PAGP - NASDAQ

Good day, and thank you for standing by. Welcome to the PAA and PAGP Fourth Quarter 2022 Earnings Conference Call. [Operator Instructions] Please be advised that today's conference is being recorded. It is now my pleasure to introduce Vice President of Investor Relations, Blake Fernandez.

Thank you, Andrew. Good afternoon, and welcome to the Plains All American Fourth Quarter 2022 Earnings Call. My name is Blake Fernandez and I recently joined Plains as Vice President of Investor Relations. The company's attractive asset base, including its premier Permian operating system, coupled with a long-term capital allocation framework focused on increasing returns to equity holders makes it an exciting time for the company. I look forward to engaging with all of you throughout the year. In today's material, we're providing forward guidance for 2023. In an effort to improve communication and forecasting, we've made a few updates including an adjusted EBITDA range, which reflects potential volatility in the underlying commodity market, along with a volumetric outlook for each segment. The slide presentation is posted on the Investor Relations website under the News and Events section at plains.com, where an audio replay will also be available following today's call. Important disclosures regarding forward-looking statements and non-GAAP financial measures are provided on Slide 2. An overview of today's call is provided on Slide 3. A condensed consolidating balance sheet for PAGP and other reference materials are located in the appendix. Today's call will be hosted by Willie Chiang, Chairman and CEO; and Al Swanson, Executive Vice President and CFO. Other members of our team will be available for Q&A, including Harry Pefanis, President; Chris Chandler, Executive Vice President and COO; Jeremy Goebel, Executive Vice President and CCO; and Chris Herbold, Senior Vice President, Finance and CAO. With that, I will now turn the call over to Willie.

Thanks, Blake. We are very pleased to have you join the Plains team. To all on the call, good afternoon, everyone, and thank you for joining us. Today, we announced strong fourth quarter and full year results exceeding our expectations in both our crude oil and NGL segments. '22 represented a positive inflection point for Plains. We executed on our goals and initiatives for the year. We captured meaningful Permian production growth on both our gathering and long haul systems, and our team was able to capture market-based opportunities via our integrated business model, flexible asset base as well as commodity price upside. In summary, fourth quarter and full year adjusted EBITDA attributable to PAA was $659 million and $2.51 billion, respectively, with full year results exceeding our February guidance by $310 million or approximately 14%. As a result, we achieved the low end of our targeted leverage range earlier than expected, which enabled us to announce our multiyear capital allocation and financial framework in November. Consistent with that framework, we subsequently announced a $0.20 per unit or approximately 23% annualized distribution increase in January to be paid later this month, bringing our yield to approximately 8.5% based on current trading levels. Additionally, we completed and/or announced several win-win strategic transactions in both our crude oil and NGL segments, including our Cactus II pipeline, Advantage Pipeline, Empress facility and our Keyera Fort Sask minority JV interest sale, which all further optimize our asset base and streamline our operations. We also achieved record health safety environmental performance by achieving or exceeding our 20% reduction targets in employee recordable injury rate and federally reportable release metrics. While we've made great progress in both of these areas and have achieved top quartile performance, we remain focused on continuous improvement with 0 as our ultimate goal for both of these metrics. Looking to 2023 and as highlighted on Slide 4, we provided adjusted EBITDA attributable PAA guidance in a range of $2.45 billion to $2.55 billion. This reflects year-over-year growth in our crude oil segment, underpinned by continued Permian production and tariff volume growth on our gathering and long-haul systems. Our guidance also factors in a reduction in our NGL segment, primarily driven by lower weighted average frac spreads and C3+ spec product sales volumes as well as the Keyera Fort Sask sale, which is expected to close this quarter. Al will provide additional color on our guidance in this portion of the call. As shown on Slide 5, we anticipate 2023 Permian crude oil production to grow plus or minus 500,000 barrels a day exit-to-exit based on an assumed 2022 exit production level of approximately 5.65 million barrels a day. Our updated forecast assumes an average horizontal oil count rig of -- rig count of 340, consistent with current levels. As part of our routine fundamentals forecasting process, we'll continue to monitor our assumptions regarding natural gas takeaway capacity and commodity prices as the year progresses. Our Permian JV system is well-positioned with more than 4 million long-term dedicated acres and operating leverage. As shown on Slide 6, we expect to capture approximately 350,000 barrels a day of incremental gathering tariff volume for the full year 2023 versus 2022. For our long-haul systems, we're seeing higher utilization year-over-year, particularly on our Cactus I and Cactus II systems. On Cactus I, we have contracted or hedged a substantial portion of our open capacity for 2023 at levels generally consistent with our prior expectations. We also expect to see similar year-over-year throughput from the Permian to Cushing on our basin pipeline. Furthermore, we anticipate additional volume on Wink-to-Webster due to an increase in MVCs. In our NGL segment, we continue to focus on optimizing the business as well as improving the predictability of our earnings. During 2022, we completed a transaction to obtain full ownership of our Empress facility and announced a $270 million sale of our interest in Keyera Fort Sask at an attractive multiple and on terms that will improve our connectivity to the Plains Fort Sask complex. Additionally, we're advancing capital-efficient debottlenecking and expansion projects around our Fort Saskatchewan facility and we hope to be able to share additional detail with you over the coming quarters. With that, I'll turn the call over to Al.

Thanks, Willie. We reported fourth quarter adjusted EBITDA of $659 million, which includes crude oil segment benefits of Canadian market-based opportunities and increased volumes across our systems, primarily within the Permian and along with NGL segment benefits from stronger seasonal sales. For the full year, we reported adjusted EBITDA of $2.51 billion, which was $310 million above our initial February guidance. Full year outperformance was primarily driven by market-based opportunities captured by our assets throughout the year, higher commodity price benefits and increased tariff volumes, primarily in the Permian systems. Slide 17 through 19 in today's appendix contains [ walks ], which provide more detail on our fourth quarter and full year performance. A summary of 2023 guidance as well as key guidance assumptions are located on Slides 7 and 8. Looking at 2023 compared to 2022 and as illustrated by the EBITDA walk on Slide 7, we expect adjusted EBITDA of $2.45 billion to $2.55 billion, with year-over-year growth in our crude oil segment and a reduction in the NGL segment. Growth in our crude oil segment is primarily driven by anticipated tariff volume increases in our Permian gathering and long-haul businesses, due in part to our increased ownership in Cactus II, which is now consolidated into PAA's financials with volumes reported on a consolidated basis and earnings on a proportional basis. This is partially offset by an assumption of fewer market-based opportunities as well as lower assumed oil prices in 2023 for our pipeline loss allowance barrels. We expect lower year-on-year NGL adjusted EBITDA as a result of lower weighted average frac spreads and C3+ spec product sales volumes due to a planned third-party facility turnaround as well as our sale of the KFS interest. I would note that our C3+ spec product sales volumes are approximately 80% hedged for the year. Regarding capital allocation, as illustrated on Slide 9, we remain committed to, one, significant returns of capital; 2, continued capital discipline; and 3, maintaining financial flexibility. For 2023, we expect to generate $2.3 billion in cash flow from operations, which assumes approximately $200 million of working capital outflow and excludes approximately $225 million of anticipated insurance proceeds related to the settlement of a Line 901 class action lawsuit, which we now expect to collect in 2024. Furthermore, we expect $1.6 billion of free cash flow, inclusive of $270 million of asset sales. Intended uses of cash flow are as follows: one, allocate approximately $1 billion to common and preferred distributions inclusive of the respective increases; 2, self-fund $325 million and $195 million of approved investment and maintenance capital net to PAA, which includes the POP JV Well Connect and intrabasin debottlenecking capital to support future growth across our Delaware system. I would note that this does not include amounts related to potential Fort Sask debottlenecks and expansion; and three, retire $1.1 billion of senior notes through a combination of cash flow, asset sales, cash on hand and available capacity on our credit facilities, bringing expected year-end leverage to approximately 3.5x. As of today, we have repaid $400 million of the $1.1 billion target. Additional detail on our capital program and the balance sheet are included on Slides 10 and 11. Before I turn the call back to Willie, I wanted to provide a few details on a few housekeeping items. In regards to our Series A preferred equity security, the owners exercised their onetime option to reprice the security at a fixed rate of 9.375% which will increase annual payments by approximately $26 million. This is in addition to the Series B preferred equity security shifting to a floating rate in November 2022, increasing expected annual payments by approximately $20 million. As a result of the Series A election, we have the right to redeem that security at 110% of par, which is the par is $26.25 per unit. We will continue to evaluate our longer-term capital structure. But near-term, we intend to maintain our financial flexibility and do not foresee any changes with respect to the preferred securities at this time. Second, during the quarter, we purchased an additional 5% interest in the Cactus II pipeline, which resulted in a consolidation of the entity and a noncash gain on investments in unconsolidated entities of $370 million. Furthermore, 2022 results also include a $330 million noncash impairment related to our California assets. With that, I'll turn the call back over to Willie.

Thanks, Al. Today's results reflect a critical inflection point for the business and a very strong year of performance and execution. I'd like to acknowledge and thank our Plains team members for their dedication and progress in all areas. We continue to believe that the world needs North American energy supply long-term and that our business will perform well in the current and longer-term environment. As such and as illustrated on Slide 12, Plains is well-positioned to improve returns of capital to unit-holders through a capital allocation framework that targets multiyear distribution growth and 8.5% current yield, significant free cash flow generation and balance sheet flexibility built on the strength of our strategically located crude and NGL footprint across North America. We appreciate your continued interest and support, and we look forward to providing further updates on our earnings conference in May. A summary of our key takeaways from today's call and our goals for '23 are provided on Slides 13 and 14. With that, I will turn the call over to Blake to lead us through Q&A.

Thanks, Willie. As we enter the Q&A session, please limit yourself to one question and one follow-up. For those with additional questions, please feel free to return to the queue. This will allow us to address questions from as many participants as practical and are available time this afternoon. Additionally, the IR team will be available throughout the week to address any additional questions you may have. Andrew, we're now ready to open the call for questions.

[Operator Instructions] And our first question comes from the line of Michael Blum with Wells Fargo.

Wonder if I could just start just one item, I guess, relates to the quarter. Can you quantify if you benefited from the fact that Keystone was down in December? And then I understand it's running at reduced pressures today. So does that benefit you at all in 2023?

Jeremy?

Michael, Hi, this is Jeremy Goebel. It happened in December. So it wasn't really impacting the trade month and in December. It was more impactful to forward periods. The impact was modest, but you'll see some from our Canadian group and some throughput impacts at our [indiscernible] facility. But by and large, that's incorporated into our guidance. It didn't really impact 2022 as much as it will be the first quarter of 2023.

Okay. Great. And then I just wanted to ask about the capital budget. Maybe just -- are there any major projects to flag in that number? And then it looks like maintenance is down year-over-year so maybe you can talk to that as well.

Yes, Michael. These are pretty consistent with kind of previous levels with a slight step-up in the expansion capital piece. Chris Chandler, would you cover the key ones?

Sure, Michael. It's Chris Chandler. We're wrapping up the link to Lester project this year and that's a little higher year-on-year. We do have some additional well connects that are driving higher costs based on volume assumptions and producer forecasts. We are funding some incremental Permian debottlenecking costs, primarily for station work and that's driven by supporting, of course, flow assurance, reliability and flexibility. There aren't any major projects included. And as Al mentioned, we're not currently including any costs related to the Fort Sask debottleneck projects.

Our next question comes from the line of Brian Reynolds with UBS.

Maybe to start off on just the Permian growth expectations. It seems like there was a slight shift in cadence lower for -- to 500,000 barrels per day from prior expectations. But it also seems like Plains is capturing the larger share of the gathering in long-haul volumes compared to prior year. So curious if you could just discuss the drivers around, one, the Permian growth guidance and then second, Plains assumptions around market share and margin opportunities into '23?

This is Jeremy Goebel. First, on the production forecast. Last February, we guided roughly approximately 600,000 barrels a day of growth in '22 and '23. You're going to exit '22 at roughly 5.7 million barrels a day. Exit '23, at roughly 6.1 million to 6.2 million barrels a day. That puts you in a range of on target with where we were last year. So we think the cadence is consistent. The 340-ish rigs that are working today is roughly 75 more than we're working in the prior period contributing to growth today. So we look at that plus a roughly 10% increase in the well connects across our system throughout the year gives us pretty much good confidence on a top-down level as well as the bottoms up filled from producer forecast in the 500,000 barrels a day outlook that we have. Some of the offset is to potentially slowing down is what we can foresee is incremental basin decline just from higher production. You've got a rebuilding of a modest level of DUCs across the system because you had some depletion last year. And then the continued conversion of development programs to maximizing the value of the inventory in the units as opposed to unbounded wells. So that combination gives us a view as to -- if you just ran out based on historical books and every well gets completed, you get higher than 500,000 barrels a day growth. So that's kind of some of the factors we considered in coming out with our view of production for this year. As for the capture rate, we look at our individual producer contributions and we look at the bottoms-up forecast as well as a top-down view. That gives us confidence as to where our capture rate would look. I'd also highlight that roughly 50,000 barrels a day is coming from another gathering system moving on to our long-haul pipe. So it's really an intra-basin capture. So some of that's really being gathered by a third party. We capture it intra-basin movement to our long-haul type. So the 350 number you could really look at that as 300 relative to 500 as opposed to 350 relative to 500.

And then quickly just on margin into '23. Is it basically the same as 22? Or should we assume any changes upward or down?

Are you talking about long-haul margins or...

Yes, long-haul Permian crude oil margins.

So the incremental margins for spot capacity are more this year than they were last year, if that's directly answering it. Contract roll-offs and step-ups can change it. But if you're looking at what the marginal capacities were this year versus next year, it's higher this year. And based on the way we were able to contract that space for this year, we've locked in largely all of our spot capacity to the Gulf Coast. And then going forward, we sold additional capacity in '24 and '25 at successively higher levels. These would be levels consistent with what we talked about before.

Great. Appreciate it. And then just for a quick follow-up. On the NGL segment, it just seems like the fee-for-service component seems to be trending higher. I'm just curious if you can talk about -- is that primarily driven from the asset sale and looking forward, are there more opportunities to term out this side of the business?

I would think some of that would come from just the decline in commodity prices, so that contribution being lower. But as Chris talked about, we're advancing opportunities for potential adding fee-for-service. So I think you may see that longer-term trend that way, but this year specifically is an erosion of some of the commodity-based margins, which is based into the forecast.

And our next question comes from the line of Keith Stanley with Wolfe Research.

So first, just on the guidance for the year. So one of the drivers in the waterfall is fewer market-based opportunities 2023 versus 2022. Can you talk just high level on what you're assuming in the '23 guidance for marketing and logistics opportunities? Are you picking some in? Are you staying pretty conservative? And if you are baking in some opportunities where they may be beyond the Keystone outage that you already referenced?

Yes, Keith, this is Willie. On the guidance for kind of market-based, what we've done is, as you know, we've got a pretty complex system that's got a lot of flexibility to be able to capture volumes when the arbitrage opportunities are there. We're not going to get into a detailed assessment of where things are. What I would tell you is we put what we thought was probable that we could capture. And then there's a lot of variations, I think that was mentioned in the prepared scripts, we went with the range, and it was actually as a response to some of our conversations with analysts on not trying to be too precise on that. So it's a long-winded answer of telling we've got some baked in that we think we're going to capture and there's some upsides and downsides. And you know the typical buckets that we capture these in, whether it be distressed crude into storage. We've got some time spreads. Sometimes we're able to capture if the market is conducive from that. And then we've got some unhedged portions of our PLA as well as our frac spreads, not a lot. We've got the predominant amount of that hedged that would give us some upside if oil prices are higher or lower.

This is Harry. Also differentials -- quality differentials can impact that.

Got it. Second question is just on the NGL guidance for the year, so down $100 million year-over-year. Last quarter, you pointed to that $100 million impact, but you beat pretty good in the fourth quarter. So '22 actually came in higher. You also had the Keyera sale. So is it fair to say the NGL business is improving in some ways. It just feels like the outlook has actually gotten a little bit better than your last update.

Yes, I think it's a fair assessment. And remember, we expect to close Keyera Fort Sask later this quarter. So you'll see that -- that number wasn't included in anything past hands. It will be prospective. But I think it's a fair assessment.

And our next question comes from the line of [ Mark Salcedo ] with Barclays.

Maybe just a follow-up on the Permian production growth outlook. Is there any sensitivity you could provide from the Plains' perspective to that 500,000 barrel a day number in terms of '23 EBITDA guidance or any context around the embedded assumptions within your guidance range?

The way we look at it is roughly -- it's different for the gathering the long-haul business, but a simple approach would be 100,000 barrels a day would have roughly $10 million to $15 million of EBITDA impact to net Plains. So if you think about that just on the gathering side and the long-haul will be a function of which market it goes to. And so since we have had a substantial portion, if that barrel wanted to go to Cushing or our shippers on Cactus II decided to ship that at higher rates, it would add additional margins. So that's a rough view on the gathering side and then your view of -- and that's assuming no market-related opportunities is just the gathering fees associated with that.

Great. That's helpful. And then on Slide 9, you referenced net debt reduction in the context of the $600 million of free cash after dividends and you also have the $400 million of cash on the balance sheet as of year-end. Just wondering if there's a particular target you have for net debt repayments this year in the context of the $1.1 billion you have maturing.

Yes, this is Al. The leverage we talked about going down basically 2/10 from 3.7 to 3.5, that's roughly about $600 million is what we're assuming. So it will be partly a reduction using cash to reduce the gross debt, but the net debt we've modeled about $600 million. Again, there's things that can happen throughout the year that will change that, but that's what's embedded in our assumptions at this time.

And our next question comes from the line of John Mackay with Goldman Sachs.

Maybe looking again at the Permian, just thinking about kind of barrels out of the Houston versus Corpus, starting to see the Corpus bound lines start to fill up on a relative basis given export levels. Curious if you can kind of share a view of what you think is going to happen in terms of the need potentially for actually more capacity or expansions on any of the lines going to Corpus and whether or not that could be a '24 or '25 or later conversation?

This is Jeremy Goebel. I'd say what you're seeing is the Corpus line is filling up because international demand is waking up for crude oil. I'd say that Wink-to-Webster step-up is having a larger impact on the market centers at Houston, moving from market centers there to Webster in Midland. And then the fourth quarter of this year, you'll see a step-up in additional movements into the Beaumont from that same market. So you'll see more of an impact there. Corpus is continuing to draw barrels, but there's a lot of spot capacity moving into Corpus today and those margins will move out over time, just as -- to get from the lower levels they are today, they're closer to new build economics. I don't think you're looking at an expansion in the near term. The markets have to move off incentive tariffs closer to where you could build or support additional construction. But Houston and New

And John, you know this, but the markets change in different locations, as Jeremy outlined, you can say, will be the lead or lag, but there are times when we've got access to all those markets. So there's times where Corpus will be attractive and sometimes we end up with a pull on Cushing up to -- on our basin pipeline from Permian to Cushing and we're able to move volumes there. So when I think about it, if market is generally dynamic and we have a system that is able to capitalize on really any of that to move barrels for our customers.

That's helpful. Maybe just on the gathering pickup, the 50 a day that's now going to be flowing on to your long-haul lines, are there more of these opportunities out there? Is this kind of a one-off, maybe anything you can share on, again, any others we could see what that maybe means for rates overall? Anything else would be helpful.

I think some of that is just a preference for producers to shift barrels. We just offer flexibility of our customers to go to specific markets. As we said earlier on the call, we continue to contract additional space opportunistically when it makes sense. And so we've layered in contracts over time to Corpus to Cushing to other markets, and we'll continue to do that. There are step-ups in our contracts on Cactus II and Wink-to-Webster this year, which can impact that. There's additional movements to Corpus as contracts roll off and we contract new pieces, it just changes the dynamics in the system. So we're not going to disclose who shippers are, how they move barrels, but that's something you continue to see. We have an attractive gathering system and people like to deal with one operator from wellhead to market, and we'll continue to capture opportunities that work for us and the customers.

And our next question comes from the line of Jeremy Tonet with JPMorgan.

Just want to come back to the assumptions in the Permian here, the $500 million assume year-over-year as well as kind of on Slide 6, the market share of those gains across gathering intra-basin long-haul. Is there any high-level thoughts you're able to provide as far as sensitivities if we want to kind of overlay our own assumptions on those, how that might impact EBITDA in the year?

I think Jeremy Goebel's earlier comment on the rough sensitivity is probably about as close as we can probably get. I mean that was at roughly $10 million to $15 million in the gathering system, if you -- for every 100,000 barrels a day of growth in the Permian. It's hard to put a detailed number more on that because it really depends on what system it's going on. And as you might understand, the -- sometimes if it's an MVC that's empty and the volume wants to go differently, it will be a benefit. So there's a lot of variables that play into, but I'd probably just go with that $10 million to $15 million per 100,000.

Yes. And Jeremy, just to recognize on the long-haul side, we feel very confident in the volumes that we put in here through the additional hedging and contracting of additional capacity. So I'd say that the long-haul system, look, some of this is flexing based on market demand, but we have a very good view of that. And I don't know that with 100,000 barrels a day of basin growth, you're going to see a lot of movement in what we think we'll capture on the long-haul side this year.

One thing that's notably different this year than past years that you may have picked up is we're coming into this year with substantial amount of our long-haul volumes in the Permian and 80% of our frac spreads kind of locked in. So that gives us a little more confidence as we think about 2023, but that's different than what we've done in the past.

Got it. That's helpful. And Al, this kind of a question, maybe for Matt a little bit here. Just as far as what's the right leverage level for the business going forward? We've seen larger peers move to a lower leverage level. So just curious, I guess, how you think -- what do you think is the right leverage for this business longer term?

Good question. Yes. We've seen that same disclosure. Our current leverage targets we established in 2019, we lowered them then pandemic hit. We've now got into them and have now migrated below. And what we're communicating versus establishing a new target is that we intend to migrate further below the low end and kind of operate there. And I think what our view is we'll assess that. We do believe that probably broader energy industry leverage probably needs to be lower than it's been historically. But we'll take a little time and assess that in the future. But for now just kind of look at it and pass along the math that we just intend to kind of operate below the low end.

Yes. I think having additional financial flexibility is a good thing these days.

And our next question comes from the line of Neel Mitra with Bank of America.

First question, the frac spread, I know you've talked about that improving for 2030 on the outlook. Could you maybe talk about what the moving parts were from the last outlook to this outlook since you're 80% hedged when you look at the NGL basket versus AECO?

Sure. Neel, this is Jeremy. Just think of it as in the fourth quarter in November, natural gas prices were substantially higher than they are now. We were not hedging through that period in the fourth quarter. And as natural gas price, Henry Hub and subsequently AECO declined, we were able to hedge into -- so propane and butane and condensate prices didn't have to move materially for -- relative to the spread of buying AECO and selling NGLs. And so we took advantage of that move and hedge additional volume. That gave us a stronger outlook for pricing, but that's all priced into the forecast we've given today. So we have an outlook that's consistent with the hedging we have and then the forward market that's there today.

Got it. That makes sense. Second question, Jeremy, probably for you also. We had a lot of crude kind of flooding the Houston area with the SPR release last year. Now that that's gone, it seemed to have affected a lot of exports and improved outlook. Is the same push there for exports and subsequently move it to Corpus versus Houston this year?

I would say those are somewhat independent because last year, light crude exports increased by just a bit more than light crude production growth from the light basins, including the Permian. The SPR was 70% heavy and that more impacted imports from Canada and imports from other locations. So the real need for replacement from those refineries, roughly the average of 450,000 barrels a day of SPR releases over the calendar year is going to be on the heavy side. They're going to need to find replacements for that distillate yield. So it's really not a replacement in yield there. We look at that more of an impact on the heavy markets than it is to the light markets. So we still think the best logistics and the best quality will draw the additional barrels for export. So we kind of look at those as independent because the domestic refiners increased last year exports of product and exports of lights. And so we just look at those in.

Got it. And if I could just ask one clarification. So when you talked about hedging the spread, let's say, between the Permian and Corpus Christi market or Permian MEH, is that for your equity volumes that you're doing that now?

It's also the price for it's an FOB sales from a Midland Basin or it's a price for contracts based on pipelines. So if you think about it on a prompt basis, in the given month, the spread to the water could be $0.50 from MEH. It's a little -- it's different than Houston and Corpus, but just from a Corpus standpoint, it could be in excess of $0.50 on a longer-term basis, if you're looking at the MEH market, it could be easily in the $0.30 to $0.40. So if you're looking at that as the market, the relationship has changed a bit since Wink-to-Webster started and the less liquidity at MEH. But it's still a proxy, but there's a premium for Corpus for sure.

I'm not sure if your question was the margin -- we capture the margin on barrels that we buy and move. Was that your question?

That was it. But Jeremy's color was also very helpful.

Our next question comes from the line of Neal Dingmann with Truist.

Kind of been asked, I just want to ask maybe a different way. I'm trying to get a sense of if you see any difference in strategy now when I look at sort of simply growth versus distribution? And then maybe part of that, how you think about the sort of minimum distribution growth coverage that you're comfortable with on either side of that if those things have changed?

Yes, Neal, this is Willie. The strategy hasn't changed. Capital discipline and discipline in everything we do continues. Our goal is to continue to generate lots of free cash flow, continue to pay debt down. We've got the preps that we want to deal with at some point in time when it's optimal. And as we go forward, we want to have that extra financial flexibility. We've got some very exciting opportunities of potential debottlenecks on some of our NGL assets. So if you do see us take on some more projects, they're going to be strong return. And we're going to be very, very measured as we go forward, whether it be capital investments or even bolt-on acquisitions or anything else. So that's why we think about it.

Very good. And then one last one. Just you mentioned -- I know previously you had a little bit of downtime or offline in the Canadian facilities. I'm just wondering any update on how that's trending now?

Yes. This is Chris Chandler. I can take that. We did have a turnaround at our Empress facility late in 2022. We completed that successfully, and we're back at full strength across our Canadian assets, both on the Empress Extraction plants and at the fractionation facilities at both Fort Sask and in the East at Sarnia.

Our next question comes from the line of Sunil Sibal with Seaport Global.

My first question was on the CapEx. So it seems like you've guided to CapEx a little bit higher than what you did last year. I was just curious, since there are no specific big item projects, is this the kind of run rate we can assume going forward, especially if the Permian growth going forward remains in the same -- similar kind of range?

Yes, Sunil, if I understood your question, you're asking kind of trajectory of growth in run rate. Is that what you're asking?

Correct.

Yes. So we do have operating leverage. So we've got capacity in the Permian gathering intra-basin and long-haul multiple markets. So there will always be some opportunities there. And then as I shared earlier on the NGL assets, there's definitely some opportunities there as well.

Okay. And then one question for Al. So when I look at the Slide 8, where you lay out financial assumptions for 2023, could you walk us from cash flow from operations of $2.3 billion to your free cash flow of $1.6 billion?

Yes. Well, from cash flow, the $2.3 billion. Yes, it would be -- we're assuming $270 million of asset sales, which would increase it, the CapEx, both the $325 million and the maintenance capital would reduce it. And I think in our calculation, we have distributions to non-controlling interest embedded in there as well. So it's the same formula as we use all the pieces and parts are -- if you look at our definition of free cash flow, you'll be able to take to some of these parts and get there. Does it make sense?

Yes, got it. And then one follow-up from the previous question on leverage. I think you also guided to a mid-BBB kind of credit ratings. So does your previous range of 3.75% to 4.25% on the leverage metrics helps you get there considering the overall environment that we are in and what we are hearing from other midstream producers also, you need to kind of lower that 3.75% to 4.5% to get to mid-BBB?

I would say probably not, other than we'd probably have to operate in the lower band of it and operate in the lower band of it on kind of a through-the-cycle kind of basis. But again, as we've communicated on this call and the call in November, we intend to operate kind of at the lower band or below. And we've had the same dialogue and communication with the rating agencies as well. We believe the path that we plan to manage our financial capital structure at is commensurate with mid-BBB ratings and it will just take time in us executing against what we've laid out to get there. So we're pleased with the progress so far. We did get one positive outlook recently and we're hopeful, again, we've just got to continue to execute and deliver like we think we will.

I will now turn the call back over to CEO, Willie Chiang for any closing remarks.

Thanks. I did want to add one thing. When we talked about things that we look at with intense financial discipline, we talked about capital investments. We looked at some -- talked about some of the NGL expansions. The one other thing on there, of course, is acquisitions. And you would expect us to take the same level of financial discipline as we think about acquisitions. When you think about our system and what we're ultimately playing for, we've got great assets. We're probably able to capture more synergies out of some of these, but we're going to be very disciplined and think about the valuation on these when they do come up. But again, anything you'll see us do is going to go through that threshold of financial discipline. Thanks, everyone, for your attention, joining us this afternoon, and we'll look forward to keeping you updated as we go forward through the year. Thank you very much.