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 speakers' remarks, there will be a question and answer session.
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 Q2 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 Voon, Senior Vice President and Chief Operating Officer, Pipelines Jared Sprout, Senior Vice President and Chief Operating Officer, Facilities Dew Taylor, Senior Vice President, Marketing and New Ventures and Corporate Development Officer and Cam Golday, 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. 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 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 765 $1,000,000 which represents a $65,000,000 or a 9% increase over the same period in 2018. Quarterly 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 remained steady.
The Q2 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 $550,000,000 in the Q2 of 2019 compared to the same period in 2018, primarily due to an increase in current taxes and a decrease in distributions from equity accounted 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 $2,850,000,000 to 3,050,000,000 dollars 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, and 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 3 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 expanding our current customer relationships. As evidence of that, we recently executed agreements for a significant term extension 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 2nd priority enhancing our business shows up in our secured growth program.
Our pipelines and facilities divisions are constructing $3,000,000,000 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 3rd priority, which is to access global markets and provide higher netbacks 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 twenty twenty is 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 and we continue to work closely with all agencies at all levels. At the local level, support for the project has grown and 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 and 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 30 $7,000,000,000 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.
Your first question comes from Jeremy Tonet from JPMorgan. Your line is open. Please go ahead.
Hi, good afternoon. Hi, Jeremy. Just wanted to follow-up on the guidance here. If I take kind of 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. And so 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 and M timing?
Jeremy, not I mean, there's obviously, you hit the nail on the head with the first comment, which was the NGL pricing is, I mean, 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. But certainly, that is an impact overall. Secondly, I think in the quarter, 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.
So based on where we are, I mean, 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. And along those same lines, to your point, we tend to have a higher integrity program in Q4 than we have prior in the year. So when you take all those factors into consideration, I think we're comfortable keeping our guidance range where it is.
Got you. Yes, I think it worked out pretty well last year. So hopefully we have the same thing again. I just also want to follow-up with some of your growth projects that you talked about before with Alliance and kind of anything notable to talk about there as far as something in the future that could come or also kind of 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, and 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 Shanahan at Aux Sable. And so, those things are moving forward. We won't really have our finalized costs at Aux Sable until about the Q4 of the year. So 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 costs, we're hoping that by the end of the year, we'll be able to make an FID on that project.
And then Jeremy, it's Jared 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. And so 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? And I guess maybe you can also touch on what that might mean for future peak expansions in terms of the pace and the scope?
So you're talking more generally in the WCSP, 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 the producers. But we continue to have a large amount of deal flow moving forward on the Peace Pipeline system specifically. So since about the Q3 of 2018, we've probably executed 200,000 barrels worth of contracts on piece. So 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. And 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 by most likely by producers with leaner gas, I think. And given we're primarily a hydrocarbon liquids company and our major gas asset is Alliance, which in fact has a very good netback and would not be curtailed. We're not overly concerned about that at the moment.
That's helpful context. Now there's 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. But 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.
But 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 piece 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. So 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 is 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 and even the pipelines, let's call those relatively flat. Just want to get a sense of kind of where you're seeing kind of your volumes trending and key drivers there and the outlook for the rest of
Yes. Hi, Rob, it's Garrett. Yes, volumes that end 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. So those are volumes that would typically flow to non deep cut facilities of ours and that have very, very as Mick mentioned, very, very low C5 yields.
Some of those volumes did get curtailed throughout the quarter. And then you have the immaterial amount of NGLs that normally would have shown up at the fractionating complex. So that's primarily it. We don't 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.
All right. And 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? Yes. So on the pipeline side, piece volumes with Phase 4 and 5 continue to ramp up as generally as we expected this quarter. They were impacted by on the Western system, we had a 3rd party outage that impacted the overall conventional volumes that sort of offset mass that increase that's happening on fees.
Right. And then 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 more a larger entry point in the potential U. S. Market?
Yes, right now, Robert, so it's only been about 15 days since we've taken over operatorship. So I can't really talk to the synergies today. But I can say that the owners are extremely excited about bringing those folks over into our organizations. And 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 Chicago land 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.
Yes. 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?
Yes, this is Stu speaking. So yes, 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 for lump sum bids from the EPC contractors and that's our contracting strategy for that type of facility.
All right, great. And then on the product front on the contracting side, any update on the 40% or so contracting level? And 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 be reach our 50% target on our contracting basis. So that we'll remain confident there. And we have numerous conversations ongoing and are excited to undertake and complete that work. And particularly these plastic, again, our facility and the idea to go with polypropylene as opposed to other plastics, these are higher demand plastic or recycled plastic and not just single use. It does have a variety of uses on a go forward basis, but it's largely 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? And I guess how long should we expect a decision to take from the time of your reapplication?
So 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 auctions, they have different time frames. And so we're working them all. And 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 for me guys, just within marketing and specifically to the crude oil midstream business, Wondering if you're able to take advantage of some of these new butane supply agreements or maybe we 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, wondered if you could take advantage of some of the cheaper butane supply?
Oh, I see.
Yes, I mean those 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, so much more than a tailwind if there happens to be any kind of arbitrage blending.
Okay. Thanks for that clarification.
Thanks,
Todd. Your next question comes from Matt Taylor from Tudor, Pickering, Holt and Company. 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 NUPICI and Mitsu there? I assume it's not material. I was just wondering if it was contract roll offs or what was just going on there?
Effectively, they're just staged contracts with the profile. The profile changes as the contract goes along. So 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. And then 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 frac tightness, how you guys are thinking about opportunities there to maybe ramp terminaling revenues or look to debottleneck fracs?
Yes. Hi, Matt. Jarrett here. Yes, so the utilization on the fracs are still fairly high. With respect to the terminaling, you may recall that Pembina finished quite a large rail expansion over kind of the latter half of twenty eighteen.
Year to date 2019, we've moved about 60% more railcars 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. And then one last one. In pipelines, it looks like the MVCs for conventional were marginal, but it looks like oil sands there had a bit of a jump in deferral variable revenue recognition. Is that more of just a one time sort of item? I'm just trying to think through the rest of the year here and kind of the shape of deferral revenue?
Yes. On the oil sands, it was 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 on a go forward basis, it will be as capital spent. So that could be anywhere between, call it, dollars 8,000,000 to $20,000,000 a year. So when you put that over a quarterly basis, it's relatively immaterial.
It will probably get lost in the noise of other things going on.
Yes, that makes sense. And then probably as we move into here into the back half the conventional system is when you'll start to recognize some of those as volumes and revenue starts to align?
Yes. And then on the conventional side, I mean, we have in our financial statements, we do lay out what we've recognized and what we've deferred on Section 7 on the selected quarterly information. So you can look at that and see the magnitude. On a year to date basis, we still have about 23,000,000 dollars 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 of times on my call that the volumes were generally in line with your expectations on the pipes, a bit flattish. There's also some outages. And then I guess the question is really what's the timing on the inflection point in your expectations on volumes to lift that business?
Typically, our volumes start to build in the second half of the year. So as we come out of break up and people are able to complete their tie ins and trucks are able to hit the road and things like that. So we typically starting about now into the Q3 and into the Q4, we typically see volumes ramp up. 4th quarter and first quarter are seasonally highest months of the year in terms of our throughput. So that's the trend we're expecting.
And then if that trend holds true, do you then see a multiplier on the facility side of your business, especially you've got a tighter frac 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?
Yes, 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. And so, yes, we will be seeing those coming at us, Andrew.
But just we don't want to overstate that because recall our fracs are 100 percent 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. So just don't double count that.
Understood. And then just one final question. 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 in the power market and how to position yourselves?
Well, I can say that, yes, with that in the full quarter now, we actually did see and I think it's in the MD and A, we did see some lower power costs in the Facilities division. But overall, we still corporately, we still saw higher power costs in the quarter. But to answer your question, in short, yes, we do. That's quite the asset.
Yes. And it's a pilot again, but we like what we saw and we think there could be applicability at Empress and also at CKPC for similar facilities just to really vertically integrate our demand for power. So stay tuned on those.
Okay. That's great. Thank you.
Your next question comes from Robert Catellier from CIBC Capital Markets. Your line is open. Please go ahead.
Thank you. I just wanted to follow-up on the NGL side here. There's a 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?
Again, with 100% take or pay, it's most likely just existing guys using their frac more fully. And if we look at, for example, the VMLP assets, they've got a lot more liquid yields and that finds its way downstream. And so, 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 pace, people just using their capacity. Jerry, would you agree with that?
Yes, absolutely. Yes,
that's helpful. And then 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 any demand source.
So too early really to say anything about that?
Rob, we've worked on it. It's in the public domain, I believe, our proposal to the Alberta government around ethane supply and we think we're uniquely qualified to procure say up to 100,000 barrels a day of ethane and we don't think anyone else can do that. So it's something that we can do and we're ready to do.
Okay. And then just on Jordan Cove, I think the comments were you're confident in the commercial support for the project. But the state of the NGL market, I guess, fluctuates a bit and there's a couple of projects in the Gulf Coast that have had approvals, but seem to be having difficulty ramping up the commercial support. So maybe you could spend a minute just indicating what you see in terms of the commercial demand for Jordan Cove?
So we continue to have conversations, Rob, with the off takers. They remain supportive of the project. Again, I believe there's a perspective of there's not many LNG opportunities on the West Coast and North America, particularly on the West Coast of the United States. I think as well the Gulf Coast project, there's lots of competition for there. There's where your end market is may dictate what your ultimate cost for delivery or land price in whatever market you're going to.
So 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. We 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. So 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. And this is a way to get them out of the ground and they otherwise might not. So 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. So there's a whole another layer that's at play here.
Yes. There's a lot more benefit if you have the reserves, right?
Absolutely.
Yes. Thank you.
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. So does that change then how you think about the timing around bringing in potential joint venture partners that caused you to want to wait, given the cash burn
is pretty small at this point? Yes. I guess that's fair. I mean, if you go back to 2018 between PDHPP and Jordan Cove, it was about $20,000,000 a month, right? I mean, it was substantial and PDHPP worked out, so that knocked half of that burn.
And then 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 Gas Connector. That cost a lot of money and now that's behind us. So we're really down to spending money on regulation 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 a FERC approval and finding out what the next step is with the state.
So there's not a ton of urgency to partner up on this thing. I mean, if the ideal partner came to us and said, hey, we'll step into this together with you, we would consider it, but it's not on the critical path for us. Getting the approvals is on the critical path.
Got it. And then I guess just on the easement, I think you mentioned you've got about 80%. So just with respect to the other 20, is that more just a matter of timenegotiation? Or is there any kind of sticky points that you're worried about or put differently, would you think you're going to have to go to eminent domain proceedings?
So, yes, we're about 82% right now, Robert. We actually thought we could get our approach 90%. If we continue to spend, we didn't see that as criticality at this point. We may still get there through time. So there will be a small portion of this right away that we will have to use the process that are available to us to secure the right ways that are there.
We think it will be small. We've had great success. And 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 product was denied the first time. And 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. So people who are out there saying different things are generally not the most impacted and they tend to speak for the most impacted while the most impacted have spoken.
Got it. I guess turning to Northeast BC and building upon your desire to build a frac up there. I'm just wondering kind of what's as you go out to customers, what's kind of the selling features to kind of 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. Kind of 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 optionality? Is there something else?
Yes. Robert, it's Jared here. It really comes down to kind of our 2 core assets. One is our integrated value chain, right? That's number 1 that brings the customers to the table.
And then 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 and then to rail it all the way back, it is a significant cost. And so there's that benefit there. And then we obviously Jason and his team, they have the the benefit of reselling that capacity downstream.
So it's really the integrated solution and the increased netback they get from saving on costs.
Okay. Maybe just to finish on the M and A market. Your stocks held in okay. We've 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 peaking your interest now that maybe wasn't a quarter or 2 quarters ago?
Yes. Your assessment that our phone is ringing a lot is correct. I mean, we Scott and Cam have kept such a tidy balance sheet that we have a lot of capability. So we are looking at a lot of different things, but we also have a huge greenfieldbrownfield plan, dollars 3,000,000,000 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.
But those acquisitions always have to compete with Greenfield and Brownfield and that's a challenge because we have some really great projects. So, it's we really 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 got we're just flush, which you wouldn't guess with the 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 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.