Oneok Inc (OKE) — Q4 2022 Earnings Call Transcript

Thanks, Andrew, and good morning, everyone, and thank you for joining us this morning. On today's call is Walter Hulse, our Chief Financial Officer and Executive Vice President, Investor Relations and Corporate Development, and Kevin Burdick, Executive Vice President and Chief Commercial Officer. Also available to answer your questions are Sheridan Swords, Senior Vice President, Natural Gas Liquids and Natural Gas Gathering and Processing, and Chuck Kelley, Senior Vice President, Natural Gas Pipelines. Yesterday, we announced strong fourth quarter and full year '22 performance. We met our 2022 financial guidance expectations despite weather-related events and a significant operational incident. We also achieved our ninth consecutive year of adjusted EBITDA growth in 2022. Through the efforts of our workforce and the resiliency of our assets, we have provided exceptional value for our stakeholders and have positioned ONEOK to continue delivering growth in 2023. I believe the term resiliency is a great description of 2022 and will continue to be a focus of our operations going forward. Our people, assets and earnings continue to prove their resiliency, flexibility and stability. With yesterday's earnings announcement, we also provided 2023 financial and volume guidance expectations. Higher natural gas processing and NGL volumes and strong fee-based earnings are expected to contribute to higher earnings in 2023 as we continue to focus on both growing our core business and innovating for future opportunities. There are key differentiators of ONEOK's business that have proven critical to our past success and offer us confidence in the future. These differentiators provide stability, resiliency and unique opportunities for growth. First, our solid and growing base business, which features strategically positioned assets in some of the most productive U.S. shale basins connected with some of the largest and most well-capitalized producers in the U.S. who provide stable and growing supply to our systems. Our margins in our core businesses are approximately 90% fee-based with minimum direct commodity price exposure because of our proactive hedging strategy; second, our strong balance sheet and investment-grade credit ratings, which provide significant financial flexibility. We've reduced our leverage to below 3.5x, a significant milestone for us. We provided investors with more than 25 years of dividend stability and growth, not cutting our dividend during the COVID challenge years and recently announced a dividend increase. Third, our proven track record of intentional and disciplined growth. We continue to benefit from significant operating leverage across our systems enabling us to continue focusing on lower capital, high-return projects and investments to support producer growth across our operations. Our strong return on invested capital is a source of pride for ONEOK and is a key metric for evaluating our management's team performance annually. Our nearly 15% ROIC in 2022 highlights the scrutiny that we place on investments, the efficiency of our capital and the high quality of our projects earnings, and this disciplined growth also approaches and will continue. Finally, the continued demand of the energy products and services that we provide, which are vital to our national security and the quality of life, in which we believe will play an important role in a transforming energy future. U.S. natural gas and natural gas liquids remain abundant and reliable. The products that we move will continue to provide much needed energy domestically and globally. We enter 2023 from a position of strength driven by a year of solid financial and operational performance. And as you can see, there are many reasons why we are confident and optimistic about ONEOK's future. With that, I'll turn the call over to Walt for a discussion of our financial performance.

Thank you, Pierce. As we detailed in yesterday's press release, we expect continued growth in our businesses in 2023 after achieving our 2022 financial guidance even with some challenging events. ONEOK's fourth quarter and full year 2022 net income totaled $485 million and $1.72 billion, respectively, representing increases of 28% for the fourth quarter and 15% for the full year compared with the same period in 2021. Adjusted EBITDA also increased year-over-year, totaling $967 million in the fourth quarter 2022 and $3.62 billion for the full year. Our strong financial performance was driven by increased producer activity, higher realized commodity prices, higher average fee rates and higher natural gas storage and transportation services. In January, we increased our quarterly dividend to $0.95 per share or $3.82 per share on an annualized basis, marking a return to dividend growth following 3 years of dividend stability. In November 2022, we completed a $750 million senior notes offering due in 2032, generating net proceeds of $742 million, which was primarily used to repay short-term debt. Just yesterday, we redeemed $425 million of 5% senior notes due September 23 with cash on hand. Our year-end net debt-to-EBITDA on an annualized run rate basis was 3.46x, in line with our previously discussed aspirational target of 3.5x or less. As it relates to Medford, we reached an agreement with our insurers in early January to settle all claims related to the incident for total insurance payments of $930 million, which included $100 million that was paid in 2022. We received the remaining $830 million in the first quarter of 2023 and applied approximately $50 million to an outstanding 2022 insurance receivable. We provided a table in our earnings release showing the line-by-line details. The remaining $780 million will be recorded as a gain in our operating income in the first quarter of 2023. As Pierce mentioned, with yesterday's earnings announcement, we provided 2023 financial guidance, including a net income midpoint of $2.41 billion and an EPS midpoint of $5.36 per diluted share. We also provided an adjusted EBITDA midpoint of $4.575 billion. Our guidance includes the net effect of the one-time insurance settlement gain of $780 million and future method related costs, primarily third-party fractionation, which we estimate will total $240 million in 2023. We expect Medford related costs to be significantly lower in 2024 due to our ability to fully utilize the MB-5 fractionator to substantially reduce third-party fractionation costs compared with 2023. By taking the full settlement of $780 million, less the $240 million of expected third-party costs in 2023, you get a total of approximately $540 million related to the settlement that has been assumed in our $4.575 billion adjusted EBITDA guidance midpoint for 2023. Excluding the effect of the settlement and the third-party costs of $540 million, this still amounts to more than $4 billion, double-digit earnings growth which we referenced on our last earnings call. We also expect double-digit earnings growth at the midpoint for both natural gas liquids and natural gas gathering and processing segments driven by higher volume expectations across our operations. Kevin will provide more detail on each of the operating segments in a moment. Our 2023 guidance assumes producer activity associated with WTI crude oil prices in the range of what we are currently seeing in the market. We expect total capital expenditures of $1.38 billion, which includes growth in maintenance capital. This midpoint reflects the investments necessary to keep up with expected increase in producer activity, the completion of MD5 early in the second quarter of 2023 and also more than $300 million related to MD6 this year. Excluding the MD6 expenditures, our total CapEx would have been lower than 2022. Our 2023 CapEx guidance does not include the Saro Connector pipeline or any other projects that have not reached a final investment decision. Our routine growth capital accounts for a higher number of well connects and our higher return projects such as natural gas storage expansions, pump stations and compression expansions to meet customer needs. Finally, as it relates to the 15% alternative minimum tax associated with the Inflation Reduction Act, we expect the AMT to have an impact on our cash taxes beginning with the 2024 tax year. You can find details in our 10-K when it is filed later today. I will now turn the call over to Kevin for a commercial update.

Thank you, Walt. In 2022, we experienced strong full-year natural gas gathering and NGL volumes, despite facing several weather challenges. This led to ongoing growth in our mainly fee-based earnings. The Rocky Mountain region saw particularly robust NGL volumes, which rose by 12% year-over-year due to heightened activities and more chances to recover ethane. Our well connections increased by 24% from 2021, and we noted a significant uptick in activity in the Mid-Continent, driving more well connections and boosting natural gas processing volumes on our system. We anticipate that this activity will continue to benefit us throughout 2023 as volumes increase. Our Natural Gas Pipelines segment outperformed its 2022 financial guidance, attributed to higher earnings from long-term storage services and increased rates due to the renegotiation of contracts. Customers recognize the value of our storage assets, and we are exploring opportunities to expand these services. As we look toward 2023, a key factor in our raised guidance is stable producer activity, which is expected to yield higher natural gas and NGL volumes across our systems, continued momentum in fee-based earnings and rates, and higher anticipated realized commodity prices because of hedges made at elevated levels compared to 2022. At midpoints, our 2023 volume guidance suggests a 7% rise in total NGL volumes and an 11% increase in total natural gas processing volumes versus 2022. We anticipate that strong producer activity will drive volume growth in the natural gas liquids segment, carrying on the momentum from 2022. Additionally, higher average fee rates will positively impact earnings, as contract escalators are realized throughout the year. The NGL market dynamics indicate improving global demand, particularly with China reopening and lower natural gas prices making the U.S. pet chemicals market attractive. In our system, we expect high ethane recovery levels in the Permian Basin for 2023, while the Mid-Continent will be in a partial recovery phase as natural gas prices fluctuate seasonally. We also anticipate ongoing opportunities for incentivizing ethane recovery in the Rocky Mountain region this year. We are on track to complete our 125,000 barrel per day MB-5 fractionator in Mont Belvieu early in the second quarter of 2023 and have recently announced MB-6, expected to be finished in the first quarter of 2025. Looking at the natural gas gathering and processing segment, we expect volume growth again this year in both the Rocky Mountain and Mid-Continent regions, spurred by producer activity and more well connections compared to 2022. In the Rocky Mountain area, we project processed volumes to increase by 11% at the midpoint compared to 2022, averaging nearly 1.5 billion cubic feet per day in 2023. Even with winter weather so far this year, we achieved processed volumes as high as 1.46 billion cubic feet per day in February, setting a new record for this segment. We completed the 200 million cubic feet per day Demicks Lake III processing plant this month, providing additional capacity and operational redundancy for our customers. Activity in the Williston Basin remains strong, particularly as we approach March, with over 40 rigs and 22 completion crews currently operational there, compared to just over 30 rigs and 13 completion crews at this time last year. Producers are dedicated to the region, and we expect more rigs to return as spring approaches. At our guidance midpoint, we aim to connect 500 wells in the region this year, marking nearly a 40% increase from 2022. We've already connected nearly 90 wells through February, maintaining over 20 rigs on our dedicated acreage. There's also a significant inventory of around 500 drilled but uncompleted wells basin-wide, with approximately half on our acreage. It's important to note that in the Bakken region, producer economics are influenced by crude oil, and our customers are among the largest and most well-capitalized in the nation. Consequently, recent fluctuations in commodity prices, especially lower natural gas prices, have not affected producer activity on our acreage. We expect gas-to-oil ratios to remain strong and to trend upward, potentially driving volume through our systems even without heightened producer activity. In the Mid-Continent region, positive activity is ongoing, with about 10 rigs operating on our acreage and more than 50 across the region. We expect processing volumes to grow by 12% at our guidance midpoint compared to 2022, averaging over 700 million cubic feet per day in 2023. Rig activity throughout the basin will continue to generate additional NGLs for our system. In the natural gas pipeline segment, we project strong demand for natural gas storage and transportation services in 2023. By the end of 2022, nearly 80% of our natural gas storage capacity was contracted under long-term agreements, and approximately 95% of our pipeline transportation capacity was also contracted. We anticipate similar levels for 2023. We are progressing on a project to expand our storage capabilities in Oklahoma by 4 billion cubic feet and are considering reactivating previously inactive storage facilities in Oklahoma and Texas. Construction is also underway on our Viking pipeline compression electrification project, with both the Oklahoma storage expansion and the Viking project expected to complete this year. Additionally, in late December 2022, a subsidiary of ONEOK applied for a presidential permit with the FERC to construct and operate new international border crossing facilities at the U.S.-Mexico border. These proposed facilities would connect upstream with a potential ONEOK intrastate pipeline called the Saro Connector and with a new pipeline in development in Mexico for delivery to an export facility on the West Coast of Mexico. Since the announcement, several positive developments have arisen concerning the potential LNG export project, with a final investment decision on the ONEOK pipeline anticipated in mid-2023. Pearce, that wraps up my remarks.

Thank you, Kevin, and thank you, Walt. We covered a lot today, and we have many reasons to feel confident in our 2023 guidance and our expectations for more growth this year. Everything that we've talked about today, from our 2022 performance to our future expectations and key differentiators for growth are all underscored by our commitment and focus on safety and environmental performance. Our company and our industry aren't immune to incidents, but I'm proud of how we have responded when challenges do occur and how we continue working to improve our performance going forward, focusing on safety and the health of our employees and the communities near where we operate. From our environmental perspective, we've made significant progress toward our greenhouse gas emissions reduction target, achieving reductions that equate to approximately 20% of our total 2030 reduction target. Our employees' dedication to meeting customers' needs while operating our assets in a safe, reliable, and environmentally responsible manner continues to drive our strong operational growth and financial performance year after year, and we're set up well for continued growth in 2023. With that, operator, we are now ready for questions.

Maybe to start off on the guidance. Last year, we had a couple of weather events and a material amount of frac capacity come offline, but guidance was still achieved. While some activity seems to have gotten pushed to 2023 from '22, the '25 guide yearly seems similar to 2022 original base guidance. So perhaps could you just talk about the puts and takes this year from last year and whether this is a base guide out performance or if we saw some volumes for G&P and NGLs get moved into '23.

Brian, yes, this is Kevin. I think probably the big thing is just like you mentioned the volume that was offline and really the delays we saw when the volume came offline primarily in April when we had the severe and historic weather events in North Dakota, that just delayed not only getting volume back online but it delayed some of the well connects as we entered into push back into '23. So that's why we feel really good about our '23 guide. Yes, we've got a significant step-up in well connects. But when you look at the wells, we've already connected to date, which historically is some of our lower months from a well connect perspective, and you look at the momentum we kind of built as we exited '22, we feel really good about where we're at volumetrically in both G&P and NGL out of the Bakken.

Great. And as a follow-up just on capital allocation. It seems like we should have pretty stable CapEx in the next few years with the MB-6 build-out. And just given the already announced dividend raise and leverage targets and payout ratios met at this point, how should we think about use of excess cash going forward?

Brian, this is an important question that allows us to clarify our key strategies for capital allocation. Firstly, we aim to invest in high-return organic projects that align with our current operations. Secondly, we intend to maintain and grow what we call a sustainable dividend. This means we want the growth of our dividend to be below the growth percentage of our earnings per share and also focus on our payout ratio, which I would say is around 85% or lower. We previously went above 100%, but our guidance for 2023 has brought it down below that level. Thirdly, we aim to maintain our strong investment-grade credit ratings with a target debt-to-EBITDA ratio of 3.5x. Once we achieve these capital allocation strategies, if we do have excess cash, we could consider share buybacks. This outlines our priorities regarding capital allocation.

First question, I wanted to touch on the third-party frac fees. You guys highlighted Mont Belvieu 5, frac 5 coming online and really sort of benefiting 2024 from the third-party frac 3 perspective. But I guess just given the fact it does come on or it sounds like it could come on early in the second quarter, is there any ability to leverage that frac as well in 2023? And to the extent you've considered any of that in the '23 guidance?

This is Sheridan. When the Medford incident happened, we quickly secured the frac capacity we believed we needed for 2023, factoring in that MB-5 would be operational in April. Our contracted frac capacity is significantly heavier in the early part of the year and will decrease once MB-5 comes online. This has all been incorporated into our settlement with the insurance company. Therefore, there hasn't been much change regarding the third-party frac we have. If volume surpasses our expectations, MB-5 will assist us in 2023.

Got it. Second question, multipart one on the Saro pipeline. So to the extent that does reach FID in mid-'23. I guess, one, would you expect any impact on the '23 CapEx budget? Or is that kind of more of a 2024 plus item? And then if you could just maybe give us any sense of cost of the pipeline, if you willing to take on JV partners? And then finally, just on the 2.8 Bcf a day of ultimate design capacity. Obviously, it's a pretty big pipe. Should we imagine that, that maybe comes on in phases or just how to think about the cadence there?

Spiro, this is Kevin. We are currently addressing many of your questions. We will not be providing a capital guide. Some money might be spent if we reach a final investment decision this year. However, since the main activity is expected to occur around 2025, most of the capital expenditures will be deferred.

So I wanted to ask about ethane recovery. You gave some broad expectations for ethane recovery across your footprint. But gas prices are pretty weak. It seems like they're going to stay there for a while. Can you just talk about opportunities for ethane recovery, specifically in the Bakken and what is actually reflected in guidance?

Yes, Michael, this is Sheridan. We have a very modest amount of ethane incentivized in our guidance, a little bit that we have already contracted and already locked down the spread. We have not done any more than that. As you said, we do see a lot of opportunity in '23 with this low gas price, which Kevin mentioned in his remarks, is making the United States pet chem very advantaged on using ethane as a feedstock going forward. And we think that we will continue to see more ethane recovery as we go through the year, especially as more demand comes on internationally, which we will pull the Mid-Continent up to be more in ethane recovery later in this year and will allow us to incentivize more ethane out of the Bakken at wider spreads than what we have done today.

Okay. Great. And then I also just wanted to ask another question about the frac market. It seems like everyone is adding frac capacity. And so I'm wondering if you think that's going to be pressuring rates over time at Mont Belvieu and within that context, how should we think about frac 6, how much of that is going to be contracted with third parties versus held-on account?

Michael, regarding the new frac capacity coming online, we are also among those building these facilities. We contract the volume and design our fracs to accommodate growth. As these new fracs enter the market, the spot market may experience some weakening compared to when our frac was offline. However, in the long run, these fracs are contracted and will be filled as the volume increases. With respect to MB-6, it's important to note that MB-6 is essentially a replacement for Medford, and like Medford, it is fully contracted. Our only significant addition to our frac fleet is MB-5, which we had already contracted prior to the Medford situation. Therefore, while we may see a slight decline in rates in the spot market, I don't anticipate a long-term decline in rates.

On the 3.5x leverage target, Walt, you've spoken about it as being aspirational for some time. But at this point, with 2022 and given your 2023 guidance, it seems more reality than aspirational. So how are you thinking about it now? Is the plan to hold this level going forward? Or are you not ready to commit to that with Sahara ahead of you? And what is still a pretty good oil price environment?

Well, Harry, I think that we've definitely achieved the goal as we sit here today, given the fact that we had an $830 million infusion from the insurance settlement. Over the course of the next couple of years, we obviously will utilize some of that cash to build out MB-6. We would expect to come back into that 3.5x or below in the not-too-distant future. We like that as a spot to give us flexibility going forward. But I think the peers walked through our capital allocation thoughts earlier. We're not concerned if it trails down a little bit lower as we look for projects. But I would just go back to Pierce's discussion about our capital allocation.

Okay. My follow-up is about your recent redemption of one of your maturities later this year. You have another one coming up. Can you provide any guidance on potential financing plans for the year and how you plan to manage your needs in the debt capital markets?

Sure. Well, yes, you're right that we actually did the make call because we could do it at par on the 4.25% for May. The other coupon that we have later in the year is 7.5%. So the make call doesn't work. So we'll wait until the actual contractual call date, which I think the first time we can do that is early May. I think you can assume that given the fact that we have had this cash infusion that we will take that out for cash at that point in time. And we'll just assess our needs as we go through the year if there is a need for any further issuance. But as we sit today, we will cover off our maturities with cash on hand.

First, I'd like just to focus a little bit on the macro front. What are your thoughts on comfort level on backing egress out of the basin? And further, are you seeing the need for Bison River, any other ways to add gas capacity there?

Jackie, this is Kevin. Regarding the macro situation in the Bakken and gas takeaway, we believe there is still between 300 million and 400 million cubic feet of capacity available on Northern Border that the basin can price out. To put it another way, there has been about 100 million cubic feet per day of displaced gas moving from Canada that has shifted south and southwest to WBI and into the Cheyenne market, which we are part of. We're actively engaged in the Northern Border open season on Bison Express, a project that TC Energy has reported positive results on. This creates an opportunity for us. From an egress standpoint, we are optimistic for the coming years, even with strong growth projected. Additionally, our NGL system can expand by simply adding pump stations, which requires minimal capital and time compared to other projects. Overall, we feel very positive about the macro environment in the basin. We do not need more rigs to meet our guidance; the existing rigs combined with finishing some DUCs put us in a strong position to achieve our volume guidance in both the gathering and processing and the liquids segments as we assess the situation in the basin.

Okay. Great. And just one quick follow-up. A little bit more into CapEx. What goes into that upside, downside for the CapEx range? What's is are there? And could you potentially provide some color on the components or segment-level spend? What's the majority of that spend specifically allocated to?

We're not going to get into segment by segment. But like Walt mentioned in his remarks, we're finishing up MB-5. We've got MB-6, a pretty significant amount of the MB-6 spend that will occur in '23. And then the uptick in activity when you think about the step-up in well connects in both the Mid-Continent and the Bakken, that's going to drive some additional capital needs from a well connect little horsepower, may need to add some pumps here or there in the NGL segment, those types of things, but those are highly efficient capital and typically generate very strong returns. So those are the types of things that we've seen. And then also, we've got some of those type projects in the gas pipeline segment as well that we're finishing up when we talked about our storage and some other expansion opportunities.

At a higher level, we've seen some of the public E&Ps gobble up some of the private companies and then kind of slow their pace of activity down. So I was just wondering if you could maybe talk about any exposure you have public versus private or any observations you've seen if maybe one of these deals that happened with your assets?

Neil, this is Kevin. We really haven't seen much impact. In some instances, larger public companies have actually reduced their acreage, which they were considering to be more Tier 2 or Tier 3, and we've observed that companies acquiring this acreage have started drilling. This has been somewhat of a trend. However, we have noted very consistent investment from the large public companies we work with, especially in the Bakken and the Mid-Continent regions, where they have consistently allocated capital.

All right. That's a great point on the flip side of that. And then for my follow-up, in the PRB, one of the large operators has kind of said they were shifting to the Mowry, which brings a much higher gas cut. I just wanted to check and see if you are seeing is that what you're seeing? Or is that what you're planning for? Or is the kind of guidance for the Rockies more so about the Bakken growth and maybe the PRB just assumes moderate growth?

Yes. The last is what is the way we think about it. We've got a nice position in the G&P segment. We do have a very nice large position in our NGL business. There's been several operators out there that have talked about the Powder and spending more capital. So we do have some modest growth built in. But the driver of the Rockies volumes is going to come from the Bakken.

I wanted to touch on the implications of building MB-6 to essentially replace Medford. I'm assuming that you're going to flow less purity volumes on Sterling and transition more to Y-grade down to Bellevue on Arbuckle. And I wanted to know the runway for Arbuckle on latent capacity before you'd have to consider an expansion for the increased volumes?

Neil, this is Sheridan. Yes, you're right. As we put MB-6 or as we're moving raw feed today, we're not moving as much purity products on the Sterling system. But as it comes to expanding Arbuckle II, we, as we did with other pipes, put it in a large diameter pipeline that if we need more capacity, it's very easy to put in a couple of more pump stations, and we get hundreds of thousands of barrels more of capacity on that pipeline. And obviously, we are watching that, and we can react very quickly. So it's fair to say we will not run out of raw feed capacity to Mont Belvieu from the Mid-Continent.

Got it. Great. Regarding the second question about optimization opportunities, with the reduced capacity in Conway and occasional propane shortages in that market, how does the higher capacity and value compared to Conway affect the optimization revenues moving forward once you receive the insurance proceeds?

Neil, as we analyze the situation, it will change slightly, but I don't believe the financial impact will be significant. When we assessed whether to rebuild Medford or proceed with MB-6, we found that most of the volume from Medford already goes to Mont Belvieu on average. Furthermore, I view this move of MB-6 as restoring us to the position we were in prior to the installation of the Busan fractionator at ONEOK. Currently, the Busan fractionator has sufficient volume to meet the mid-continent market demand. We've adjusted our business to align more with Bellevue. Essentially, we will have the opportunity to capitalize on occasional spikes in the Conway market compared to previous periods, and we will optimize the overall feed system to the fractionators in Mont Belvieu. Overall, I don't expect this to significantly affect our optimization business.

To start off kind of a 2-parter on the volume outlook. I was wondering if you could provide a breakdown of that 10% G&P inlet growth assumption in '23 between the Mid-Con and Bakken. And the second part of that question was kind of what's the right way to think about volumes and EBITDA growth in '24 if you guys have 20-plus rigs on your acreage for 2 to 3 years.

We provided the breakdown for Mid-Continent versus Rockies and included the guidance range materials for 2023. In terms of growth, we noted that about 15 rigs are needed on our acreage to keep volumes steady. Therefore, if we maintain over 20 rigs on our acreage, we can expect growth. This would mean an increase in 2024 compared to 2023, assuming activity levels in the Bakken remain consistent. The same applies to the Mid-Continent. Additionally, the increasing gas-to-oil ratios will contribute positively to volume growth, especially if we maintain the current activity levels.

Got it. Appreciate that. And then I appreciate that you guys spoke on frac fees a bit earlier, but just wondering if maybe you guys could provide a rough sense of what third-party frac fees look like per quarter in '23 and then maybe for 2024 as well given like the incremental volume growth maybe could we think about third-party frac fees in the $100 million range for '24?

Yes. We are not going to provide a detailed breakdown of our fracking costs for competitive reasons as we move through 2023. However, I can say that what we have received from the insurance company will cover the payments to third-party fracking services in both 2023 and 2024.

I just wanted to confirm one thing regarding your comments on the Medford fractionator. Did you mention that it is fully contracted? Is it safe to assume that all your third-party frac leads for 2023 and 2024 are contracted at this point?

Yes. Yes, that's a good assumption.

Okay. And then on the Saguado gas pipeline, in addition to the FERC approval, I was curious what are other kind of getting items for that project? And could you look at a kind of a JV or a partnership for that pipeline? And then lastly, would you look to finance all of that, if that were to move ahead on your balance sheet or you could look at some other ways to finance.

Kevin here. We're still in the early stages from the pipeline perspective. This would be an intrastate pipeline, meaning we wouldn't require additional FERC approvals to actually construct it if it reaches FID. Regarding partnerships, we currently plan to own the pipeline, but if a strategic and economic reason arises for partnering, we would consider that. For now, we are treating this as if our pipeline will simply be part of the broader pipeline service delivering gas to the West Coast of Mexico.

Yes. I mean. So this pipeline is going to be built over a course of several years in the context of our normal CapEx, we would just do it on our balance sheet unless we found an attractive source of capital that was more efficient than the normal way. We always are keeping our eyes open for that sort of thing. But I don't think it would have a significant change in our CapEx program going forward. So not one that we would have to change our ordinary course.