have really created for themselves up there.
And then when you look at Northeast B.C., Robert, I think we all know that 2,000 and 3,000 or 5,000 barrels isn't going to do it. You have to have a material volume. And so we're working hard with those customers that have that, and we feel really confident directionally.
Okay. And then just to finish here, any commentary, whether it's volumes and/or pricing, especially just comparing to the 2020 year just for the NGL year here?
Yes. I mean, I'll turn it over to Stu, yes, but I mean it's -- the pricing now is like way better than last year. I think I'm just trying to remember my AGM numbers, but I think it was $0.50 last year, and we're at $0.90, Belvieu. I think those were the numbers that I'm going to present this afternoon. So it's -- yes, gas prices are a little more. But you're talking $2 roughly to maybe $2.70. So you've got a double, let's call it, rounded a double on NGL pricing, and you've only got a 50% increase in gas pricing year-over-year. So that's a lot to us. So we're -- I don't know where exactly we're hitting to in terms of the full year, but we're way ahead of where we thought we'd be in the first quarter.
Robert, I won't add a lot more. I think Mick's covered it. We had a great gas recontracting, our NGL recovery at our facilities when we're out securing gas. So we're really, really pleased where we are. I think we've already covered. We're seeing strong pricing. There will be some softening through the summer months as we go. But we are expecting to come back with very, very strong pricing in the fourth quarter. But across the board, some significant improvement over 2020 and excited about where we're going.
Right. And sorry, I was just asking about on the procurement side. Did you -- were you able to capture similar volumes and -- with headline NGL prices moving higher, are you seeing a similar in these percentage shifts in your procurement cost?
On the buy side.
On the buy side, yes, we paid up obviously with the pricing going up there. But again, it's not substantially different. So we were very, very pleased with our procurement of the gas on the gas side of where we ended up.
Our next question comes from the line of Chris Tillett with Barclays.
I guess, maybe just to shift gears here a little bit. Can you talk about the progression of Phase 8 and 9, how the discussions are going there? And then the contracts that you have in place that you mentioned in the release, are those with new customers or are those sort of expansions of contracts with existing customers? Just curious to hear sort of an update on that.
We're doing the engineering for those projects. As you saw with Phase 7, we've kind of delaminated Phase 7 a little bit. I mean we took a lot of costs out of 7. A lot of it was outright savings, some of it was scope. And so we're getting a little forensic on 8, 9 and maybe 9 goes before 8, we'll see. So we're trying to mix and match that. The tricky part is you only get to put the pipe in the ground once. And so what size you put in. And that's kind of what we're waiting for with to see which remaining anchor tenants we can land, and that will drive the physical design. So we're carrying different options. But the original customers -- I mean, they're signed. So they remain in place. But there are some very exciting developments up in Northeast BC, I'm sure you're all aware of them, and we're working hard to capture those before we announce exactly what Phase 8 and 9 look like.
Okay. And then obviously, you sort of need to know the sizing there before you can have a better grasp on capital expectations, but is there anything you might be able to tell us at this point in terms of where those might land relative to prior expectations?
I think that if things work out, we'll have possibly a lot more volume and a lot longer runway to growth there. That's kind of what we're seeing right now than we thought before. Jaret, go ahead.
Well, I guess, Harry talked about -- Harry talked about some of the procurement, et cetera. Yes, there is inflationary pricing, but I think we're making excellent headway on driving down our overall diameter branch mile cost as well.
Yes. Let me summarize it by saying we believe NEBC is more exciting than we thought when we FID-ed at the first time.
Okay. Great. And then I guess last one for me is obviously, the last 6 months have seen quite a bit of M&A activity in Western Canada, I guess, particularly and specifically in areas that are served by the Peace system. So would just be curious to know kind of your thoughts about where in that cycle you think we are today? And how you think the M&A impacts you guys moving forward?
Can you just specify what kind of M&A, you mean like loose assets, corporates or just in general?
Yes, sort of all of the above, I guess.
Sure. I mean, we're -- we've got a great value chain. And so we normally have kind of embedded advantages when it comes to loose asset purchases. We're always on the lookout there, of course. We've really focused through 2020 on our profitability, our return on invested capital. And I think the full impact of that will start to show in 2022. So we're still very focused on cost. And I think we took about $150 million out of our cost structure. Last year, we're working hard to maintain that. And so that's our primary focus. As our share price comes up, our currency improves, more things become possible. But we are right now focused more on profitability and that torque as we've been trying to message. When we fill off existing assets, it's almost infinite return, and we look absolutely outstanding, if we can improve our utilization, say, from 75%, 80% to 90% to keep our costs in check, we just sync, and that's our primary focus.
Right. Okay. That's helpful. I think, I guess, maybe just to clarify, I meant more how has the upstream M&A impact your assets?
Positively, like we -- from a counterparty credit, we've seen -- like with the Arc70 merger, we had -- they became investment-grade, they became more capable. They've all taken their debt down, like I'm looking across the universe, everyone is just getting after their debt. I mean I looked at CNQ's released the other day and so that's really positive. We tend to see the biggest users who have huge plans. They like dealing with real pipe and -- that's in the ground that they know they can rely on. And so generally, not just from a financial guardrails perspective, but from a commercial perspective, people -- the biggest companies tend to transact with us. So we're pretty pleased with how that's working out.
Our next question comes from the line of Robert Catellier with CIBC Capital Markets.
You've answered most of my questions here. I'm just curious on the Ruby pipeline term loan that was repaid in April and any other financial support that might be needed going forward. What level of support is required from the owners to make those payments?
Yes, Robert, you're correct. The Ruby pipeline term loan was repaid in April with funds at Ruby. There's no additional support required with Ruby from the owners.
Okay. Great. And then just a clarification here, if the event we get a shutdown on Line 5, how that impacts your business? And what mitigation plans do you have in place? And specifically, is the Prince Rupert terminal and some of the other export options available on the NGL side now enough to effectively mitigate that with respect to any exposure you might have and any headwinds getting to your guidance?
Robert, when we built the Empress fractionation facility, which came into service, we built it to make money, and it's making money. It's working great. But we also built it as a hedge in case eastbound volumes, West to East volumes ran into problems. And so we can rail out of that facility now, and we can rail to Sarnia, if we need to. That line shuts down, Sarnia is going to get pretty expensive, but we can get our product there still. But you're absolutely correct, we can also get those volumes elsewhere, whether it's south or west. So again, partially, we primarily built that to make money. But we also built it in a defensive way just in case this happens. So it would be terrible and unprecedented for this to occur. But we do have contingency plans in place. Stuart, anything to add?
Yes. Just to add that Mick mentioned in Sarnia, look, we moved those volumes from West to East and frac them out there. But we also have a large storage position in Corunna with rail and trucking, inbound and outbound. So if -- in the unfortunate event that would happen, that asset would be highly coveted.
Okay. And then I just want to make sure I understand the risk transfer on the Mitsue agreement. It seems like most of its spread benefit seems to accrue to the -- to your marketing customers. So are you effectively on that piece of the business now sort of in the fee for service or in the tolling-type contractual arrangement?
Yes. The way the marketing pool works, Robert, is all of our volumes, including Pembina. So roughly 1/4 of the volumes are ours and 3/4 of the volumes we're the agent for. They get what we get. So we ship to Conway, we rail to Conway, we deduct the rail cost. If we take it through PRT, we deduct the toll at PRT and the rail cost. And so it's just 3/4 fee-for-service and 1/4 is proprietary to us. So it's kind of like -- that's the reason our marketing pool is so successful is that we have the greatest economies of scale in the sector to get to premium markets. And because we give our customers what we get. And so we're shoulder to shoulder, and that creates tremendous alignment. And we think it's the winning model.
Yes. I appreciate that aspect of the model. I'm just curious on the Mitsue agreement. If you're still -- and the whole marketing pool as long as the spread to Asia or if Mitsue has Edmonton to the Asia spread?
It's the former, Robert, at this point in time. Like again, we deliver the product. We load the vessel and Mitsue is selling that product. And as Mick said, we're covering our costs for 75%, but it's essentially -- those barrels are selling into the Asian market at this point. And so that's how the deal struck with Mitsue.
Our next question comes from the line of Shneur Gershuni with UBS.
Most of my questions have been asked and answered. I just wanted to come back to the 8 and 9 expansion for a second here. Is it -- in sort of listening to your responses to the various questions, I'm trying to wonder -- I'm trying to think about how to think about when it actually gets FID-ed whether you're fourth in goal or not. Just like if you're at the point where you're discussing scope and size and so forth, does that mean that we're pretty close to the point where you could FID it, and it's something that could be spent potentially in '21 or mostly in '22? Or am I misreading that? And it's probably going to still take some time just given the recovery in where it's at.
Consider we FID-ed those projects once already and then pulled them back. So they're very well understood from a rooting, regulatory perspective. It's just a matter of what is physically required, giving the rapid -- given the rapidly emerging picture in NEBC and what that price might look like. So we just need a little bit -- we're just measuring twice before we cut there. And we have some things we'd like to get done before we move that thing forward. Harry, anything to add there?
I think Mick hit the nail on the head. It's looking really, really good. I think, as Mick alluded to earlier in the call, you could probably see Phase 9 resanctioned earlier. But there's -- probably a twofold reality is how the industry and our producer community are thinking about what they need next has shifted slightly. So we are adjusting with them in the context of Phase 8 and 9. And then secondly, I believe, Mick and the team have talked about on the optimization process we're going through here. And that's resulted in clearly some optimization across our conventional business, and we're looking to take advantage of that initially before we spend money on new capital. So -- and I think it's safe to say some barrels freed up through our optimization process that has really helped that. So we're looking to fill that first. And then get into the new capital.
Yes. Just on that, we used to call that Phase 10, just for those who heard about Phase 10. So as we do kind of a sweeping review of our pipe and across the board, we realize Cochin has way more capacity embedded in it than we thought before, and we're already using a bunch of that incremental capacity with more to come. Peace, we've freed up tens of thousands of barrels a day through optimization. And again, with technology, we expect that to continue to improve. And so when you're -- let's just say, hypothetically, we could move 50,000 or 60,000 barrels a day, more down Peace, that obviously impacts our design. And so those things are all in an iteration right now, cross-referenced against what the demands and when those demands from customers will evolve in NEBC. So again, we're working it. We're optimistic we can say more about it in the second half of this year along with the Prince Rupert expansion.
If I can just clarify my understanding to your response there because it sounds very interesting. Are you essentially saying through the optimization process that you effectively been able to create essentially one of the phases synthetically? Is that sort of the way to think about it? So it sort of delays the need for some capital, but you can still actually capture the volumes and the associated cash flow. Is that the right way to be thinking about it?
That is correct that we are creating parts of those phases through just getting more through the pipe. I mean, consider the -- if you kind of go back 5, 10 years, we've been building, building, building. We never had a pandemic to stop and look what these systems can actually do. And so we've had that time to engineer, reengineer, and we are producing that capacity synthetically at no cost throughout our systems or throughout our pipeline universe. We've never had that opportunity before. And so that is partially what led to Phase 7. We didn't have to build out all of Phase 7 because we realized Phase 7 optimized could move virtually as much capacity as all of Phase 7. So we took $150 million out of that cost estimate. So that is what is going on. And part of the reason that we're taking for our needs to say a pause for the cause to make sure we don't overcapitalize these assets. And all that leads to lower tolls for our customers.
A good way to look at it because Peace is obviously much more complicated system. The example Mick gave on Cochin is perfect. As when the team looked at Cochin, we were able to find 14,000 barrels a day that are flowing today that weren't flowing before with no capital.
Right. Okay. Perfect. I really appreciate the color there. And I was just wondering if you can go back to the Prince Rupert expansion potential as well, too. I guess when I sort of think about the LPG demand in Asia, when I think about shipping, vessel rates have gone up as well also, which is indicative of the strength of that market there. Have you been able to handle some of the larger vessels? I think you were talking about an MGC, I can't remember what the names are correctly in -- is the demand there to easily expand? And it's something that is also potentially a float-in-roll type of expansion? And could the opportunity from a pricing perspective, be pretty strong just given the global market dynamics?
100% of the demand is there right now. We could have sold a lot more than we did through our process. We're very pleased with Mitsue as a partner there. The question is, do we expand? If you recall, our original FID was put in a few more steers and upgrade the rail somewhat and kind of go from 25,000 to 40,000 barrels a day. And that's still a legitimate plan, and we're realizing that even though we're using the smaller handy-size ships, they are very handy. They can get into some really great niche markets, and Mitsue is helping us understand that. So we may choose not to go to larger ship size because we can access niche markets that no one else can access in smaller markets. Hawaii, Alaska, South America, Mexico, they're very well suited for smaller cargoes because if you had a VLDC, they'd have to soft in Alaska, partially unload and then sails to Hawaii partially unload, and that's just not economic. So the handies aren't necessarily a liability. But that said, we have realized we can get the larger ships and the larger ships don't refrigerate on board, so we'd have to refrigerate onshore. That's a little more capital intensive. So we're studying those options right now. I think we have at least 2 options in parallel. Jaret, anything else?
Yes. Just -- I would just add, like Mick said, customer demand is high. The relationship with the community of Prince Rupert, the port and the surrounding and business communities is excellent and just evaluating the 2 different work streams that stick with the handies and/or go from 150,000 to roughly 250,000 barrels per vessel. So just that works ongoing, and we expect to have that wrapped up mid- to later this year.
Your last question comes from the line of Patrick Kenny with National Bank.
Mick, just to clarify your comment there around providing more of a growth update in the second half of the year. Are you in live discussions today with shippers with respect to the timing and the need for building out incremental frac capacity, whether at Redwater or in the field in B.C. and perhaps dovetailing these discussions into rolling over whatever is left on the near-term contract expiries on Peace? Or is that simply your expectation as we step into the second half of the year?
We're in live discussions. Every single place in the value chain, whether it's processing, whether it's increases in what we need on Peace, filling Peace, filling Alliance, fractionation, it's soup to not -- we talked about Rupert. Things are coming around. And like when we say, we think we're going to be the Pembina of 2017 to 2019 in 2022, we believe that wholeheartedly that we'll get our capital program back to $1.5 billion to $2 billion a year. Without too much difficulty, we'll keep our costs flat. And we'll do a bunch of things that you know of, and we'll probably do a bunch of stuff that might surprise you, as we always have over the last decade. So we are feeling we've hit play, and we're emerging. So our morale is very good.
Okay. That's excellent. And then just maybe one last cleanup question. Back to the PPA with TransAlta, obviously, checks the ESG box nicely there. But given where power prices were in the quarter, are you now looking to ramp up your contracted power portfolio just as much from a financial standpoint? Or do you prefer to keep more of an open position as it relates to power costs?
It's mixed. We always have to be careful of how we do it. I mean, places like Empress where we bear all the cost for power. It's game on, and we're looking to contract a lot of that out. Places where we flow through, we have to be very mindful that we're making the best deal possible on behalf of our customers. So far, all the deals we're doing are to our account. We'll investigate going beyond that in the future. But this won't be the last PPA we do. We think it's a good part of the energy mix for us. And as you know, we do what we say. And when we say we're going to reduce the emission intensity of every business, we will do that. We're just not going to make grandiose claims about 2050 when we have no idea how to get there. That's not who we are.
At this time, there are no further questions. Are there any closing remarks?
Yes. It's Scott here. I'll just clarify one question before I turn it over to Mick to wrap up. Jeremy, just circling back to your question on hedging for the remaining of the year. Your previous question asked me for a quarterly run rate on G&A. So I actually answered your question. I answered it on a quarterly basis, not a yearly basis. So we expect to have losses of about $20 million per quarter when it relates to NGL, and that's pricing as of March 31. So I just wanted to clarify that my $20 million was per quarter for the rest of the year.
Yes. Thanks, Scott. Listen, everybody. Look forward, we have our AGM at 2:00 p.m. Looking forward to having you tune in for that. We got a very positive message to deliver on the way we got through 2020, which we're extremely proud of and what we see upcoming, and we'll have a nice little video at the end, which is something new, realizing you're all online, that'll be a little more entertaining, and you'll get to meet Janet in person. So looking forward to having you all meet her. So that's 2:00 p.m. Mountain Time. Talk to you soon.
This concludes today's conference call. Thank you for participating. You may now disconnect.