Pembina Pipeline Corp Q2 FY2020 Earnings Call

Thank you all for joining us today for Pembina Pipeline Corporation's Second Quarter 2020 Results Conference Call. I will now turn it over to Scott Burrows, Senior Vice President and Chief Financial Officer. Please proceed.

Thank you, Julianne. Good morning, everyone, and welcome to Pembina's conference call and webcast to review highlights from the second quarter of 2020. I'm Scott Burrows, Senior Vice President and Chief Financial Officer. On the call with me today are Mick Dilger, President and Chief Executive Officer; Jason Wiun, Senior Vice President and Chief Operating Officer Pipeline; 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. First, I hope everyone listening to this call today is safe and healthy. 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 management's discussion and analysis dated August 6, 2020, for the period ended June 30, 2020, which is available online at pembina.com and on both SEDAR and EDGAR. Before we discuss the second quarter results, I'd like to first give Mick a chance to make some opening remarks. Mick, over to you.

Thanks, Scott. Good morning, everyone. Hope you're all doing well. The world has certainly changed a lot since our call in early May, and even the second quarter results feel like a distant memory. However, the second quarter was a very important one for Pembina because it was proof of concept for many of the themes you've heard us talk about for many years. First and foremost remains our commitment to each of Pembina's stakeholders: customers, investors, communities, and employees. COVID-19 assessed us all and provides a challenge unlike any in our company's history. We remain proud of the actions we've taken to balance the needs of all stakeholders. Pembina's business continues to operate safely and reliably throughout the pandemic, ensuring uninterrupted service to our customers, which is a testament to the company's dedicated staff. We also continued projects in flight to ensure customers had the service as they needed. Second is our commitment to the financial guardrails. Our strong contractual underpinning, fee-based take-or-pay revenue streams, prudent dividend payout, commitment to a BBB credit rating, and focus on working with solid counterparties, all are elements that have contributed to Pembina's resilience through this historic crisis. Indeed, the delivered diversification of Pembina's business across geographies, basins, commodity types, and counterparties has positioned us very well. With this strong foundation, we expect to exit 2020 in a solid financial position, providing flexibility to restart various capital projects when it is prudent to do so. Further, we remain confident in our ability to provide a stable and growing dividend, as we have through past recessions. It's worth noting, too, that our top customers, many of which have just reported their own Q2 results, are performing well under the circumstances. Although higher prices are likely needed to incentivize significant growth in the basin, given the recovery in commodity prices, many are generating free cash flow after dividends and CapEx and are focused on paying down debt and strengthening their balance sheets. This is very supportive of Pembina's counterparty credit portfolio. I congratulate all of them. Now I'll pass it back to Scott to discuss the second quarter highlights and our outlook for 2020.

Thanks, Mick. In addition to the impact of COVID-19 and the decline in commodity prices, the major factors impacting the second quarter relative to the same period in the prior year was the Kinder acquisition. The acquisition continues to outperform our expectations for 2020, and the quality of the customers and cash flows from these assets has shone through in the second quarter, providing greater stability during a challenging time. One of the major drivers of the Kinder acquisition was the opportunity to diversify and strengthen the quality of Pembina's cash flow. The acquisition of strategically located assets supported by strong contracts with investment-grade counterparties strengthens Pembina's financial guardrails and provides enhanced diversification of basins, currencies, and markets. Adjusted EBITDA for the quarter was $789 million, a 3% increase compared to the same period last year. The increase was due to the contribution of new assets following the Kinder acquisition and a realized gain on commodity-related derivatives. These positive contributions were partially offset by lower margins on crude oil and NGL sales in the marketing business and lower interruptible volumes on Alliance as a result of the narrow AECO-Chicago price spread. Second quarter earnings of $253 million were down 62% over the same period in the prior year, largely due to noncash factors, including higher deferred taxes due to the enactment in the second quarter of the prior year of Alberta's Bill 3, which reduced Alberta's corporate income tax rate from 12% to 8%; higher unrealized losses on commodity-related derivatives; and lower contribution from marketing and Alliance. As mentioned previously, these declines were somewhat offset by the contribution of additional assets from the Kinder acquisition and lower G&A and other expenses. During the second quarter, the impact of low crude oil and NGL prices was seen through lower producer activity and a temporary decline in physical volume in certain Pembina's businesses. Total volumes during the second quarter were just over 3.4 million BOE per day, up 1% over the same period in 2019 or down 2% when compared to the first quarter of 2020. I'd like to highlight 2 important points regarding volume. Firstly, it is worth noting that the vast majority of the quarter-over-quarter reduction was contained in our Conventional Pipelines business unit. Volumes in our other pipeline business units as well as the Facilities division were essentially flat from the first to the second quarter. Secondly, the high proportion of take-or-pay contracts in our business leads to a catch-up of volumes and revenue in the second half of the year. Pembina continues to expect 2020 adjusted EBITDA to remain within the previously disclosed guidance range of $3.25 billion to $3.55 billion, albeit near the low end of the range. This outlook contains an expectation that the 2020 adjusted EBITDA contribution from the Marketing & New Ventures Division will be approximately $125 million lower than was assumed in the midpoint of the original guidance range. The impact of lower interruptible revenue in the asset-based business is expected to be largely offset by operating and administrative cost savings. We predict the majority of these savings can be maintained in 2021. Turning to our balance sheet and funding ability. Pembina further enhanced its liquidity position during the second quarter by terming out approximately $850 million of debt drawn on the company's credit facility and establishing a new $800 million revolving credit facility. Following the early redemption in July of $200 million in senior notes originally due in 2021, Pembina's liquidity position currently stands at $2.8 billion. With no debt maturities for the balance of 2020 and $600 million of maturities distributed throughout 2021, Pembina's liquidity position is ample. The recent debt issuances at a weighted average term to maturity of 17 years at a rate of approximately 3.2% provide a strong endorsement from a broad cross-section of the debt capital market. Combined with the recent affirmation of Pembina's BBB credit rating by both S&P and DBRS, we believe the company's strong financial position is fully affirmed. Moving on to the capital investment program. During the first quarter, the company took the prudent steps of deferring $4.5 billion of capital projects. Pembina is on track to realize a reduction to its 2020 capital investment plan of approximately $1.1 billion. However, challenging weather conditions and COVID-19-related precautions and delays resulted in capital cost overruns in 2020 of approximately $100 million. Additionally, during the second quarter, Pembina also added approximately $90 million of projects. With the modest improvement in commodity prices, many investors are asking about our deferred projects and the conditions under which they would restart. We view the deferred projects in 3 groups. Firstly, the Phase VII, VIII, IX Peace expansions will continue to be evaluated in consultation with our customers based on their needs and an assessment of future transportation requirements in the Western Canadian Sedimentary basin. Pembina is well positioned to handle all customers' volumes. Secondly, regarding CKPC PDH/PP facility, the project team has substantially completed the activity specifically and cost-effectively deferred the project. The fabrication of critical long-lead items has continued and key talent and knowledge are being retained, all to preserve project value for efficient potential restart. Pembina and its joint venture partner continue to evaluate a number of factors related to the project. First, a necessary condition is the safety of all personnel to be assured. Second, while the immediate incremental costs associated with COVID-19 were contained by the decision to defer the project, the future and ongoing risks need to be understood and priced into the project cost estimate. Third, the full impact of COVID-19 on the global economy and future demand for polypropylene remains uncertain and needs to be carefully evaluated. Fourth, with both the federal and provincial governments as well as our project financing indicating extensions have or will be drafted, we remain confident for the original investment parameters to be reconfirmed. Finally, the project restart is subject to CKPC Management Committee approvals and each partner's Board. Thirdly, the Prince Rupert Terminal expansion and the Empress cogeneration facility are progressing for a potential restart. These projects are entirely discretionary and commence at any time.

In closing, in the first half of 2020, we've seen Pembina rise to an unprecedented challenge, reacting quickly and effectively in service of its stakeholders. Pembina's growth and diversification over recent years, combined with an unwavering commitment to its financial guardrails, ensured the company was well positioned for adversity. Pembina expects to deliver financial results within its original guidance range and exit 2020 in a strong financial position. This will allow the company to resume its deferred capital projects and continue its long track record of growth by providing customers valuable integrated services. As always, thank you to all of our stakeholders for your support. With that, we'll wrap things up. Operator, please go ahead and open the line for questions.

Your first question comes from Jeremy Tonet from JPMorgan.

I would like to begin by discussing the current volumes. Have all the shut-ins come back as you anticipated? I would also like to hear about the discussions with producers and what you're observing right now. How do you expect volumes to trend in the various basins for the rest of the year? I'm trying to gauge how the resumption is progressing.

Yes. We'll let Jason address that question. As Scott mentioned, most of the variability is in conventional, and Jason will provide more details.

Jeremy, so I guess, May, as we mentioned in our release, was kind of the low point for our volumes. We had 1 week in May where volumes hit their low point, and then they've slowly been recovering since then. As of this moment, we're not quite back up to where we were in January and February, but we are seeing things sort of recover steadily in that direction. I think our discussions with our customers continue to be positive. There are still positive developments out there. Customers are still committed to their forecast. But obviously, they're looking at their budget right now and what they're planning to do for the 2021 year. There's some M&A activity I'm sure you've seen going on in the market that we think is positive and will lead to continued strength in some of those areas. But at the moment, things are recovering slowly. It's kind of an unprecedented situation. So I wouldn't really say it's as expected because I don't know necessarily what to expect. It kind of depends on the demand for the commodities.

Got it. That makes sense. I was wondering, as we consider 2021 and capital expenditures, do you expect it to be in line with what you did in 2020 or to decrease from there? Some projects might come back into focus, as you mentioned. I'm just trying to get a sense of how it might turn out.

I'll discuss the Peace expansion first. We are currently assessing Phases VII, VIII, and IX. It's important to note that all these expansions, along with the existing Peace base business, are well contracted, which gives us the capacity to proceed with these projects backed by the contracts in place. We decided it was wise to survey our customers regarding their timelines and expectations for these expansions before moving forward with execution. We are nearing completion of these discussions with the majority of our customers and anticipate making a decision on the timing of the expansions by the end of this year.

Jeremy, Mick, we have significant flexibility in 2021. Our capital program is under $0.5 billion for the projects we know we're undertaking, which is a stark contrast to our expectations at the beginning of 2020. In 2019, our spending was $2.5 billion, and we managed to reduce that by about $1 billion. For 2021, our capital expenditures will drop another $1 billion. This gives us ample cash flow exceeding our capital expenditures in 2021. As Jason noted, and with CKPC as well, we have the ability to bring those projects back, but we need to consider what is beneficial for our customers. They do not need additional capacity and take-or-pay contracts without any actual volumes. Our decision to defer projects aligns with customer requirements.

Understood. That makes sense. I want to briefly address marketing and get a sense of things. You mentioned that there is an expectation for marketing to be $125 million lower than the midpoint guide. I'm curious about the guidance for marketing in the latter half of 2020 and into 2021. Is marketing expected to follow a new, lower trend based on the current commodity prices? I’d like to understand how that might develop, considering the current curve.

Yes, Jeremy, it's Stu. We've seen a low following the collapse in commodity prices, but we are noticing some improvement. We believe this will continue to strengthen in the second half of 2020 due to an increase in volume and some recovery in commodity prices. We also expect further improvement into 2021. Overall, we think we've moved past the low period and will see strengthening for the rest of this year and into 2021.

The key point to focus on is the resilience in natural gas and the decline in liquids this year, which has impacted our operations. The decreased frac spread has been significant. If we can reach a stable natural gas price while liquid prices rise into 2021, it could unlock substantial revenue opportunities for us. Keep an eye on those trends, Jeremy, as they will help indicate what to expect in 2021.

Got it. Just real quick, does the caps deferral, has that been impacting, I guess, recontracting on Peace at all? Has that been helpful in any sense?

I think existing infrastructure always has advantages because it's real, it's reliable. And so if you're a customer, you've got to think, am I going to count on the pipeline that's there or am I going to count on a pipeline that might be there? And so we think, overall, it's been positive for our discussions with customers.

Our next question comes from Matt Taylor from Tudor, Pickering, Holt.

Just wanted to follow up on Jeremy's question on marketing. The $125 million impact, does that include any offsetting assumptions on realizing once you're contango? I noticed that you had proactively added some lower-cost NGLs. And then also, is the sharp recovery in crude pricing and volumes returning in that $125 million impact as well?

Yes, Matt, it's Scott here. That forecast is from a couple of weeks ago, so it reflects the best information we had at that time. It's also important to mention two other points. First, we experienced a $10 million cavern loss in Q2, which was a one-time occurrence that negatively affected our earnings for that quarter. Additionally, if you look at the NGL sales volume, you'll see that it decreased significantly from Q2 to Q2. Given the margins at that time, we decided to store some incremental NGLs, hoping to monetize them in the latter part of this year and possibly in early 2021. Therefore, part of the weakness in this second quarter was also a deliberate choice to postpone some of our NGL sales volumes.

Great. I wanted to discuss the expansion potential at baseline and your plans for adding tankage at the facility ahead of TMX. Although we are a couple of years away, I assume customers are starting to consider this as we get closer. Any insights on that?

Matt, it's Jason. So we're currently working with our partner there, evaluating the cost of that expansion. We're currently looking at the site, starting to get some of the prep work done on the ground to get that site ready for expansion, putting the estimates together to figure out exactly what that expansion would cost. But we're aligned with your thoughts there. Once TMX comes into service, we believe there's an opportunity to provide both storage and terminaling services to be able to provide batches onto TMX and things like that for our customers as well and storing products. So that does seem to be a catalyst, and just trying to narrow in on the timing of when that is, is a bit of the science that we're trying to do at the moment.

Great. And then one last one for me. You talked about interruptible revenues being offset by OpEx and G&A savings. Is that target still $100 million? I know that's what you disclosed on Q1, and I'm just wondering how much of that is left to be realized in the back half of this year.

We are highly confident that we will reach our targets. Currently, we are performing at or above our forecast, which gives us strong assurance. We expect these savings to persist, especially considering that our committed capital is $1 billion less than it was in 2021 compared to 2020. We have no reason to believe that we cannot sustain $50 million in G&A savings and $50 million in OpEx savings throughout 2021.

Just to clarify, was that $100 million realized in Q2?

Not. It'll be realized by the end of the year. Like we recall, we kind of announced at early Q2, by the time we've got really organized it, we were starting those savings kind of in the June timeframe. And so that $100 million was really realized in, call it, 6 months, give or take, over the back half of the year. But we're forecasting meeting or exceeding that right now and expect to be able to continue that level of efficiency through 2021.

Your next question comes from Linda Ezergailis from TD Securities.

I'm wondering if we can follow up a little bit in drilling down to understanding some of the moving parts in your marketing business in the quarter. Can you elaborate a little bit more on the nature of the operational issue in the storage cavern? Has it been resolved? Is it discrete to this one particular cavern? Or is there some systemic things that you might want to remedy across your franchise?

Linda, Jaret here. Yes, it was contained to 1 cavern, and it has been mitigated as we speak. So it's not a systemic issue, no.

And can you describe a little bit what happened in the product? Or...

Product was C2+. And I won't get into the technical nature of the loss, but yes, it was C2+.

Okay. And with respect to the guidance range, I'm wondering what might move the 2020 results to the upper end of the range? Is it purely volumes and margin? Or are there other factors? And maybe you can talk about the main things to look at beyond liquids pricing?

Yes, Linda, I can unfortunately say that we're reaching the top end of the guidance range, which is $150 million. It looks like $3.55 billion is not achievable for us. We're expecting to be between the midpoint and the low point of our projections. To move from the low point, we would need to see a significant improvement from areas like Drayton Valley, where we are still considerably behind. That's one of our two systems, the other being Swan Hills, where we lack a substantial number of take-or-pay contracts. We need to observe a rebound in the Drayton Cardium and wider spreads in crude WCS, which are trending positively. Additionally, we need a noticeable increase in the price of propane. We have a significant amount of propane stored, and due to commodity prices in the second quarter, we didn't pay much for it. If propane prices rise, it would contribute to a healthy margin in the fourth quarter. Those are the factors that could help us move from the low point toward the midpoint, but we currently don't anticipate going above the midpoint.

Okay. As a follow-up regarding your piece of Northern systems, you have about 0.25 million barrels per day of currently available physical capacity. I'm curious how much of that capacity is take-or-pay versus spot capacity. I'm wondering if, as that fills up, some of the margins might not be fully additive since they could be displacing and releasing other customers from their take-or-pay obligations.

Linda, it's Jason. So in terms of the take-or-pay, most of our customers are operating somewhat close to their take-or-pay. So when you think about how much take-or-pay revenue we're actually recognizing in the back half of the year, it's not a huge amount of take-or-pay revenue. So all incremental volumes that we do get is really going to be profit from that perspective. Yes, so I think like if we do get incremental volume from customers under contract, that will add incremental margin. And then some of the trucking volumes are where you see some of the volume back out, whether they come through third-party terminals or our own track terminal. So that's where some of the opportunity lies for us at the moment.

Your next question comes from Rob Hope from Scotiabank.

A follow-on question on the deferred projects. When we take a look at Phase VII, VIII, and IX of the Peace expansions, are you looking to pick those up as they were originally planned? Or do you have some flexibility to alter some of those projects to better suit your customers' volume outlooks?

Yes, that's a great question. In the last six weeks, we have explored various options related to the master plan. We definitely have less capital-intensive alternatives that we can implement in the near term. However, our main focus is on developing a robust system for the future, which involves more products and pipelines extending almost from the B.C. border. This approach provides us with significant flexibility, reduces our dependence on storage, and allows us to integrate products mid-pipe instead of solely at storage hubs. It also enables us to partially loop systems, granting us remarkable future flexibility. Therefore, at this point, we are committed to building the right master plan.

All right. That's helpful. And then just a follow-up question. Can you comment on the changes that were made with the PG&E/Ruby contracts?

We can't specifically comment on customer contracts. But I think, really, I guess, the way to characterize it is to give both them and us more flexibility.

Your next question comes from Andrew Kuske from Crédit Suisse.

The question really relates to the producer M&A that we've seen and the reduction of counterparty risks that it does for you in the front end. I guess, when you think about it on a longer-term basis, what does it mean for you? Do you wind up having better counterparties and effectively bigger volumetric opportunities? Or do you see a little bit of competition for some of the producers that like to do their own thing on the processing side?

It's really about each customer individually. Your insight that the deals will likely become larger and more integrated is probably correct overall. For example, in the last five years, our collaboration with the Chevron/KUFPEC joint venture has created an area alliance where we handle processing, transportation, and fracturing, along with product and marketing cooperation. We believe these larger agreements make a lot of sense as they offer economies of scale necessary for the modern oil and gas sector to spread costs over significant volumes and remain highly competitive. Drilling multiple well pads with numerous horizontal segments and extensive liquids handling capacity is very capital-intensive and requires substantial water resources. However, this approach leads to remarkable longevity and economies of scale, which will have the most significant impact on Pembina. We are also glad to work with smaller producers, particularly those in the Drayton Valley and Swan Hills regions where we have excess pipeline capacity. They do not need to engage in large agreements, although they may be more sensitive to commodity prices. Jaret, would you like to add anything?

No, I think you nailed it, Mick. I think in this new world where everyone needs a higher netback, I think not only will you see consolidation on the upstream side, Andrew, but I think, as Mick said and Jason said, like we've got a lot of capacity on the pipe. We need to stop overbuilding our infrastructure and consolidating a lot of this and putting maximum amount of molecules through these facilities. So even though some customers, I would say, may typically have wanted to build those assets themselves, I think they may be looking at alternative solutions to focus their core competencies on what they do and let people like ourselves focus our competencies on what we do great.

Okay. That's helpful. And then I'll go from the big broad to a bit more narrow. And just on the Vancouver Wharves business, how are you thinking about that and, I guess, about the year that you've added on the books, thereabouts?

Not much of that terminal is based on hydrocarbons, and we are evaluating the potential for hydrocarbons there. For instance, diesel is currently being processed at that facility, and there are hydrocarbon tanks as well as some vacant land. The berths are not fully in use, but the location is in the heart of Vancouver. We are considering all these factors to determine the best use for our company compared to what it might be valued at by others.

Your next question comes from Robert Kwan from RBC Capital Markets.

I wanted to revisit some of the stalled projects. You've outlined the three categories. Based on the current situation, which of those three categories do you think is most likely to resume activity the soonest?

That's a great question. It's a bit like predicting what will happen next with COVID since COVID influences demand. If the U.S. had not experienced many cases, I would say we would likely bring all those projects back. However, estimating future demand for hydrocarbons and the resulting pricing, which will influence drilling, is challenging. On a positive note, our customers' recent strong performance in the Peace area is encouraging. We plan to consult with them and let them decide whether to proceed or not. The situation with CKPC is less clear because we need to feel confident about global GDP growth, which is uncertain at the moment. Nobody can predict the future exactly. As for the timeline, I believe 2025 is now the expected on-stream date, which is still a ways off, so we are making educated guesses. In the next eight weeks, we have to decide whether to move forward this winter or postpone again. These are tough decisions, and I hope you understand the complexities involved.

And I guess, Mick, at the beginning of the call, you made a statement that you have a focus to exit 2020 strong, and you're looking at the ability to resume the growth when prudent. I guess, if you pair that with your outlook that the business is still uncertain and you're trending to that lower half of the guidance range based on the outlook you've got, is there any reasonable possibility that you bring these projects and start putting them into construction in 2020? Or is this very squarely 2021 at best?

There is a possibility that we could move forward and say we will start in 2021. The beginning date for CKPC would be March 2021. For Phase VII, we have 65 kilometers completed and a stockpile of pipe, so we have a clear re-estimate and are approved. We could accelerate that project. We’ll be contacting customers in the next four weeks, and the conversation will be whether they want to start or delay based on their contract. If they decide they want to start, we will begin. So we will wait to see their response.

Okay. And then just last on this topic, can you clarify the new growth that you've recorded? Is that characterized by high returns and quick payback? If so, how do you see Phase VII, VIII, IX fitting in alongside some of the lower-capital, more configurable options compared to laying new pipe?

Yes, we can initiate some of the smaller projects, like the Prince Rupert expansion or Empress cogeneration, when we determine it's the right time. We want to assess the export landscape as we approach fall, which will inform our decision on whether to proceed with those. For cogeneration, we can begin anytime, and we will evaluate that as well. It's a valid point that these projects are less dependent on external factors since cogeneration provides self-supplied power. Our existing cogeneration facilities are performing well, which means we could potentially revive those projects. We also discussed the baseline tank project, which could be reactivated. Our marketing team could become a customer for it, or we might offer it out to clients for a fee, especially with the TMX coming online. We have a range of projects in the pipeline, as well as additional initiatives that we haven't deferred, all of which are being prepared for fast execution, meaning they are fully engineered and have the necessary regulatory approvals. This allows us to respond swiftly to market changes. Obtaining regulatory approvals and completing engineering for our capital program is relatively minor, and during these slower periods, we can get ahead of these processes. This approach will enhance our flexibility. Overall, we remain cautiously optimistic about gradually improving conditions in the sector.

Okay. Can you clarify the $125 million figure, which is lower than your original midpoint? Has there been a recent change, or are you just providing more details to the market? Also, it seems that the 5% to 10% of EBITDA coming from commodity remains consistent with previous disclosures.

Yes. Robert, I mean, really, again, this is kind of the best information we have at the time. This is our current forecast. This is really about giving incremental disclosure, trying to give people the information that the vast majority of the kind of reduction to the low end of the guidance range was from the commodity-exposed portion of the business. Most of this is COVID related and the downturn in pricing. But to be honest, some of this was starting to kick in, in February when we had the initial kind of price war between Saudi and Russia. So this has kind of been a trend throughout the year and to the point where we are today. And then as incremental disclosure, we thought we'd let The Street know. So you're right, our kind of commodity-exposed portion of the business, we've kind of talked about in that 5% to 10% range. If we were to update that today, it would be 5% or less, maybe 5% to 3%. And I'll just build on that. I mean when we set our guidance, we truly set it at the midpoint of what we think is going to happen. And the wiggle in our guidance is usually highly correlated to kind of 1090 on marketing, net of what we think we might be able to mitigate in a down market. So going two years back when we raised our guidance twice because we were kind of at C95. And then last year, we were in the upper end of our guidance, and so it did cover the positive wiggle in guidance. And this year, through a bit of hard work, it still is covering the negative wiggle in marketing outcomes. And so I think looking back, the way we do guidance has served us quite well.

Your next question comes from Robert Catellier from CIBC Capital Markets.

I was wondering if you could give an update on the outlook for Alliance pipeline with respect to the eventual renewal there in light of the AECO-Chicago differential and some recent customer comments about the fee structure. And maybe if you could add to that, how the outlook for associated gas in the Bakken, how it plays into the equation?

Robert, it's Jason. This year has been quite different for Alliance in terms of the strategy between Chicago and AECO. Traditionally, we've been in a favorable position, but this year has been unusual. Looking ahead beyond Q3 and into 2021, we expect those spreads to return. We're optimistic that in the second half of the year, volumes will begin to recover. We also believe there’s justification for holding on renewals. Historically, it has been a challenging market for our customers, and we think they will continue to appreciate that diversification. You mentioned the associated gas in the Bakken, and when considering the overall gas production landscape in the lower 48, we believe there is optimism that gas prices will remain strong in the Chicago market for the long term. Overall, we are confident that conditions will improve for Alliance regarding recontracting compared to the first half of 2020.

Yes. And I would just add, if you zoom out and Jason's comments are wrong, we're going to make a lot more money on our extraction business because that means gas prices are lower. And so whether it's at an Aux Sable or at Empress, there kind of is a bit of a natural hedge in there.

Right. Just moving to the CKPC and what's required to restart there, you had some pretty good color. But I just want to make sure I understand the nuance here and what you're looking for on the future polypropylene demand, given that you do have some contracts. So are those contracts still in place and still valid? And what do you really need to see in light of those contracts from the demand side of the equation? Or is it just a question of you have a partner and everyone has to be comfortable on where they see demand?

Robert, it's Stu. We're looking at, I think, the global context. We'll revisit and look at the project economics, ensuring that the investment thesis is still valid and whole to drive through. We still believe that, again, the Western Canadian Sedimentary Basin provides a cost advantage to produce the polypropylene product. We think we are in a logistic advantaged location for market access. And we'll rerun the economics here in the third quarter and update our perspective of our ability to be a low-cost polypropylene provider into the North American and global markets. That's the intent of the statement.

And then in terms of contracts, just like the phases of Peace, those contracts remain good and valid, and they don't have any kind of outside date concern at this time. So when we go, those contracts will go as well.

Okay. Regarding the security of the propane supply, I understand you're working on the project at Empress to address that. However, considering the reduced production of NGLs, which may be temporary, but with increasing export options, how confident are you in maintaining a low-cost position in light of the propane situation?

We are confident in our position. Historically, whenever this basin has responded to price signals, such as when the West Coast terminals significantly increase their demand for propane, we typically see a temporary increase in value. Subsequently, producers may reduce their plant operations to utilize more propane or someone might invest in additional infrastructure. Over the past 40 years, we have monitored the performance of the ethane market, and concerns like these have emerged intermittently. At times, it appeared there would not be sufficient supply for the polyethylene sector, estimated at 250,000 barrels per day. Currently, all gas pipelines, including Enbridge, TCPL, and Alliance, are operating at maximum heat capacity, and there is a substantial surplus of ethane being exported from the province, indicating we have an abundance of ethane. We believe that this basin is exceptionally productive. We will respond as soon as a price signal arises, primarily due to the high quality of the rock.

Your next question comes from Ben Pham from BMO.

I also had a question on CKPC and 1 of the references, the 3 you mentioned with respect to the federal and commercial government. And I was wondering, is that anything to do with the royalty credits there in terms of expiration dates, your ability to monetize those credits?

Yes. We have confirmed the commitments from both the provincial and federal governments regarding the funding. The Alberta government has stated that the royalty credits belong to them, and we are collaborating with them on the documentation for the extensions. Additionally, we are also working with the federal government on the grants we received from the SIF program and are confident that everything will be extended according to the government grants.

Okay. It seems that when this was established around 2016, there might be some sort of expiration approaching. However, it appears you feel optimistic about extending it.

Ben, it's Scott. We took advantage of some low interest rates recently. As we mentioned after Q2, we refinanced one of our existing 2021 notes at an interest rate 3% to 4% lower than its original issue rate. We're starting to make progress on that. Additionally, we have about $800 million on our credit facility, which we plan to term out in the latter half of the year to benefit from long-term interest rate savings. Regarding our preferred shares, we have considered optimizing them, but a normal course issuer bid is challenging due to the lack of liquidity in that market. Therefore, while we have thought about it, we are not pursuing that option at this moment.

Can I ask you about the recent news regarding Dominion and Warren Buffett? What are your thoughts on capital allocation and mergers and acquisitions? If your stock price were more appropriately valued, would you consider pursuing assets that could strategically fit Pembina, even in competition with Warren Buffett?

I think he made a really great deal when he bought the railroads about ten years ago, and it looks wise in hindsight. He’s likely to look smart again with this. Those assets have a long lifespan, and there’s a scarcity factor since it’s challenging to build new ones in that region. Our focus is on growing our business so that the combined value is greater than the sum of its parts. We’ve been careful in our approach and will continue to ensure that any acquisition has synergy. While the railroad purchase was a good move, it doesn’t create the same type of synergy we experienced when we acquired Provident and added downstream capabilities, or with Kinder Morgan through storage and cross-border pipelines that align with our infrastructure and export facilities connected to our rail fleet. These are the kinds of opportunities we believe can yield outstanding results over time. It’s difficult to see good deals that may not be as synergistic slip away, but we are committed to our strategy.

Your next question comes from Patrick Kenny from National Bank Financial.

Just to clarify on CKPC, if the project might be eligible for these additional grants that are being rolled out by Alberta this fall, I believe, on top of the royalty credits that you've already secured? And then also, just any thoughts on how this new program might bring some of your ethane-based infrastructure opportunities more into focus over the near term.

So we're investigating that. Again, our facility was granted under PDP 1 with royalty credits. PDP 2 was put forward by the Alberta government, and they've since then come out with the new program. You cannot, as we understand, collect both PDP 2 and the new program credits. We are investigating whether there would be additional opportunity for us, given that we were in the PDP 1 program. We look at it, and we're trying to manage that, and we have meeting set up to go and investigate more of that.

At a macro level, ethane is being sold for gas value right now. It's just being sold as heat and no premium. And so it seems like the sector is ripe for additional ethane consumption infrastructure, and we're well positioned to be the ethane production infrastructure.

As far as the new program, again, I think the government has listened, and it's trying to look at how other jurisdictions have gone about they're incentivizing development and infrastructure development. This is a program that is not a one-time event. It's ongoing, which I think from an investment cycle purposes, that's advantageous. And the government isn't picking winners and losers. Here, they're saying if you go forward and you build your assets, there are credits that could be made available to you. So I think it is an improvement. As far as the ethane development, I think it opens up for more people and perhaps greater competition for development as well.

Okay. That's good stuff. And then on the potential sale of the $200 million to $500 million of noncore assets, I guess, given all the actions you've taken over the past few months to boost your liquidity position, doesn't seem to be the same financial incentive to sell these assets, at least relative to maybe earlier in the year. So maybe just to comment on what the benefits might be from synergies or strategic rationale perspective that still support the decision to dispose of these assets?

Yes, Pat. The decisions to potentially monetize some assets were made kind of well before COVID-19 hit. We had started some of this work late last year and in the early part of this year. Really, we just disclosed it in March with the rest of the initiatives that were going on since it was underway, but really just started pre-COVID. And the point there is that these were never done for liquidity or balance sheet reasons. These were really born out of some pretty significant inbounds that we got, and we thought it was our job to at least explore them. So I think the point I'm trying to make through all this is we're in the process of investigating some of those but at the end of the day, if bids don't hit our retention value, then we won't sell. We don't have to sell. We weren't selling specifically for COVID-19 or balance sheet reasons. So we'll assess the bids in the context of our retention value. And if we get good value, we'll make the decision at the time. And if we don't get good value, we're happy to own the assets.

Got it. Okay. And then also, I appreciate the updated disclosure on your frac spread hedges. Just back to your comments, though, on looking to monetize your propane storage position that you've been building here recently ahead of next winter, are you also looking to lock in some of your propane marketing margins on top of your frac spread exposure? Or will those barrels be mainly exposed to an open position?

Pat, in addition to our frac spread positions mentioned in our release, we also have some of our winter inventory hedged. Therefore, we have price protection through the winter.

Your next question comes from Shneur Gershuni from UBS.

I don't want to overanalyze the question, but I would like to follow up on the propane-related inquiries and the variability in your guidance regarding the $125 million. Given that you've provided some hedging, is this primarily a timing issue? You currently have NGLs in storage, and depending on how frac spreads develop, you may realize this in the fourth quarter or roll it into the first quarter. Is the variability due to timing, or is the $125 million opportunity effectively a loss at this stage?

Yes. I think a large portion of it, the vast majority of it would be pricing, so degradation in margin. But there is a small piece of it that's timing depending on when we monetize some of the volumes that we stored in Q2. Some of those will likely be monetized in Q1 of 2021. So there's a small portion of that, that's timing, but the majority of it is generally lower volumes on the crude oil side just due to shut-ins that we've seen in kind of Q2 and into Q3 and then NGL margins as well.

And if everything came back, I realize this is a hypothetical, but everything comes back full boat volume wise, do you have the capacity to take everything out of storage while running your systems full boat at the same time? Or would that create a timing issue or capacity issue as well?

No. Obviously, we couldn't do it instantaneously. But no, we do have the infrastructure and the capacity to process all the incoming NGL volumes and be taking adequate storage out the back end.

Okay. I have one last question regarding costs. You've done an excellent job managing them, and this trend seems to be observed throughout the industry. Recently, it's been notable how significant the cost reductions have been at some midstream and broader energy companies. I acknowledge that you've made considerable progress, but are you encouraging your team to aim for even greater cost reductions than you've achieved so far? Given the entire shelter-in-place experience, have you had the opportunity to reassess all aspects, and do you believe there are chances for significantly more cost reductions to be announced in the upcoming quarters?

We’re really proud of what we’ve accomplished, and I appreciate the recognition. We are not planning any further staff reductions as we want to maintain our current capabilities. We believe that opportunities will arise in the future, although I can’t specify when they will materialize. Many of these opportunities will be driven by technology. For instance, we are finishing a new telecom system along our Peace right-of-way, which will provide us with incredible bandwidth to operate remotely with cameras and telemetry, enhancing our capabilities. This opens up new possibilities with machine learning, and as Jason mentioned regarding Peace Phase X, we can potentially increase our capacity by unearthing an additional 50,000 to 100,000 barrels a day through optimization of our pipeline flows. We haven’t had a break like this in a long time. Over the past decade, we have invested approximately $15 billion in green and brownfield projects without taking the time to optimize what we have. Therefore, we believe there are not only cost synergies but also revenue synergies that we will actively pursue. Improving the return on our invested capital is our top priority for 2021, and there is a lot of enthusiasm within the company to achieve that. Maintaining the synergies we outlined in 2020 into 2021 is our immediate goal, but this is just the beginning of our journey. We believe we can progress further, but it will take time.

I completely appreciate those comments. To clarify, I wasn't considering additional layoffs; I was focused more on enhancing productivity, which you seem to understand. It appears you're identifying opportunities for these enhancements in terms of revenue optimization. Is that an accurate assessment?

Revenue and cost. What we're trying to do is, along with getting projects shovel ready, ask ourselves how we can complete all those projects without increasing our headcount. The solution is to leverage technology to maximize our people's efficiency. It's not just about cutting costs in our current operations; it's about finding ways to grow without hiring more staff. I believe technology can facilitate this growth. So, there will be revenue synergies, cost synergies, and general and administrative synergies, but the key is expanding without incurring additional fixed costs. I think the most significant opportunity for the future lies in this area.

Your next question comes from indiscernible from Wells Fargo.

Just one quick question for me. I think you mentioned in the prepared remarks that you're seeing higher spot volumes on Ruby this quarter. I guess, what's driving that? And is there any opportunity to turn some of those interruptible volumes into longer-term contracts?

Yes. It's primarily influenced by the differences in pricing between Malin, Opal, and Alberta. With gas prices in Alberta being stronger, we have an opportunity to transport spot barrels via the Ruby pipeline. We are currently in discussions with Kinder Morgan about securing those volumes in long-term contracts.

Yes. In our region, which I am more familiar with than other areas in the U.S., gas-based producers are experiencing some uplift. This means that gas prices are increasing, which should lead to higher gas volumes. As this positive trend continues, we feel increasingly optimistic that the Alliance recontracting will proceed favorably, along with Ruby. All of this is interconnected. If you are confident about prices, you naturally become more confident about volume as well. We will see how this develops, but it's still early stages.

I'd also just add that, I mean, it goes to show you over the last couple of years, all these different pricing points have changed over time. So most producers like to have a diversity of endpoints because you actually can't predict which market is going to be making more money than the other. So we still think that having the Alliance and the Ruby, Malin and Chicago exposure is great because lots of producers are going to want a diversity of supply points.

Okay. That's great. And do you think these spot opportunities will persist for the next several quarters? Or do you think it's just kind of a one-quarter benefit?

We've seen it on and off over the last year, so at least from my perspective, fairly positive that it will continue for some period of time. But with the market as volatile as it is, it's kind of hard to predict.

We have no further questions. I would like to turn the call over to Mick Dilger for closing remarks.

Thank you all for your interest. I am very proud of what we accomplished in the second quarter. If we reflect on our feelings in March and compare that to where we are now, the world is still facing many challenges, but there are signs of improvement, thanks to the dedication of our staff and the strength of our customers. I commend our customers for their resilience. As time goes on, we are beginning to feel increasingly optimistic. Enjoy the rest of your summer and stay safe.

Ladies and gentlemen, this concludes today's conference call. Thank you for your participation. You may now disconnect.