Pembina Pipeline Corp Q1 FY2021 Earnings Call

Good day and thank you for joining us. Welcome to the Pembina Pipeline Corporation 2021 First Quarter Results Conference Call. All participants are currently in listen-only mode. After the presentation, we will have a question-and-answer session. Please note that this call is being recorded. I will now turn it over to your first speaker today, Cameron Goldade, Pembina’s Vice President of Capital Markets. Please proceed.

Thank you, Christy. 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 and New Ventures and Corporate Development Officer; and Janet Loduca, Senior Vice President, External Affairs and Chief Legal and Sustainability Officer. I would 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. 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 longstanding officers, Paul Murphy, Senior Vice President and Corporate Services Officer; Jason Wiun, 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, Pipelines. On behalf of everyone at Pembina, I congratulate Paul and Jason on their retirements 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, in the first quarter of 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 pre-pandemic levels in April. With many systems previously operating near take-or-pay levels throughout the second half of 2020, Pembina is beginning to realize the anticipated benefits of its operational leverage 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 hedging program. In conjunction with strong first quarter results, Pembina is celebrating a few recent developments. The first is the startup 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, two vessels have departed PRT destined for international markets. I’m also pleased to announce that we have entered into a one-year agreement with a subsidiary of Mitsui, whereby they will purchase substantially all of the post-commissioning cargo shipped from PRT, with 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 customers 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, governments, and First Nations, Pembina was able to transform and repurpose a contaminated site on Watson Island, BC 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 a key income-generating asset 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 commitments by lowering emission intensity of each of our businesses. We have signed a long-term 100-megawatt power purchase agreement with a subsidiary of TransAlta Corporation that supports development of a 130-megawatt Garden Plain Wind Project in Alberta. The PPA provides significant benefits to Pembina including securing 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 tonnes of CO2 equivalent emission offsets annually or an estimated total of 1.8 million tonnes of CO2 equivalent emission 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 facility represent approximately 7% of Pembina’s 2019 reported greenhouse gas emissions. Pembina has committed to reducing the carbon intensity of each business that operates and by the end of 2021 will have taken concrete action in this area by publishing five-year emission targets. Finally, Pembina through its joint venture Veresen Midstream safely completed the startup 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 and an increase in realized losses on commodity-related derivatives, along with higher general and administrative costs and other expenses, largely driven by increased long-term incentives offset by lower salaries and wages and lower acquisition-related costs. The increased mark-to-market and long-term incentives were 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, 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 were 3.5 million barrels per day in the first quarter, down only slightly from the same period in the prior year. Lower interruptible volumes and pipelines due to reduced upstream activity in 2020, were 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 compared to the first quarter last year, the real story, as Mick noted in his opening comments, is the steady rise in volumes over most of 2020 and now into 2021, with physical volumes in April reaching pre-pandemic 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’m 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’ve 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 their aggressive debt reduction and shareholder returns. Ultimately, we expect producers to sanction new drilling activity and Pembina is well-positioned to capitalize on that activity, particularly to serve growing volumes in the Northeast BC, Montney, and Alberta Duvernay areas. New infrastructure including the Trans Mountain pipeline expansion, LNG Canada, Enbridge’s Line 3 Replacement, and Pembina’s 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 and 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 new opportunities for Pembina. These opportunities include the reactivation of the currently deferred Peace Pipeline Phase VIII and IX expansions and the expansion of the 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 the 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 p.m. Mountain Time, 4 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 Investors 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.

Our first question will come from Matt Taylor with Tudor, Pickering, Holt & Co.

Hey. Thanks for taking my questions here. I wanted to start first with your bullish comments 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 BC and the Cardium. Our NGL business volumes are quite good at Redwater, so you’re seeing it throughout. I mean, we did reach pre-pandemic levels in April; certain areas, Drayton Valley have been very strong, and of course, that all feeds our marketing business as well.

Great. As a follow-up, it seems your EBITDA guidance is based on last year's levels rather than new growth. Could you explain how this performance relates to your EBITDA guidance and the possibility of restarting projects?

When we established our guidance, the pricing environment was quite different. I believe many would be pleasantly surprised to see oil prices in the mid-$60s, with propane prices around $0.90 at Belvieu and natural gas prices approaching $3 Canadian, around $2.70. We are observing a rare situation where all three of our volume streams are performing simultaneously. Typically, at least one stream is underperforming, often two. Despite the focus on debt reduction, I agree that there are signs of a quiet return to drilling activities, and we expect this trend to pick up as more meetings occur. I've been reading favorable reports from our customers who are significantly reducing their debt and experiencing increases in their share prices, which suggests they will soon transition from buybacks to pursuing growth. They appear to be strategically assessing their expansion opportunities, and we believe they have a clear plan for optimizing their capital investments. We anticipate this will unfold later this year and into the next. We still have substantial capacity available, and we are starting to get past the take-or-pay level, which will benefit us. We are optimistic as we enter the first quarter. While we were slightly over hedged, that was a decision made during the second wave of the pandemic, and with hindsight, it was a prudent one. We have a significant portion of our hedges that were discretionary, and those will expire at the end of the quarter. We are hopeful about returning to pre-pandemic volumes and the expected growth as demand builds. If prices remain strong, the situation is poised to become quite exciting.

Yeah. Thanks for that color there, Mick. Maybe just to clarify your comments there, like my understanding is, is that guide is looking at 2020 levels and if there’s an incremental interruptible in the system or various other pieces 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 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 within the guidance range. We’re comfortable there.

Yeah. Matt, maybe I’ll just add a couple of 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 down 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 two. 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 provide guidance.

Okay. Yeah. Thanks for all that good detail there. I’ll leave it there.

Our next question comes from the line from Jeremy Tonet with JPMorgan.

Hi. Good morning.

Hi, Jeremy.

Just want 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, 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 hand it over to Scott shortly. The hedging program at its core is our non-discretionary program, which comprises about half of our NGL business, excluding Aux Sable. We discontinued the non-discretionary aspect starting this quarter because we see that commodity prices are stronger than we expected, particularly compared to the fourth quarter of last year. Scott, would you like to add anything?

Sure, Jeremy. Looking ahead, we still have the frac spreads that were established in 2020, and those are clearly not performing well. Just to remind everyone, for the rest of the year, the frac spread business is the only part that is hedged; winter storage and Aux Sable are not. With the current projections, we anticipate losses of around $20 million to $25 million on the NGL side of the business.

Got it. That’s helpful. Thanks. And then with the corporate expenses a bit higher than what we expected this quarter, I guess, what should we be thinking about as a run rate? Appreciate there was an LTIP noise and retirement noise, and there’s made a bit higher, but just thinking about what kind of normalized at this point?

In the first quarter, as you mentioned, there was a mark-to-market impact from some of the incentives. To give you an idea, a $1 change in our share price corresponds to approximately $1 million in general and administrative expenses. With our share price increasing from $32 to $38 at the end of the quarter, this had a noticeable effect on our quarterly results. We also incurred some one-time consulting fees as we continue to optimize our operations. Therefore, there was some variability in the quarter. Looking ahead, we anticipate that our corporate costs will be around $40 million per quarter.

Got it. Okay. So it doesn’t seem like corporate is really that different from what you budgeted for the year. Because if I’m looking at just Pipeline and Facilities segment, that’s $800 this quarter, and if I annualize that without even thinking about marketing, that gets you $3.2 at the bottom end of the range. And if you talk about the kind of improved producer outlook, granted 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 here? What you are expecting here? Are there any kind of benefits 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. Yeah. Jeremy, we need to ensure we're comparing similar things. My $40 million was mainly for corporate expenses. Additionally, we have general and administrative costs within the businesses. So, in total, it amounts to about $60 million to $65 million each quarter.

Got it. Understood. I will leave it there. Thank you.

Our next question comes from the line of Ben Pham with BMO.

Hi. Thanks. Good morning. On your wind project you announced with TransAlta, I am just curious how do you weigh or consider the relative difference between building wind 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 view the wind project like any other project. We have a small 20-megawatt wind project with Veresen. Our approach is to treat it as a capital allocation decision. We are learning and studying the opportunity. We have an option to participate in the wind farm up to 50%, but we have chosen not to invest our own capital at this time. However, there is a significant demand for power, which gives us economies of scale. We can establish strategic partnerships for wind power and are keeping the option to participate and self-supply open, but currently, the project has not attracted investment.

All right. And there was some reference to rising power costs in a quarter and that’s at the Alberta power price. Can you remind me is that, do you recover that in your business as a way your EBITDA instead? And then maybe just an overall comment on inflationary pressures you are seeing, any sort of protections you have there?

Our variable costs generally flow through, except in our extraction business where we manage power costs. This is one of the reasons we are implementing cogeneration at all of our large plants. It allows us to reduce emissions, gain control over future prices, and align electricity costs with gas pricing instead of grid pricing.

What about trade, labor, and steel? As you start to expand, are there any considerations regarding potential inflationary pressures?

Not right now. If you think back to our largest projects, like Phase VII, we purchased the steel before the pandemic, so it was already in inventory. We had invested about $300 million, mainly for the tangible assets, and that was all hedged at last year’s pricing. Most of our major projects have fixed costs, as we secured them at a very advantageous time following the cancellation of Keystone XL. Our skilled staff managed to lock in a variety of costs associated with that. Harry?

Yeah. They are done 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 two mainline contractors on the two spreads per se Phase VII; we’ve seen really directionally good pricing on both the mainline contracting and then the HDDs that need to happen as well. So we’re very happy with that as we sit here today.

All right. That’s great. Okay. Thank you, everybody.

Your next question comes from the line of Linda Ezergailis with TD Securities.

Thank you. I’m wondering as we look at the energy transition, I think most people use some of the political and economic constraints as 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?

We are actively considering our position in solar and wind, and currently do not see significant contributions in those areas, which is why we are opting to partner with others instead of pursuing wind projects on our own. However, in carbon capture, we are conducting an early pilot project at Redwater to capture CO2 and assess its viability. We produce hydrogen, which aligns with our skill set, and we excel in various aspects of electric generation from gas and its subsequent sequestration. Our carbon capture system is effective, and we have extensive experience in transporting and injecting gas, as this has been part of the industry for years. Our operational footprint and rights of way enhance our capabilities in this domain. We're focusing on supplying CO2 for Enhanced Oil Recovery (EOR) projects, as many prime targets for EOR lie within our area. Whether we inject CO2 into the Cardium reservoir or another party does, the returns would eventually pertain to our facilities, providing us with a competitive edge. This is a key area of focus for us right now.

Thank you. On a related note, you mentioned that you're reviewing your hedging profile. There's a significant amount of change occurring in the industry and also within your asset mix, particularly with your new LPG export capabilities being quite prominent. Can you discuss how the hedging might change in response to these developments and whether there could be opportunities to either enhance your exposure as you align more closely with commodity prices or reconsider your financial parameters and the appropriate level of contracting?

We still value our guardrails. We recently completed a strategy session with our Board, who are very supportive. I look forward to reviewing everything during the AGM later today. Those guardrails have served us extremely well. We nearly achieved the midpoint of our guidance and, if you take a step back, we had a record year for EBITDA last year, which reflects the benefits of diversification and our guardrails. I'm very satisfied with how they have helped us, although there were challenges, such as the hedging losses in the first quarter. Our focus is on delivering steady and growing dividends, and we excel at that, which is why people invest in our stock. We will continue on this path. Regarding hedging and Rupert, remember that only a quarter of the volumes are our proprietary volumes; the remaining three-quarters come from our marketing pool and producer volumes. These producers will benefit significantly from the great Bay price, while we will get some as well. We differentiate ourselves from competitors by providing customer volume and market access instead of relying solely on our own. This will start to materialize, and I believe it will make our customers very happy when they see the net returns. There isn't much additional hedging needed in this area. From our standpoint on Rupert, it represents a valuable diversification beyond existing markets like Edmonton, Sarnia, Conway, and Belvieu. We see it as a new market opportunity that aligns with our strategy to gradually expand globally, catering to customer demand.

Thank you. I’ll jump back in the queue.

Our next question comes from the line of Robert Kwan with RBC Capital Markets.

Thanks. Good morning. 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’s 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 pre-pandemic volumes. We’ve seen that strength continue throughout April. In fact, April physical volumes were in the neighborhood of about 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 strength on the Conventional Pipeline System.

Yes. Just a reminder, Robert, those only attract a small fixed cost burden. As you know, the variable costs flow through, and every barrel gathered is a barrel marketed. We have significant potential from this point forward.

And Mick, I think that’s probably what you’re 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 they are 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 and touch again?

For oil, it’s very highly correlated; almost every barrel that we bring in is a barrel marketed for NGLs, not quite as much. But I think a quarter 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 and Taylor. And so there we’re fully exposed, and this is a good time to be exposed. Go ahead, Jaret.

Hi, 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 liquid-rich condensate into the gaseous 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 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 two 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 just 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 are going forward? And if you have any comments as well with respect to the Northeast BC Connector project filing and what that might mean for you?

We’re advancing key conversations, Robert, and we will 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 VIII, IX, 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.

Generally speaking, are you seeing though the outlook is more of a rising tide or more of a zero-sum game?

We are very comfortable that we can announce those projects later in the year and that they’ll be very well anchored.

So, Robert, the way I think about it is, it’s really three-fold. Jaret absolutely nailed it when he talked about HVP volumes started. So that’s the first piece. 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 haven’t looked at Drayton Valley in particular, they are just above in April pre-pandemic 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 conversation is now starting to return to additional volumes above that. So we feel really positive directionally for those four reasons. One we’re going, and I think we also feel confident speaking into the mic in the back half of the year in Phases VIII and IX.

Yeah. The one intricacy that maybe people don’t fully understand in Northeast BC is, the system that reaches into the heart of any BC is a cost of service system, and so as the customers feel that their per unit tolls drop, that system gets ever more competitive. It used to be a pretty expensive system when Petronas anchored it like five 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 really a key competitive advantage that customers have really created for themselves up there.

And then when you look at Northeast BC, 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.

Got it. If I can just finish, oh, sorry, go ahead.

I just wanted to add something quick. Again, we could see a lot of the strength we’re witnessing this quarter, Nikolai. We’ve highlighted that we’ve had some strong logistical support on the contracting side from some of our major operators this year. And we’re getting seasonal benefits out of Northeast BC that are driving the bottom line quite a bit. So hence this optimism.

Okay. If I can just finish, my last question for you is whether you have any commentary on volumes or pricing, especially in comparison to the year 2020 regarding the NGL.

I’ll turn it over to Stu now. The pricing is significantly better than last year. If I recall my AGM numbers correctly, it was $0.50 last year and we're currently around $0.90 in Belvieu. I will be presenting this afternoon, but to address your point, gas prices are a bit higher, generally around $2 to $2.70. So, we are seeing nearly double the NGL pricing compared to last year, while gas pricing has only increased by about 50% year-over-year. That’s quite substantial for us. I’m not sure where we will end up for the full year, but we are well ahead of our initial expectations for the first quarter.

Robert, I won't add a lot more; I think Mick covered it. We had a great gas re-contracting. Our NGL recovery at our facilities when we’re out securing gas, we’re 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. Across the board some significant improvement over 2020 and excited about where we’re going.

I was inquiring about the procurement side. Were you able to capture similar volumes with headline NGL prices increasing? Are you experiencing a similar percentage change in your procurement cost?

On the buy side.

On the buy side, we’ve 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.

Okay. Thank you.

Your next question comes from the line of Chris Tillett with Barclays.

Hey, guys. Good morning. Thanks for taking my question. I guess maybe to just shift gears a little bit, can you talk about the progression of Phase VIII and IX? 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 an update on that.

We’re doing the engineering for those projects. As you saw with Phase VII, we’ve kind of delaminated Phase VII a little bit. I mean, we took a lot of costs out of VII, a lot of it was outright saving, some of it was scope. And so we’re getting a little forensic on VIII, IX, and maybe IX goes before VIII; 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 do you put in? That’s kind of what we’re waiting for with the remaining anchor tenants we can land, and that’ll 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 VIII, IX 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 will have possibly a lot more volume and a lot longer runway to grow there. That’s kind of what we’re seeing right now than we thought before. Jaret, go ahead.

Yeah. There is inflationary pricing, but I think we’re making excellent headway on driving down our overall diameter, branch mile cost as well.

Let me summarize it by saying we believe NEBC is more exciting than we thought when we applied at the first time.

Okay. Great. Thanks so much for that. And then, I guess, last one for me is, obviously, the last six 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 we’ll 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?

Yeah. Sort of all of the above I guess.

Sure. I mean, we’ve got a great value chain. And so we’d 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 up 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 think 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 impacted your assets?

Positively, we’ve observed that with the Arc/Seven G merger, they achieved investment grade status and became more capable. Many are actively reducing their debt. I recently reviewed some 10-Q filings, and the overall trend is encouraging. The largest producers, who have significant plans, prefer to work with reliable infrastructure that they know they can trust. Consequently, from both a financial and a commercial standpoint, the major companies tend to engage with us. We are quite satisfied with this development.

Okay. Perfect. Thank you very much.

Your last 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?

Yeah. 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 in the event we get a shutdown on Line 5, how that impacts your business? And what mitigation plans you have in place, and specifically, is the Prince Rupert Terminal and some of the other port options available on the NGL side now enough through to effectively mitigate that with respect to an 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 out great. But we also built it as a hedge in case east-down 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 happened. So it would be terrible and unprecedented for this to occur. But we do have contingency plans in place. Jaret, anything to add?

Yeah. 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 Corona with rail and trucking inbound and outbound. So if in the unfortunate event that what happened, that asset would be highly coveted.

Okay. And then, I just want to make sure I understand the risk transfer on the Mitsui agreement, it seems like most of the spreads benefit things accrue to your marketing customers. So are you effectively on that piece of the business now sort of in a fee-for-service or tolling-type contractual arrangement?

Yeah. The way the marketing pool works, Robert, is all of our volumes including Pembina. So roughly a quarter of the volumes are ours and three quarters of the volumes were the agent for. They get what we get. So if we shipped 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 costs. And so it’s just three quarters fee-for-service and one quarter is proprietary to us. So it’s kind of why 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.

Yeah. I appreciate that aspect of the model. I’m just curious on the Mitsui agreement and if you’re still and the whole marketing pool is long the spread to Asia or as Mitsui has admitting to Asia spread.

It’s the former, Robert at this point in time. Like, again, we deliver the product, we load the vessel, and Mitsui 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 is struck with Mitsui.

Okay. Thank you.

Our next question comes from the line of Shneur Gershuni with UBS.

Hi. Good morning, everyone. Most of my questions have been asked and answered. I just wanted to revisit the VIII and IX expansion for a moment. Is anyone considering your responses to the various questions? I’m trying to understand how to gauge when it actually reaches the final investment decision. Are you at a point where you’re discussing scope and size? Does that indicate we are close to being able to make the final investment decision, potentially spending in 2021 or primarily in 2022, or am I misinterpreting the data and it may still take some time given the current recovery?

Consider we FIDed those projects once already and then pulled them back. So they’re very well understood from a routing regulatory perspective. It’s just a matter of what is physically required given the rapidly emerging picture and NEBC and what that prize 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 made an excellent point. Things are looking very promising. As Mick mentioned earlier, we might see the Phase IX resection sooner than expected. However, there are two aspects to consider: first, the way the industry and our producer community is thinking about their needs is evolving, so we are adapting alongside them in relation to Phase VIII and IX. Secondly, Mick and the team have discussed the optimization process we're currently undergoing, which has led to improvements in our Conventional business. We want to leverage these enhancements before investing in new capital. It's fair to say that some resources have been freed up through our optimization efforts, which has been beneficial. Our priority is to address those first before moving on to new capital investments.

We used to refer to that as Phase X for those familiar with it. In our comprehensive review of our pipeline, we discovered that Quoton has significantly more capacity than we previously realized, and we are already utilizing a considerable portion of that additional capacity, with more expected in the future. In Peace, we have been able to free up tens of thousands of barrels per day through optimization. With our technological advancements, we anticipate continued improvements. Hypothetically, if we could move an additional 50,000 or 60,000 barrels per day through Peace, that would certainly influence our design. Currently, we are iterating on these elements while aligning them with customer demand and timelines, particularly in NEBC. We are actively working on this and remain hopeful that we can provide more information in the latter half of this year, alongside 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’ve 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; we are creating parts of those phases by increasing throughput. If you think back five to ten years, we’ve been continuously building without any breaks to evaluate what our systems can actually achieve. Now, we have had the chance to engineer and re-engineer, allowing us to produce capacity synthetically at no additional cost throughout our systems. This opportunity has never existed before, which is partly why we developed Phase VII. We realized that optimizing Phase VII could enable us to move as much capacity as the whole of Phase VII itself, allowing us to reduce the cost estimate by $150 million. This situation is what is currently happening. Additionally, we are taking a step back to ensure we do not over-capitalize these assets, which will ultimately lead to lower costs for our customers.

Yeah. A good way to look at it because Peace is obviously a much more complicated system. The example Mick gave on Quoton is perfect; when the team looked at Quoton, we were able to find 14,000 barrels a day that are flowing today that weren’t flowing before with no capital.

I appreciate the information provided. I would like to revisit the potential for expansion at Prince Rupert. Considering the demand for LPG in Asia and the increase in shipping vessel rates, which suggests a strong market, have you managed to accommodate some of the larger vessels? You mentioned an MDQ earlier, but I can't recall the specifics. Is there sufficient demand for an easy expansion, and could this represent a significant pricing opportunity given the dynamics of the global market?

The demand is definitely present right now. We could have sold much more than we did through our process. We’re very pleased with Mitsui as a partner. The question we face is whether to expand. Our original plan was to add a few more spheres and upgrade the rails to increase capacity from 25,000 to 40,000 barrels a day. That plan is still valid, and we’ve found that even though we’re using smaller Handysize ships, they are quite effective; they can access some excellent niche markets, with help from Mitsui in understanding that. We might opt not to pursue larger ship sizes because the smaller vessels allow us to reach niche markets that larger ships cannot, such as Hawaii, Alaska, South America, and Mexico. These markets are ideal for smaller cargo loads, as larger vessels would require stopping in Alaska and partially unloading before continuing to Hawaii, which isn’t economical. Therefore, the Handys are not necessarily a drawback. However, we've recognized that we can consider larger vessels, but those do not have onboard refrigeration. Thus, we would need to implement refrigeration at shore, which requires more capital investment. We are currently evaluating those options. At this moment, I believe we have at least two options we are exploring concurrently. Jaret, do you have anything else to add?

Yeah. Just I would just add like Mick said, customer demand is high. The relationship with the community of Prince Rupert, the ports, and the surrounding indigenous communities is excellent. And just evaluating the two different work streams that stick with the Handys and/or go from 150,000 to roughly 250,000 barrels per vessel. So, just that work is ongoing and we expect to have that wrapped up mid-to-later this year.

All right. Perfect. Really appreciate the color and the discussion towards the end here. Thank you very much and have a great weekend.

You as well. Thanks for your interest.

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