Good day. Thank you for standing by. Welcome to the PAA and PAGP Q4 2022 earnings conference call. At this time, all participants are in a listen-only mode. After the speaker presentation, there will be a question-and-answer session. To ask a question during the session, you will need to press star one one on your telephone. You will hear an automated message advising that your hand has been raised. To withdraw your question, please press star one one again. 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 Q4 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 the 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 two. An overview of today's call is provided on slide three. 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, thank you for joining us. Today, we announce strong Q4 and full-year results, exceeding our expectations in both our crude oil and NGL segments. 2022 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, 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, Q4 and full-year Adjusted EBITDA attributable 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 multi-year 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. 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 Saskatchewan 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 zero as our ultimate goal for both of these metrics. Looking to 2023, as highlighted on slide four, we provided Adjusted EBITDA attributable PAA guidance in a range of $2.45 billion-$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 Saskatchewan 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 five, we anticipate 2023 Permian crude oil production to grow ±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 six, 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 own 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 Saskatchewan 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 Q4 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. 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. Slides 17 through 19 in today's appendix contains walks which provide more detail on the Q4 and full year performance. A summary of 2023 guidance as well as key guidance assumptions are located on slides seven and eight.
Looking at 2023 compared to 2022. As illustrated by the EBITDA walk on slide seven, we expect Adjusted EBITDA of $2.45 billion-$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 segment's 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 to 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 nine, we remain committed to, one, significant returns of capital, two, continued capital discipline, and three, 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 outflows 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. two, self-fund $325 million and $195 million of approved investment and maintenance capital net to PAA, which includes the POP JV WellConnect 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 bottlenecks and expansions. 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 detail on a few 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 is $26.25 per unit. We will continue to evaluate our longer-term capital structure, 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 non-cash gain on investments in unconsolidated entities of $370 million. 2022 results also include a $330 million non-cash 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 multi-year distribution growth, an 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 2023 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 in our 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.
Certainly. As a reminder, to ask a question, please press star one one on your telephone and wait for your name to be announced. To withdraw your question, please press star one one again. Please stand by while we compile the Q&A roster. Our first question comes from the line of Michael Blum with Wells Fargo.
Hi, Michael.
Hey, thanks. Good afternoon, everyone. I 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? I understand it's running at reduced pressures today. Does that benefit you at all in 2023?
Jeremy?
Michael, hi, this is Jeremy Goebel. It happened in December. It wasn't really impacting the trade month ending December. It was more impactful to the forward periods. The impact was modest. You'll see some from our Canadian group and some throughput impacts at our Patoka facility. By and large, that's incorporated into our guidance. It didn't really impact 2022 as much as it will be the Q1 of 2023.
Okay, great. just wanted to ask about the capital budget. maybe just are there any major projects to flag in that number? it looks like maintenance is down year-over-year, so maybe can you talk to that as well? Thank you.
Yeah, 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 Wink to Webster project this year, and that's a little higher year-over-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. As Al mentioned, we're not currently including any costs related to the Fort Sask debottleneck projects.
Great. Thank you.
Thanks, Michael.
Thank you. Our next question comes from the line of Brian Reynolds with UBS.
Hi. Good morning, everyone. Maybe to start off on just the Permian growth expectations, it seems like there was a slight shift in cadence, lower for the 500,000 barrels per day from prior expectations. It also seems like Plains, you know, is capturing the larger share of the gathering and long-haul volumes compared to prior years. Curious if you could just discuss the drivers around, one, the Permian growth guidance, and then two, Plains' assumptions around market share and margin opportunities into 2023. Thanks.
Hello. This is Jeremy Goebel. First on the production forecast. Last February, we guided to roughly approximately 600,000 barrels a day of growth in 2022 and 2023. You're gonna exit 2022 at roughly 5.7 million barrels a day, exit 2023 at roughly 6.1 million-6.2 million barrels a day. That puts you in a range of on target with where we were last year. We think the cadence is consistent. The 340-ish rigs that are working today is roughly 75 more than were working in the prior period contributing to growth today.
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 a bottoms-up build from a producer forecast in the 500,000 barrels a day outlook that we have. Some of the offset as 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. Then, the continued conversion of development programs to maximizing the value of the inventory in the units as opposed to unbounded wells.
That combination gives us a view as to. If you just ran out based on historical looks and every well gets completed, you get higher than 500,000 barrels a day of growth. 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 a bottoms-up forecast as well as a top-down view. That gives us confidence as to where this, 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 intrabasin capture. Some of that's really being gathered by a third party. We capture it, intrabasin movement to our long-haul pipe. The 350 number, you could really look at that as 300 relative to 500 as opposed to 350 relative to 500.
Then quickly, just on margin into 2023, is it basically the same as 2022, or should we assume any changes up or down?
Are you talking about long-haul margins?
Yeah, for long-haul Permian crude oil margins.
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. Based on the way we've been able to contract that space for this year, we've locked in largely all of our spot capacity to the Gulf Coast. Then, going forward, we've sold additional capacity in 2024 and 2025 at successively higher levels.
Great. Thanks.
Brian, these would be-
Go ahead. Sorry.
...as levels consistent with what we talked about before.
Great, appreciate it. 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? You know, looking forward, are there more opportunities to term out this side of the business? Thanks.
I would think some of that would come from just the decline in commodity prices, so that contribution being lower. As Chris talked about, we're advancing opportunities for potential adding fee for service. 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 baked into the forecast.
Great. I'll leave it there. Thanks.
Thanks, Brian.
Thank you. Our next question comes from the line of Keith Stanley with Wolfe Research.
Hi, Keith.
Hi. Thank you. First, just on the guidance for the year. 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 2023 guidance for marketing and logistics opportunities? Are you baking some in? Are you staying pretty conservative? If you are baking in some opportunities, where they may be beyond the Keystone outage that you already referenced?
Yeah, 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 gonna get into 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. It's a long-winded answer of telling.
We've got some baked in, that we think we're gonna capture, and there's some upsides and downsides. 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. 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.
In this area, also differentials, quality differentials can impact that.
Got it. Thank you. Second question is just on the NGL guidance for the year. Down $100 million year-over-year. Last quarter, you pointed to that $100 million impact, but you beat pretty good in the Q4 , so 2022 actually came in higher. You also had the Keyera sale. Is it fair to say the NGL business is improving in some ways? It just feels like the outlook's actually gotten a little bit better than your last update.
Yeah, I think it's a fair assessment. Remember, we expect to close Keyera Fort Sask , later this quarter. You'll see that. Yeah, that number wasn't included in anything past tense. It'll be, prospective. I think it's a fair assessment.
Thank you.
Thank you. Our next question comes from the line of Marc Solecitto with Barclays.
Hi. Good afternoon. Maybe just to 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 2023 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. A simple approach would be 100,000 barrels a day would have roughly $10 million-$15 million of EBITDA impact net to Plains. If you think about that just on the gathering side and the long haul will be a function of which market it goes to. Since we've hedged 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 margin. That's a rough view on the gathering side and then your view of. That's assuming no market related opportunities, it's just the gathering fees associated with that.
Great. That's helpful. On slide nine, you referenced net debt reduction in the context of the $600 million of free cash after dividends. 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.
Yeah, this is Al. You know, the leverage we talked about going down basically 0.2 from 3.7- 3.5, that's roughly about $600 million is what we're assuming. It'll 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.
Got it. Appreciate the time.
Thanks, Mark.
Thank you. Our next question comes from the line of John Mackay with Goldman Sachs.
Hey, everyone. Thank you for the time. Appreciate it. Maybe, looking again at the Permian, just thinking about, kind of barrels headed to Houston versus Corpus, you know, 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 gonna 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 2024 or 2025 or later conversation.
Hi, this is Jeremy Goebel. I'd say what you're seeing is the Corpus lines filling up because international demand is waking up for crude oil. I'd say the Wink Webster step up is having a larger impact on the market centers at Houston, moving from market centers there to Webster and Midland. The Q4 of this year, you'll see a step up and additional movements into the Beaumont from that same market. You'll see more of an impact there. Corpus is continuing to draw barrels, 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 to 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. Houston and Nederland both have strong markets and will pull barrels, and Cushing will continue to pull barrels based on the excellent crack spreads you're seeing in the market today. We see the Permian needs all of the above to clear. At this point, the most efficient dock from a quality and a logistics standpoint is Corpus, and it yields a premium to the other markets. If it's an export barrel, it's gonna look to price into that market, but there's low overflow capacity into the others, and you'll see pull into those other markets. For purely logistics and quality reasons and pricing, you'll see Corpus pull that export barrel.
John, you know this, but the markets change in different locations, as Jeremy outlined. You can say we'll be the lead or lag, but there are times when, you know, we've got access to all those markets. There's times where Corpus will be attractive, and sometimes we end up with a pull on Cushing up to, you know, on our Basin Pipeline from Permian up to Cushing, and we're able to move volumes there. You know, when I think about it, 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. Thanks for that. Maybe just on the gathering pickup, the 50 a day that's now gonna be flowing onto your long-haul lines. Stewart, are there more of these opportunities out there? Is this kind of a one-off? Maybe anything you can share on, you know, 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 ship barrels. We just offer flexibility to 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. 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 in Wink 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. We're not gonna disclose who shippers are or 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.
All right. Appreciate the time. Thank you.
Thank you. Our next question comes from the line of Jeremy Tonet with JP Morgan.
Hi, Jeremy.
Hi, good afternoon.
Good afternoon.
Just wanted to come back to the assumptions in the Permian here, the 500 assumed year-over-year, as well as kind of on Slide six, the market share of those gains across gathering, interbasin, long haul. Is there any high-level thought 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?
Well, 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-$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. As you might understand the, you know, sometimes if it's an MBC 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-$15 per 100,000.
Yeah. Jeremy, just 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. I'd say that the long haul system, look, some of this is flex and based on market demand, but we have a very good view of that. I don't know that within 100,000 barrels a day of basin growth, we're gonna see a lot of movement in what we think we'll capture on the long haul side this year.
Yeah, 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. That gives us a little more confidence as we think about 2023. That's different than what we've done in the past.
Got it. That's helpful. Thanks. Al, this is 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. Just curious, I guess, how you think, you know, what do you think is the right leverage for this business longer term?
No, good question. Yeah, 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. 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. 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. We'll take a little time and assess that in the future. For now, just kind of look at it and path along the math that we just intend to kind of operate below the low end.
Yeah, I think having additional financial flexibility is a good thing these days.
Got it. I'll leave it there. Thank you.
Thanks, Goebel.
Jeremy.
Jeremy, yeah.
Our next question comes from the line of Neel Mitra with Bank of America.
Hi, good afternoon. First question, the frac spread. I know you've talked about that improving, you know, for 23 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 the, in the Q4 in November, natural gas prices were substantially higher than they are now. We were not hedging through that period in the Q4 . As natural gas price, Henry Hub and subsequently AECO declined, we were able to hedge into. Propane and butane and condensate prices didn't have to move materially for relative to the spread of buying AECO and selling NGLs. We took advantage of that move and hedged additional volume. That gave us a stronger outlook for pricing, but that's all priced into the forecast we've given today. 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. Thank you. 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 the outlook. Is the same push there for exports and subsequently movement 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. That more impacted imports from Canada and imports from other locations. 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 gonna be on the heavy side.
They're gonna need to find replacements for that distillate yield. It's really not a replacement in yields there. We look at that more of an impact to the heavy markets than it is to the light markets. We still think the best logistics and the best quality will draw the additional barrels for export. We kind of look at those as independent. The domestic refiners increased last year exports of product and exports of lights. We just look at those independent.
Got it. If I could just ask one clarification. When you talk about hedging the spread, let's say between the Permian and Corpus Christi market or Permian and MEH, is that for your equity volumes that you're doing that, now?
It's also the price for an FOB sale from a Midland Basin, or it's a price for contracts based on pipelines. 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 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-$0.40. If you're looking at that as the marker, the relationship has changed a bit since Wink to Webster started, and there's less liquidity at MEH. It's still a proxy, but there's a premium for Corpus, for sure.
You know, I'm not sure if your question was. We capture the margin on barrels that we buy and move. Was that your question?
That was it. Jeremy's color was also very helpful. Thank you.
Thank you. Our next question comes from the line of Neal Dingmann with Truist.
Afternoon, guys. Thanks for the time. It's kind of been asked, I just wanna ask maybe a different way. I'm trying to get a sense of if you see any difference when strategy now 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. Is on either side of that, if those things have changed?
Yeah, 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. You know, we've got the pref that we wanna deal with at some point in time when it's optimal. As we go forward, we wanna have that extra financial flexibility. We've got some very exciting opportunities of potential debottlenecks on some of our NGL assets. If you do see us take on some more projects, they're gonna be strong return, and we're gonna be very, very measured as we go forward, whether it be capital investments or even bolt-on acquisitions or anything else. That's the way we think about it.
Very good. One last one. Just you'd mentioned I know previously you had a little bit of downtime or offline in the Canadian facilities. I'm just wondering any update or how that's trending now. Thank you.
Yeah. 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.
Thank you. Our next question comes from the line of Sunil Sibal with Seaport Global.
Hi, good afternoon, everybody. My first question was on the CapEx. Seems like, you know, you've guided the CapEx a little bit higher than what you did last year. I was just curious, you know, since there are no specific big item projects, is this the kind of run rate we can assume going forward, especially if the, you know, Permian growth going forward remains in the same similar kind of range?
Yeah. Sunil, if I understood your question, you're asking kind of trajectory of growth and run rate. Is that what you're asking?
Right.
Yeah. We do have operating leverage. We've got capacity in the Permian, gathering intrabasin long-haul multiple markets. There'll always be some opportunities there. As I shared earlier on the NGL assets, there's definitely some opportunities there as well.
Okay. One question for Al. When I look at slide eight, 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?
Yeah. Well, from cash flow, the two three, yeah, 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. I think in our calculation, we have distributions to non-controlling interests embedded in there as well. It's the same formula as we use. All the pieces and parts are. If you look at our definition of, you know, free cash flow, you'll be able to take the sum of these parts and get there. Does that make sense?
Yeah, got it. One follow-up from the previous question on leverage. I think you've also guided to a mid triple-B kind of, you know, credit ratings. Does your previous range of 3.75-4.25 on the leverage metrics help, you get there, considering the overall environment that we are in and, you know, what we are hearing from other midstream producers also, you need to kind of lower that number 3.75-4.25 to get to mid triple-B?
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. 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. We've had the same dialogue and communication with the rating agencies as well. We believe the path that we plan to manage, you know, our financial capital structure at is commensurate with mid triple-B ratings, and it'll just take time and us executing against what we've laid out to get there. We're pleased with the progress so far. We did get one positive outlook recently, and we're hopeful. Again, we just gotta continue to execute and deliver like we think we will.
Thanks for that.
Thank you. I will now turn the call back over to CEO Willie Chiang for any closing remarks.
Thanks. Hey, I did wanna add one thing. When we talked about things that we look at with intense financial discipline, we talked about capital investments, we 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 disciplines as we think about acquisitions. You know, when you think about our system and what we're ultimately planning for, we've got great assets.
We're probably able to capture more synergies out of some of these, but we're gonna be very disciplined and think about the valuation on these when they do come up. Again, anything you'll see us do is gonna be 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.
Ladies and gentlemen, this concludes today's conference call. Thank you for participating, and you may now disconnect.