Good afternoon. My name is Christina, and I will be your conference operator today. At this time, I would like to welcome everyone to the Pembina Pipeline Corporation second quarter results conference call. All lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question and answer session. If you would like to ask a question during this time, simply press star, then the number 1 on your telephone keypad. If you would like to withdraw your question, press the pound key. Thank you. Scott Burrows, Senior Vice President and Chief Financial Officer, you may begin your conference.
Thank you, Christina. Good afternoon, everyone, and welcome to Pembina's conference call and webcast to review highlights from the second quarter of 2019. I'm Scott Burrows, Pembina's Senior Vice President and Chief Financial Officer. On the call with me today are Mick Dilger, Pembina's President and Chief Executive Officer, Jason Wiun, 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 Cam Goldade, Vice President, Capital Markets. Before we start, 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.
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 various financial reports, which are available at pembina.com and on both SEDAR and EDGAR. Pembina delivered strong second quarter results, reporting quarterly adjusted EBITDA of CAD 765 million, which represents a CAD 65 million or a 9% increase over the same period in 2018. Quarterly results were driven by period-over-period increases in the pipeline and facilities divisions as a result of new assets being placed into service, as well as increased terminalling and storage revenues. Additionally, in our oil sands business, we saw higher revenues from recoveries under flow-through capital arrangements. These higher recoveries relate to both current and prior periods and reflect increased capital spending. The impact on revenue in future periods will be dependent on actual capital spending.
Within the marketing business, the quarter was positively impacted by the adoption of IFRS 16, a realized gain on commodity-related derivatives and higher NGL volumes offset by lower NGL margins. Performance in the crude oil marketing business remains steady. The second quarter is seasonally weaker for our NGL marketing business, and there were headwinds in North American propane and butane price markets. However, our growing NGL volumes and hedging program, combined with integration and market diversification, drove sustained performance in the quarter. Adjusted cash flow from operating activities decreased by 1% to CAD 550 million in the second quarter of 2019 compared to the same period in 2018, primarily due to an increase in current taxes and a decrease in distributions from equity accounts investees, partially offset by an increase in operating results and the adoption of IFRS 16.
Finally, based on our year-to-date results and our outlook for the balance of the year, we remain on track to meet our adjusted EBITDA guidance range of CAD 2.85 billion-CAD 3.05 billion. Now, I will turn things over to Mick for an update on some of our key growth projects and business development activities.
Thanks, Scott. Good afternoon, everyone. Thanks for accommodating this late-day call. Pembina delivered another quarter with strong results. Our integrated business model, supported by long-term contracts and a strong financial position, has generated consistent and growing earnings through energy market cycles. We continue to develop and expand the Pembina store, ultimately driven to be the leader in delivering integrated infrastructure solutions connecting global markets. At our Investor Day in May, we outlined three strategic priorities. The first priority was protecting our base business, which includes safe, reliable, and cost-effective operations, optimizing our existing assets, and renewing and extending our current customer relationships. As evidence of that, we recently executed agreements for a significant term expansion and increased volume commitments at Pembina's Saturn Deep Cut Processing Facility. These agreements include gas processing, NGL transportation and fractionation, and marketing services.
The second priority, enhancing our business, shows up in our secured growth program. Our pipelines and facilities divisions are constructing CAD 3 billion of capital projects, which in aggregate are trending on budget. Our teams continue to see a steady flow of new business opportunities, and we are confident that Pembina is best positioned to meet customer demand for integrated services. Finally, our third priority, which is to access global markets and provide higher net backs to our customers, continue to take shape. Our Prince Rupert terminal, currently under construction and expected to go into service in the second half of 2020, is a relatively small but important project, as it serves as a pilot project in our development of an export terminal business. Our PDHPP project is now in the execution phase, and we are obtaining engineering, procurement, and construction bids.
Long lead equipment orders have been placed, partially placed, and early work construction contracts have been awarded. Site clearing is also complete. On Jordan Cove LNG, we are focused on the federal and state permitting processes. We continue to work closely with all agencies at all levels. At the local level, support for the project has grown. Notably, we now have signed easement agreements that constitute 80% of the privately-owned portion of the proposed pipeline route. Commercial discussions with prospective customers are ongoing. We remain confident in the commercial interest to support the project. I would add that given we are now through the technical and land acquisition phases of this project, our monthly spend profile has dropped dramatically.
In closing, I'm very pleased with the quarterly safety, operating, and financial results, the progress we are making on major projects, and the steady stream of business opportunities our teams are developing. Pembina is set to mark another major milestone next month, celebrating 65 years as a company. We have grown from a single pipeline and a workforce of 30 people to 2,300 employees and a total enterprise value of some CAD 37 billion. As always, I'd like to thank all of our stakeholders, our customers, our investors, our communities, and of course, our dedicated and hardworking employees for their ongoing support. It takes all of you to make things work this well. With that, I'll wrap things up. Operator, please go ahead and open the line.
Certainly. At this time, I would like to remind everyone, in order to ask a question, please press star, then the number one on your telephone keypad. Your first question comes from Jeremy Tonet from J.P. Morgan. Your line is open. Please go ahead.
Hi, good afternoon.
Hi, Jeremy.
Just wanted to follow up on the guidance here. If I take what you achieved in the first half of the year, and I just double that, seems you'd skew above the high end of the guide here. I'm just wondering, besides lower NGL prices, are there any headwinds in the back half of the year that we should be thinking about, like MVC timing or O&M timing?
Jeremy, obviously you hit the nail on the head with the first comment, which was the NGL pricing is, if you map it out, it's a little bit weaker in the back half of the year. That is offset partially by our hedging program. Certainly that is an impact overall. Secondly, I think in this quarter, we had some one-time events like the OBU revenue. That is ongoing, but the magnitude of Q2 was somewhat amplified, so it would be inappropriate to extrapolate that out. Based on where we are, I think we had the same discussion at this time last year, where we were slightly ahead on a year-to-date basis, and we had the same discussion. Along those same lines, to your point, we tend to have a higher integrity program in Q4 than we have prior in the year.
When you take all those factors into consideration, I think we're comfortable keeping our guidance range where it is.
Got you. Yeah, I think it worked out pretty well last year. Hopefully we have the same thing again. I just also wanted to follow up with some of your growth projects that you talked about before with Alliance and anything notable to talk about there as far as something in the future that could come, or also the BC fracs, if there was anything new to talk about as far as expansions there?
Hi, Jeremy. This is Jason. With respect to Alliance, I think things are continuing to progress well. We're talking to a number of producers in the Bakken, we're fairly happy with the conversations. We're progressing those discussions. I think we're continuing to move the engineering forward, both on the Alliance Pipeline and the frac at Channahon at Oxbow. Those things are moving forward. We won't really have our finalized cost at Oxbow until about the fourth quarter of the year. The combination of bringing the customer negotiations and the completed capital costs, we're hoping that by the end of the year, we'll be able to make an FID on that project.
Jeremy, it's Jaret here. With respect to the Northeast BC frac, we've approached the majority of the customers up in that area, and I think as the customers are seeing the realization of the benefit of the West Coast LPG exports, they're seeing that benefit. Things I would say are going very well there with respect to providing the customers a higher netback, but no details on timing right now.
Great. That's it for me. Thank you.
Your next question comes from Linda Ezergailis from TD Securities. Your line is open. Please go ahead.
Thank you. To follow on Jeremy's question, I'm wondering if you could give us a broader sense of the nature of your discussions with your producer customers. Has the tone changed, the volume of discussions changed in terms of their ability to commit to additional services in this pricing environment? I guess maybe you can also touch on what that might mean for future Peace expansions in terms of the pace and the scope.
You're talking more generally in the WCSB, Linda?
Correct.
I think obviously, gas prices are having an impact on producers' bottom lines, and there is some challenges out there for a number of the producers. We continue to have a large amount of deal flow moving forward on the Peace Pipeline system specifically. Since about the third quarter of 2018, we've probably executed 200,000 barrels worth of contracts on Peace. We don't see that as being a real challenge at the moment. The producers continue to pursue the opportunities and work things forward. We're still optimistic about our Phase IX project, and we feel confident that we'll be able to move that forward in the future.
Thank you. Just as a follow-up, to the extent that there might be the potential for some sort of systemic natural gas production curtailments introduced in Alberta with the government and industry working together, what sort of effect, if any, would you see that having on your operations?
It's Mick. That would be driven most likely by producers with leaner gas, I think. Given we're primarily a hydrocarbon liquids company and our major gas asset is Alliance, which in fact has a very good net back and would not be curtailed. We're not overly concerned about that at the moment.
Okay. That's helpful context. Your Prince Rupert terminal is facing some budget creep. I'm assuming the economics are still very compelling, but can you give us a sense of the nature of that pressure on your budget in terms of the scope and then what the magnitude of the increase might be?
We're working through, Linda, how we're going to disclose on a project-by-project basis. We think the most important thing for the readers of our statements is to know that we're trending on budget and on time, in terms of the overall basket. In terms of the blow-by-blow, we haven't decided whether we're going to disclose it down to an asset level. That particular asset, it's fine. It's always the usual suspects on these kinds of projects. I don't think we're going to be disclosing variances on a blow-by-blow basis because, I'll give you one example, to disclose between Peace phases whether we're over or under, can be a scope change, a timing change, and it's just kind of a chasing your tail proposition.
We're probably going to be more likely just to inform the readers that we're kind of on budget overall and henceforth, your model's going to be fine.
Thank you.
Your next question comes from Rob Hope from Scotiabank. Your line is open. Please go ahead.
Hello, everyone. I want to start off first on the volumes. Just taking a look at the facilities volumes. We saw gas services down quarter-over-quarter, same with NGLs. Even the pipelines, let's call those relatively flat. Just want to get a sense of where you're seeing your volumes trending and key drivers there and the outlook for the rest of 2019.
Hi, Rob, it's Jaret. Volumes I think quarter-over-quarter were down for the facilities division, roughly 3%. That was primarily IT volumes that were being curtailed due to the extremely low AECO pricing that we saw. Those are volumes that would typically flow to non-deep cut facilities of ours, and that I have very, as Mick mentioned, very low C5+ yields. Some of those volumes did get curtailed throughout the quarter. You have the immaterial amount of NGLs that normally would have shown up at the fractionating complex. That's primarily it. As Mick said already, the majority of our facilities are in the higher liquid yields, and in those areas, we have pretty high take-or-pays and long-term contracts, so we're not overly concerned about it.
Then on the pipeline side, conventional has been kind of 895, 840 or 880, kind of in that 900-ish range for a couple of quarters now.
Yeah. On the pipeline side, Peace volumes with Phase 4 and 5 continue to ramp up as generally as we expected. This quarter, they were impacted. On the western system, we had a third-party outage that impacted the overall conventional volumes that sort of offset and mask that increase that's happening on Peace.
Just finally, just taking over operatorship of Aux Sable, what benefits do you think you can bring there and longer-term, does that give you kind of a larger entry point in the potential U.S. market?
Right now, Rob, it's only been about 15 days since we've taken over operatorship, I can't really talk to the synergies today, I can say that the owners are extremely excited about bringing those folks over into our organizations. I think you kind of nailed it. Now that we have our hands on the steering wheel, we do get a little bit more insight into that Chicagoland market with respect to the NGLs, the business that we do every day here in Western Canada.
All right. Thank you.
Your next question comes from Patrick Kenny from National Bank Financial. Your line is open. Please go ahead.
Yeah. Hey, guys. Maybe just starting with the PDH. Could you remind us when you expect to have your EPC contract locked down and whether you're looking to go with a lump sum bid or a cost plus?
Yeah. This is Stu speaking. Yeah, we're in the process of evaluating our EPC bids as we speak. It's going to take us a couple of months, but we're planning to be through the review and the negotiations on the EPC by the end of October. For us, we are looking for lump sum bids from the EPC contractors, and that's our contracting strategy for that type of facility.
All right, great. Then on the product front, on the contracting side, any update on the 40% or so contracting level? Maybe any comment on whether or not the proposed ban on single-use plastics is in any way causing friction to those discussions you may be having?
We've ramped up our efforts regarding the fee for service with the work that we have and remain confident that we'll be, as we enter 2020, that we will reach our 50% target on our contracting basis. We remain confident there, and we have numerous conversations ongoing and are excited to undertake and complete that work. The single-use plastic, again, our facility and the idea to go with polypropylene as opposed to other plastics, these are a higher demand plastic, a recycled plastic and not just single use. It does have a variety of uses on a go-forward basis, but we don't see any impact from a demand basis for the facility.
All right, perfect. Moving over to Jordan Cove. When do you guys expect to reapply for the 401 permit? I guess how long should we expect a decision to take from the time of your reapplication?
We're working with the regulators, the state regulators in Oregon. We have a number of options with respect to the 401 permit and continue to work through with DEQ on those options. Obviously, with multiple options, they have different time frames, and so we're working them all. At this point, we're comfortable with the progress that we're making, but we expect still that we'll have our permits following our FERC approval in January of 2020.
Okay, great. Last one from me, guys. Just within marketing and specifically to the crude oil midstream business, I'm wondering if you're able to take advantage of some of these new butane supply agreements or maybe should we expect a ramp up still in margins here through the back half of the year?
We're not sure what you mean by butane supply agreements. Sorry.
Just within your crude oil midstream business, wondering if you could take advantage of some of the cheaper butane supply.
Oh, I see.
Yeah.
Yeah. We're getting less money for butane to the extent there's a butane to crude arb, we make more, but generally, it's a headwind. Lower butane prices are a headwind for us much more than a tailwind if there happens to be any kind of arbitrage blending.
Okay. Thanks for that clarification.
Thanks too .
Your next question comes from Matt Taylor from Tudor, Pickering, Holt & Co. Your line is open. Please go ahead.
Hey, guys. Thanks for taking my questions here. Can you provide some more context on the lower take-or-pay commitments on MPCL and Mid-C there? I assume it's not material, but I was just wondering if it was contract roll-offs or what was just going on there.
Effectively, they're just staged contracts with a profile. The profile changes as the contract goes along. It's just the way the term of the contract rolls over.
Okay. Is there any read through to some of the other legacy pipes like Swan Hills or Drayton Valley, or was this just kind of isolated to those two systems?
It was predominantly those two systems.
Great. Thanks. Just moving on to the commentary on terminalling revenues for propane and butane and NGL services. Can you give me some sense of where utilization is today for those assets and given frack tightness, how you guys are thinking about opportunities there to maybe ramp terminalling revenues or look to debottleneck fracks?
Hi, Matt. Jaret here. The utilization on the fracks are still fairly high. With respect to the terminalling, you may recall that Pembina finished quite a large rail expansion over the latter half of 2018. Year to date 2019, we've moved about 60% more rail cars this year than we had last year, and that's primarily due to the fact that we have that rail expansion now behind us.
Okay. That's great. One last one. In pipelines, looks like the deferrals, the MVCs for conventional were marginal, but it looked like oil sands there had a bit of a jump in deferred variable revenue recognition. Is that more of just a one-time sort of item? I am just trying to think through the rest of the year here and the shape of deferral revenue.
Yeah. On the oil sands, I don't want to call it a one-time event. There was a one-time event that kind of inflated it to the number that it was.
It was a catch-up.
On a catch-up. On a go-forward basis, it'll be as capital spent. That could be anywhere between, call it CAD 8 million-CAD 20 million a year. When you put that over a quarterly basis, it's relatively immaterial. It'll probably get lost in the noise of other things going on.
Yeah, that makes sense. Probably as we move into here into the back half on the conventional system is when you'll start to recognize some of those as volumes and revenue starts to align?
On the conventional side, in our financial statements, we do lay out what we've recognized and what we've deferred on section seven on the selected quarterly information. You can look at that and see the magnitude. On a year-to-date basis, we still have about CAD 23 million of deferred take-or-pay revenue that we may or may not recognize over the back half of the year, depending on how volumes show up from the various producers.
That's great. Thanks for taking my questions.
Thank you.
Your next question is from Andrew Kuske from Credit Suisse. Your line is open. Please go ahead.
Thank you. Good afternoon. I think it's been said a couple times on the call that the volumes were generally in line with your expectations on the pipes, a bit flattish. There's also some outages. I guess the question is really, what's the timing on the inflection point in your expectations on the volumes to lift in that business?
Typically, our volumes start to build in the second half of the year. As we come out of breakup and people are able to complete their tie-ins and trucks are able to hit the road and things like that. Typically, starting about now into the third quarter and into the fourth quarter, we typically see volumes ramp up. Fourth quarter and first quarter are our seasonally highest months of the year in terms of our throughput. That's the trend we're expecting.
If that trend holds true, do you then see a multiplier on the facility side of your business? Especially if you've got a tighter frack market at this point in time and there's a bunch of other factors as you start to feed more volume through your entire network.
Yeah, exactly. As those volumes are coming on, primarily driven by the condensate barrel that's moving down the pipeline, all of your associated NGLs and then your gas, for example, the Duvernay facility will be coming on stream here in late 2019. Yeah, we will be seeing those coming at us, Andrew.
Just we don't want to overstate that because recall our fracs are 100% take-or-pay, so not every barrel that shows up is incremental revenue in the frac. It does manifest in the marketing side where it's more of a variable revenue stream based on volume. Just don't double count that.
Understood. Just one final question, and it's just with, I think, a full quarter of Redwater, the cogen under your belt. Do you feel you have a more sophisticated knowledge of just what's happening on the power market and how to position yourselves?
Well, I can say that, yeah, with that in the full quarter now, we actually did see, and I think it's in the MD&A, we did see some lower power costs in the Facilities division. Overall, we still corporately still saw higher power cost in the quarter. To answer your question, in short, yes, we do. That's quite the asset.
Yeah. It's a pilot again. We like what we saw, and we think there could be applicability at Empress and also at CKPC for similar facilities to just to really vertically integrate our demand for power. Stay tuned on those.
All right. That's great. Thank you.
Your next question comes from Robert Catellier from CIBC Capital Markets. Your line is open. Please go ahead.
Yeah, thank you. I just wanted to follow up on the NGL side here. You're pointing to a 13% increase in volumes over the period. I wonder how much of that is market share gains versus the fact that there's just more production out there and the market's growing. Do you have a sense on where you stood on market share gains this last contracting season?
With 100% take or pay, it's most likely just existing guys using their fracs more fully. If we look at the, for example, the VMLP assets, they've got a lot more liquid yield and that finds its way downstream. It's people who have contracts more fully utilizing them. I don't know that that would really I'm implying, of course, that market share gains means that we're taking them away from other fracs. I don't think that's the case. I think it's just because of the take or pays, people just using their capacity. Jaret, do you agree with that?
Yeah, absolutely.
Yeah. Okay.
No fair call.
Yeah. That's helpful. There's talk now about a Prince George petrochemical plant under development. I'm wondering if you see a role for Pembina in that, either in the project itself or in supplying the project with infrastructure.
We've talked about supplying ethane to others for a while, and clearly, we have an important role to play in the basin, with ethane supply and clearly, that's upside that we could have and that's just a role we'd gladly play for any demand source.
Too early really to say anything about that?
Rob, we've worked on it. It's in the public domain, I believe our proposals to the Alberta government around ethane supply. We think we're uniquely qualified to procure, say, up to 100,000 barrels a day of ethane. We don't think anyone else can do that. It's something that we can do and we're ready to do.
Okay. Then just on Jordan Cove, I think the comments were, you're confident in the commercial support for the project. The state of the NGL market, I guess, fluctuates a bit, and there's a couple projects on the Gulf Coast that have had approvals, but seem to be having difficulty ramping up the commercial support. Maybe you can spend a minute just indicating what you see in terms of the commercial demand for Jordan Cove.
We continue to have conversations, Rob, with the offtakers. They remain supportive of the project. Again, I believe there's a perspective of, there's not many LNG opportunities on the West Coast of North America, particularly on the West Coast of the United States. I think as well, the Gulf Coast projects.
There's lots of competition for there. Where your end market is may dictate what your ultimate cost for delivery or landed price in whatever market you're going to. I think people are looking for diversification away from the Gulf Coast for a variety of reasons. And I think Jordan Cove provides that diversification, where you have the ability to be attached to a Western Canadian Sedimentary Basin with challenged feedstock pricing. You can connect to the Rockies basins through our Ruby Pipeline, again, with challenged pricing on a go-forward basis. We believe Jordan Cove is well-positioned, and I think that's been evidenced by our continued support from our off-takers. They like the idea of Jordan Cove and are supporting us through this permitting exercise that we're going through.
Rob, also consider that some of our off-takers may have reserves in the ground that, in today's market or even in the foreseeable future, don't have a lot of value in the ground. This is a way to get them out of the ground, and they otherwise might not. It's not just comparing Gulf Coast netbacks to Jordan Cove netbacks. It's also comparing gas that has very little value or perceived value in the future in the WCSB versus them needing to buy gas on the open market. There's a whole another layer that's at play here.
Yeah, there's a lot more benefit to if you have the reserves, right?
Absolutely.
Yeah. Thank you.
Again, if you would like to ask a question, please press star, then the number one on your telephone keypad. Your next question comes from Robert Kwan from RBC Capital Markets. Your line is open. Please go ahead.
Good afternoon. Maybe I'll start and just stick with Jordan Cove here. You made the comment earlier, Mick, that you've been able to take the cash burn down quite dramatically at this point. Does that change how you think about the timing around bringing in potential joint venture partners that cause you to want to wait, given the cash burn's pretty small at this point?
Yeah. I guess that's fair. If you go back to 2018 between PDH PP and Jordan Cove, it was about CAD 20 million a month, right? It was substantial and PDH PP worked out, so that knocked half of that burn. As we disclosed, we've got a lot of the right of way nailed, and that cost a lot of money. We had to do all the engineering on the Pacific Connector Gas Pipeline. That cost a lot of money, and now that's behind us. We're really down to spending money on regulation, and we've come so far, and there's not a ton of money ahead of us. There could be some time, but not a ton of money involved in seeing our way through to approval and finding out what the next step is with the state.
There's not a ton of urgency to partner up on this thing. If the ideal partner came to us and said, "Hey, we'll step into this together with you," we would consider it. It's not on the critical path for us. The getting the approvals is on the critical path.
Got it. I guess just on the easements, I think you mentioned you got about 80%. Just with respect to the other 20, is that more just a matter of time/negotiation or is there any kind of sticky points that you're worried about? Put differently, would you think you're going to have to go to eminent domain proceedings?
Yeah, we're about 82% right now, Robert. We actually thought we could get or approach 90%. If we continue to spend, we didn't see that as criticality at this point. We may still get there through time. There will be a small portion of this right of way that where we will have to use the process that are available to us to secure the right of ways that are there. We think it'll be small. We've had great success. When we told the regulators what success we've had here, they were quite thrilled and impressed of the progress that's been made. It's a dramatic change to when this project was denied the first time. Again, we think we could get more, but it's also a spending issue that we're trying to manage.
If you step back from it, what it says is that the people who are "most impacted" by the project have signed up. People who are out there saying different things are generally not the most impacted, and they tend to speak for the most impacted. The most impacted have spoken.
Got it. I guess turning to Northeast B.C. and building upon your desire to build a frack up there. I'm just wondering, as you go up to customers, what's the selling features to go through your potential project and then the Prince Rupert terminal, given there are players up there that have similar assets trying to sell the same thing? What are you bringing? Is it optionality to do a number of different things with the molecule? Is that what you're offering, that type of optionalities or something else?
Robert, it's Jaret here. It really comes down to our two core assets. One is our integrated value chain, right? That's number one that brings the customers to the table. The second one is truly that increased netback from not transporting that barrel. It's such a long ways from that Fort St. John area north of there all the way into Fort Saskatchewan, to rail it all the way back. It is a significant cost. There's that benefit there. We obviously, Jason and his team, they have the benefit of reselling that capacity downstream. It's really the integrated solution and the increased netback they get from saving on costs.
Okay. Maybe just to finish on the M&A market. Your stock's held in okay. We've seen certain kind of segments of the market across North America come under some pressure here. Is there anything, obviously you probably don't want to get into specifics, but is there anything just kind of generally here that's piquing your interest now that maybe wasn't a quarter or two quarters ago?
Yeah. Your assessment that our phone is ringing a lot is correct. Scott and Cam have kept such a tidy balance sheet that we have a lot of capability. We are looking at a lot of different things. We also have a huge greenfield/brownfield plan, CAD 3 billion underway, and if we go Phase IX Northeast BC, there's a lot of demand for capital. We got to get Scott to not sit on his wallet quite so hard. Those acquisitions always have to compete with greenfield and brownfield, and that's a challenge because we have some really great projects. Including at our board meeting today, the topic at Pembina's board meetings are capital and people allocation. Do we have enough money and enough people to do a really good job? It's not about deal flow.
We're just flush, which you wouldn't guess with certain of the commodities being disadvantaged. We are just flush with deal flow.
Okay. That's great. Thank you very much.
There are no further questions at this time. I turn the call back over to the presenters.
Well, I'll wrap up. It's Mick. Again, thanks to everybody for staying late. We're really pleased with the quarter, and thank you very much for your ongoing support. Wherever you are, have a great August long weekend. Thank you.
This concludes today's conference call. You may now disconnect.