Plains Gp Holdings LP Q4 FY2022 Earnings Call

Good day, and thank you for standing by. Welcome to the PAA and PAGP Fourth Quarter 2022 Earnings Conference Call. Please be advised that today's conference is being recorded.

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 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.

Thanks, Willie. We reported fourth quarter adjusted EBITDA of $659 million, which includes crude oil segment benefits from 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 details that provide more context 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 significant returns of capital, continued capital discipline, and 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: allocate approximately $1 billion to common and preferred distributions inclusive of the respective increases; 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 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 housekeeping items. In regards to our Series A preferred equity security, the owners exercised their one-time 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 at $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.

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.

And our first question comes from Michael Blum with Wells Fargo.

I wonder if I could just start with one item, I guess, relating 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 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 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. I wanted to ask about the capital budget. Are there any major projects to highlight in that number? Also, it seems like maintenance is down year-over-year, so could you speak 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 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, regarding the production forecast. Last February, we indicated an expected growth of around 600,000 barrels a day for '22 and '23. You will finish '22 at approximately 5.7 million barrels a day and '23 at about 6.1 million to 6.2 million barrels a day. This aligns with our expectations from last year, indicating a consistent pace. The 340 or so rigs currently operational is about 75 more than in the previous period, contributing to today’s growth. Additionally, we anticipate a roughly 10% increase in well connections across our system throughout the year, which provides us with confidence both from a top-down perspective and from bottom-up input from producer forecasts supporting our 500,000 barrels a day outlook. Some of the potential slowdown may come from incremental declines in basins due to higher production levels. We are also seeing a modest rebuilding of DUCs across the system due to previous depletion last year, along with ongoing efforts to optimize our development programs to enhance the value of our inventory instead of just focusing on unbounded wells. Considering all these factors, if we were to use historical data and complete every well, we could see growth exceeding 500,000 barrels a day. These are some of the elements we factored into our production outlook for this year.

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.

Thank you. I appreciate it. For a quick follow-up on the NGL segment, it appears that the fee-for-service component is trending higher. Can you discuss whether this is mainly a result of the asset sale and if there are additional opportunities to expand this part of the business in the future?

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. 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 believe that's a reasonable evaluation. Additionally, we anticipate finalizing the Keyera Fort Sask transaction later this quarter. Therefore, that figure was not reflected in any prior estimates. It will be forward-looking, but I think it's a reasonable evaluation.

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 that it's different for the gathering and long-haul business, but a simple approach would be that 100,000 barrels a day would have an impact of roughly $10 million to $15 million in EBITDA for Plains. If you consider that just for the gathering side, the long-haul part will depend on which market it is directed towards. Given that we have a substantial portion, if those barrels were to go to Cushing or our shippers on Cactus II decided to ship at higher rates, it would create additional margins. This is a general perspective on the gathering side, assuming there are no market-related opportunities, just the gathering fees connected to 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 are 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. The Corpus line is experiencing increased activity due to rising international demand for crude oil. The Wink-to-Webster transition is significantly affecting the market centers at Houston, shifting operations from those centers to Webster in Midland. In the fourth quarter of this year, you can expect to see increased movements into Beaumont from that same market, resulting in a more pronounced impact. While Corpus is actively drawing barrels, there is currently a considerable amount of spot capacity directed towards Corpus, and those margins are expected to normalize over time as they approach new build economics. I don't anticipate any expansion in the immediate future; the market needs to adjust from incentive tariffs to levels that would justify additional construction. However, both Houston and New Zealand are experiencing strong market demand, and Cushing will continue to pull barrels due to favorable frac spreads in the current market. The Permian will require all options to manage demand effectively. Right now, Corpus stands out as the most efficient dock in terms of quality and logistics, providing a premium over other markets. If it's an export barrel, it will likely target prices within that market. There’s limited flow capacity into the other markets, but you will see demand shifting to those areas. From a logistical, quality, and pricing standpoint, Corpus will continue to attract those export opportunities.

The markets vary by location, as Jeremy mentioned, and we can experience both leading and lagging factors. There are instances when we have access to all these markets. At times, Corpus can be appealing, and we may see a draw on Cushing through our basin pipeline from Permian to Cushing, allowing us to transport volumes effectively. Overall, the market is dynamic, and our system is designed to take advantage of these conditions 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 onto 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 for 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 get. That was around $10 million to $15 million in the gathering system for every 100,000 barrels a day of growth in the Permian. It's challenging to provide a more detailed number because it really depends on the system it's associated with. Sometimes, if it's an MVC that's empty and the volume moves differently, it can provide a benefit. There are many variables involved, but I would say it's around $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 a 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. Al, I have a question for Matt regarding the appropriate leverage level for the business moving forward. We've observed that larger competitors have shifted to lower leverage levels. I'm curious to hear your thoughts on what you believe is the right leverage for this business in the long term.

Good question. Yes. We've seen that same disclosure. Our current leverage targets we established in 2019, we lowered them then the 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. In November during the fourth quarter, natural gas prices were significantly higher than they are now. We did not hedge during that period in the fourth quarter. As natural gas prices at Henry Hub and AECO declined, we were able to hedge, allowing propane, butane, and condensate prices to remain relatively stable compared to the spread between buying AECO and selling NGLs. We took advantage of that change and hedged additional volume, which improved our pricing outlook. All of this is included in the forecast we provided today. Our outlook aligns with the hedging we have in place and the current forward market conditions.

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 FOB sales from the Midland Basin or for contracts based on pipelines. If you consider it on a prompt basis, in a given month, the spread to the water could be $0.50 from MEH. It's somewhat different than Houston and Corpus, but from a Corpus perspective, it could be over $0.50 on a longer-term basis. Looking at the MEH market, it could easily range from $0.30 to $0.40. The market relationship has shifted a bit since Wink-to-Webster started and due to the reduced liquidity at MEH. However, it remains a proxy, with a clear premium for Corpus.

I'm not sure if your question was about the margin. We capture the margin on the 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.

I 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.

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 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 across 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.

Yes, from cash flow, the $2.3 billion assumes $270 million from asset sales, which would increase it, while the $325 million in capital expenditures and maintenance capital would decrease it. We also have distributions to non-controlling interest included in our calculation. The same formula applies, and if you refer to our definition of free cash flow, you can analyze these components to understand it better. Does that make sense?

Yes, got it. And then one follow-up from the previous question on leverage. I think you also guided to mid-BBB kind of credit ratings. So does your previous range of 3.75% to 4.25% on the leverage metrics help 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 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.

Thanks. I wanted to add one thing. When we discussed our approach to financial discipline, we focused on capital investments and some of the NGL expansions. Another important aspect is acquisitions, where we will apply the same level of financial discipline. Considering our system and our long-term goals, we have excellent assets and can capture more synergies, but we will remain very disciplined regarding valuation when opportunities arise. Anything we pursue will meet our financial discipline criteria. Thank you all for your attention this afternoon, and we look forward to keeping you updated throughout the year. Thank you very much.

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