Kinder Morgan, Inc. (KMI) Q1 2022 Earnings Call Transcript

Kinder Morgan, Inc. (NYSE: KMI) Q1 2022 earnings call dated Apr. 20, 2022

Corporate Participants:

Richard D. Kinder — Executive Chairman

Steven J. Kean — Chief Executive Officer

Kimberly Allen Dang — President

David P. Michels — Vice President and Chief Financial Officer

Tom Martin — President, Natural Gas Pipelines

Analysts:

Jean Ann Salisbury — Sanford C. Bernstein — Analyst

Colton Bean — Tudor, Pickering, Holt and Company — Analyst

Jeremy Tonet — J.P. Morgan — Analyst

Brian Reynolds — UBS — Analyst

Chase Mulvehill — Bank of America Securities — Analyst

Michael Lapides — Goldman Sachs — Analyst

Keith Stanley — Wolfe Research — Analyst

Becca Followill — U.S. Capital Advisors — Analyst

Presentation:

Operator

Good afternoon, and welcome to the Quarterly Earnings Conference Call. [Operator Instructions]

I would now like to turn the call over to Mr. Rich Kinder, Executive Chairman of Kinder Morgan. Thank you. Sir, you may begin.

Richard D. Kinder — Executive Chairman

Great. Thank you, Michelle. Before we begin, I’d like to remind you, as I always do, that KMI’s earnings release today and this call include forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 and the Securities and Exchange Act of 1934 as well as certain non-GAAP financial measures. Before making any investment decisions, we strongly encourage you to read our full disclosures on forward-looking statements and use of non-GAAP financial measures set forth at the end of our earnings release as well as review our latest filings with the SEC for important material, assumptions, expectations and risk factors that may cause actual results to differ materially from those anticipated and described in such forward-looking statements.

Let me begin by, today, we formally announced our dividend increase for 2022, taking the annual payout to $1.11, that’s the fifth consecutive annual increase. Also, as Steve Kean and the team will tell you, the year is off to a good start, but I want to talk about broader issues that impact all of us. Since our last call in January, seismic events have occurred. The Russian invasion of Ukraine has shaken the world order as we know it with a dramatic impact on the economy of Europe and indeed the entire world. Predicting how this whole tragic situation will be finally resolved is far beyond my capabilities, but I’m pretty certain the impact on the energy segment of the economy will be significant at least over the next several years.

This crisis has demonstrated the continued dependence of the world on fossil fuels, especially natural gas, and the inability to develop a satisfactory substitute in the short to intermediate term. This situation is illustrated by the frantic efforts of Europe to win itself from its overwhelming reliance on Russian natural gas. Beyond that, we are shown once again how the tight the world market is for oil, natural gas, NGLs and even coal as we look at the dramatic escalation in prices since the war began in late February.

What does this mean for the energy space in America? In my judgment, the crisis plays to our strengths. The U.S. is a reliable supplier with the ability to grow its production modestly in the near-term, and more robustly, in the immediate term. We operate under a transparent legal system. And we have technical expertise from the well-head to the burner tip that is unmatched anywhere in the world. For all these reasons, the United States will be a major part of the solution to adequately supply the world with oil and natural gas it needs to surmount the present problem.

In particular, the U.S. will be a major supplier of additionally LNG to Europe to replace, at least in part, Russian gas. I anticipate that all of our present LNG export facilities will be running at capacity for the foreseeable future and the contracts necessary to support the construction of new facilities in the next few years will be more attainable than they’ve been in the past. By way of caution, I’m still concerned that our Federal government will not properly expedite the permitting of these new facilities. But I’m reasonably hopeful that at some point this administration will recognize the importance of playing its energy cards to support its allies and sanction its adversaries.

The impact of these developments will benefit the midstream energy segment and Kinder Morgan specifically in both the short-term and the long-term. At Kinder Morgan, we move about 40% of all the natural gas in America and about 50% of the gas going to LNG export terminals. As volumes increase, throughput will increase as well the need for selective expansions and extensions of the network. In short, it’s a good time to be long natural gas infrastructure. Steve?

Steven J. Kean — Chief Executive Officer

All right. Thanks, Rich. So after wrapping up a record year financially in 2021, we’re off to a strong start in 2022 with strong performance in our base business and attractive opportunities to add growth. We’re keeping our balance sheet strong, exceeded our plan in the first quarter, and even though it’s early in the year, we are projecting to be above plan for the full year.

In addition to commodity price tailwinds, we experienced very strong commercial performance in our gas business with continued improvement in our contract renewals, especially on our flexible gas storage services, good performance during the winter and new emerging project opportunities in our Bakken, Haynesville and Altamont assets and increasing interest in new Permian transportation capacity.

On the Permian, we are working on the commercialization and development of compression expansions on our PHP and GCX pipelines. While we will need to do a small amount of looping, most of the expansion can be accomplished with additional horsepower. Compression expansions are low-risk from a sighting and permitting perspective and they are very capital-efficient. So they do come with a higher fuel rate for the customer.

Most importantly, in today’s environment, compression expansions allow for speed to market. Once we have contracts and make FID, we believe we can get to in service in about 18 months. We believe the market will need that capacity in that timeframe and see one or both of these expansions as the near-term solution, pushing our potential greenfield third pipeline further in time. Combined, the two expansions can add 1.2 Bcf per day of capacity out of the Permian.

Finally, for gas, our Stagecoach storage asset, which we acquired in 2021, helped us with our strong winter performance and continues to perform above our acquisition model. Our CO2 business was aided by commodity prices and also operational outperformance versus our plan. We continued to advance our three renewable gas projects, which we picked up in the Kinetrex acquisition last year, and we are advancing additional opportunities in our Energy Transition Ventures Group. Our products pipelines were modestly above plan for the quarter. And while terminals missed plan by a bit, we started to see good recovery in our Jones Act charter rates and continued strong performance in our bulk terminals business.

For the balance of the year, commodity prices continue as a tailwind and we have locked in enough, such that our updated sensitivity is about $4 million per $1 movement of WTI. We expect continued strength in our base business, but we also expect to experience some negative impact from cost pressures due both to additional maintenance and integrity work that we added to the plant for this year as well as some higher costs on certain materials, chemicals, parts and vehicle fuel. Still, taking all of this into account, we are predicting that we will be above plan for the year. In summary, we’re doing very well.

With that, I’ll turn it over to Kim.

Kimberly Allen Dang — President

Thanks, Steve. I’ll go through the segments starting with natural gas. Our transport volumes there were up 2% or approximately 0.9 million dekatherms per day versus the first quarter of 2021 and that was driven primarily by increased LNG deliveries, generally colder weather, partially offset by the continued decline in Rockies production and a pipeline outage on EPNG. Deliveries to LNG facilities off of our pipes averaged approximately 6.2 million dekatherms per day with the 32% increase versus Q1 of ’21. Our market share of deliveries to LNG facilities, as Rich mentioned, remains around 50%.

Exports to Mexico were down in the quarter when compared to Q1 of ’21 as a result of third-party pipeline capacity added to the market. Overall deliveries to power plants were up 5% and we believe that natural gas power demand is becoming more inelastic relative to coal. Deliveries to LDCs and industrials also increased. The overall demand for natural gas is very strong, both our internal and WoodMac numbers project between 3 and 4 Bcf of demand growth for 2022. And in our numbers, we project growth in all major categories; res-com, industrial, power, exports to Mexico and LNG exports.

Our natural gas gathering volumes were up 12% in the quarter compared to the first quarter of ’21. Sequentially, volumes were down 6% with a big increase in Haynesville volumes, which were up 14%, more than offset by lower Eagle Ford volumes, which were impacted by contract termination. Overall, our budget projected gathering volumes in the natural gas segment to increase by 10% for the full year, and we are currently on track to exceed that number.

In our products pipeline segment, refined product volumes were up 7% for the quarter compared to the pre-pandemic levels using Q1 of ’19 as a reference point. Road fuels were down about 0.5%, so essentially flat, while jet was down 18%. We did see a decrease in the monthly growth rate as we went through the quarter, so higher prices may be starting to impact demand. Crude and condensate volumes were down 4% in the quarter versus the first quarter ’21. Sequential volumes were flat with the reduction in the Eagle Ford offset by an increase in the Bakken.

In our Terminals business segment, the liquids utilization percentage remains high at 92%. If you exclude tanks out of service for required inspection, utilization is about 95%. Our rack business, which serves consumer domestic demand, was up nicely in the first quarter. Our hub facilities, which are driven more of by refinery runs, international trade and blending dynamics were also up significantly. As Steve said, we’ve seen some green shoots in our marine tanker business with all 16 vessels currently sailing under firm contracts and day rates are still improving, but still lower relative to expiring contracts.

On the bulk side, overall volumes increased by 19%, driven by pet, coke and coal, which more than offset lower steel and ore volume. In our CO2 segment, crude volumes were essentially flat compared to Q1 of ’21 and NGL volumes were up 7%. CO2 volumes were down 9%, but that was due to the expiration of the carried interest following payout on a project in ’21. On price, we saw very nice increases in all of our primary commodities.

Overall, we had a very nice start to the year. For the first quarter, we exceeded our DCF planned by 4%. We estimate that roughly half of that outperformance was due to price and the other half due to strength in our base business. As Steve said, we currently project that we will exceed our full year 2022 plan. We’ve not specifically quantified the outperformance, because one, it is relatively early in the year. And two, there are a lot of moving pieces, commodity prices, gathering volumes, inflation, regulatory demands and interest rates to name a few. But we expect the upsides to outweigh the downside.

And with that, I’ll turn it to David Michels.

David P. Michels — Vice President and Chief Financial Officer

All right. Thank you, Kim. So for the first quarter of 2022, we are declaring a dividend of $0.2775 per share, which as Rich mentioned, is $1.11 annualized and 3% up from our 2021 dividend. For the quarter, we generated revenues of $4.3 billion, which is down $918 million from the first quarter of last year. However, when you exclude the large non-recurring contribution from winter storm Uri from last year, our revenue would have been higher this quarter versus last year. And our net income was $667 million, down from the first quarter of 2021, but excluding the contribution from winter storm Uri last year, our net income during the first quarter of 2021 would have been $569 million. So relative to that recurring amount, we generated $98 million or 17% higher net income this quarter versus last year.

Our DCF performance was strong, natural gas segment was down $797 million, but again, the winter storm contribution from last year, which was over $950 million in the first quarter of 2021 led to the majority of that decline this quarter. Otherwise, we had nice outperformance in our natural gas segment, driven by contributions from our Stagecoach acquisition, Tennessee Gas Pipeline contributions, Texas Intrastate as well as greater volume on KinderHawk.

The Products segment was up $36 million, driven by increased refined product volumes and favorable price impacts, partially offset by higher integrity costs. And our Terminals business, up $11 million versus Q1 to 2021, again, greater contributions from our bulk terminals, driven by higher pet, coke and coal volumes as well as growth in our liquids terminals business due to expansion project contributions and an unfavorable impact from winter storm Uri during 2021, and those were partially offset in the Terminals segment by lower contributions from our New York Harbor Terminals and our Jones Act tanker business.

Our CO2 segment was down $83 million and more than all of that decline is explained by the segment’s contribution from winter storm Uri during 2021. Other than that, the CO2 segment is up nicely year-over-year, mainly driven by commodity prices. Total DCF generated in the quarter was $1.455 billion or $0.64 per share. That’s down from last year. But again, excluding the non-recurring contributions from winter storm Uri, our DCF would be up $203 million or 16% higher compared to the first quarter of 2021.

Moving on to the balance sheet. We ended the quarter with $31.4 billion of net debt with a net debt to adjusted EBITDA ratio of 4.4 times. That’s up from 3.9 times at year end 2021, but excluding the non-recurring EBITDA contributions from Uri, the year end ratio would have been 4.6 times. So we ended the quarter favorable to our year end recurring metrics.

The net debt during the quarter increased $191 million, and here’s a reconciliation of that change. We generated $1.455 billion of DCF. We paid out $600 million of dividends. We contributed $300 million to our joint ventures and to growth capital investments. We had $250 million of increased restricted deposits, which is mostly due to cash posted for margins related to our hedging activity. And we had a $500 million working capital use, which is not uncommon in the first quarter when we have higher interest expense payments, property tax bonus payments. We also had a rate case reserve refund paid. And that explains the majority of the $191 million for the quarter.

And with that, I’ll turn it back to Steve.

Steven J. Kean — Chief Executive Officer

Okay. Thanks, David. Michelle, if you could come back on and open it up for questions. And I’ll just point out, we’ve got our entire senior management team around the table here, so we’ll be passing the mic if you have questions about our different segments and their performance and outlook, etc. So Michelle, open it up, please.

Questions and Answers:

Operator

Thank you, sir. [Operator Instructions] Our first caller is Jean Ann Salisbury with Bernstein. You may go ahead.

Jean Ann Salisbury — Sanford C. Bernstein — Analyst

Hey, I just wanted to ask about the potential compression expansion. How are customers comparing the compression expansion option versus the newbuilds? Are the rates similar? Obviously, you mentioned that the timeline to market is factor, which is great. But maybe the compression rate is lower since the fuel cost is higher. Just wanted to understand which was kind of more attractive to customers.

Steven J. Kean — Chief Executive Officer

Very good. Tom Martin, President of our Gas Group.

Tom Martin — President, Natural Gas Pipelines

Yeah. I mean, can’t get too specific about overall rates because it’s a competitive situation, but I think I’ll just say, it is attractive to the market in total. As Steve said, it is more fuel costs, but that will be at least partially offset by the fixed fee that’s associated with it. I think the key is speed to market. And that’s the message that we’re hearing from our customers is that getting this in service in 2023 will really help alleviate a containment issue that we’re really seeing — starting to see now and certainly expect to get much worse as we get into 2023. So not ready to call this a win yet. Clearly, we’ve got a lot of work to do, but getting some good feedback.

Jean Ann Salisbury — Sanford C. Bernstein — Analyst

Great. That’s helpful. And I guess, on that topic, is 18 months to add compression and some looping kind of longer than a similar project in the past? Is it due to supply chain issues going on or am I just too demanding?

Tom Martin — President, Natural Gas Pipelines

Yeah. I mean, it may be somewhat longer, but we’ve made some mitigating steps, we’ve taken some mitigating steps to help make that better than it otherwise could have been. But I think in these times that’s probably indicative if not longer.

Jean Ann Salisbury — Sanford C. Bernstein — Analyst

Okay. And then just one more follow-up on this, if I may. Are you seeing any movement from kind of the people that have not traditionally signed up for long-term contracts, like the privates to sign-up this time given more constraints on flaring and everything or do you think it’s going to likely be the same mix of customers as in the past?

Tom Martin — President, Natural Gas Pipelines

Again, hard to speculate specifically on customers, but I think I would say, it’s a broader set of customers in general than what we may have seen on the greenfield projects. So speaking I think really to the point you’re making is that there are — there is a broader set of customer interest at this time.

Jean Ann Salisbury — Sanford C. Bernstein — Analyst

Great. That’s all from me. That’s super helpful. Thank you.

Operator

Thank you. Our next caller is Colton Bean with Tudor, Pickering, Holt and Company. Sir, you may go ahead.

Colton Bean — Tudor, Pickering, Holt and Company — Analyst

Good afternoon. So you all mentioned seeing higher cost in the release, can you just elaborate on where you’re seeing those cost hit the system, whether that’s materials, labor or other areas?

Steven J. Kean — Chief Executive Officer

Yeah. So there are two categories of higher costs here. One is that we’ve added some work to the plan, okay? So we’ve added some incremental integrity and maintenance work to the plan. And so that’s not an inflation thing, that’s just a scope of work thing. And it’s not a ongoing or recurring, but we’re doing some work there that we’ll be doing this year and probably next year. That’s one category.

The second thing is, we haven’t experienced a great deal of inflation to date. We experienced as normal. When commodity prices are up, you see it in the oil field, right, but commodity prices are up, the revenues are up to go with it. So we’re seeing some there. The other places where we’re seeing inflation, we projected a little inflation, but the places where we’ve actually experienced it are obviously fuel for our trucks and for our other equipment. So fuel prices are up, those prices are up, related hydrocarbons or composites like lubricants is also up and some materials, steel cost for certain equipment has come up and raw steel has come down a little bit. It’s been down then up a little. So it’s some materials, equipment, lubricant and fuel.

Colton Bean — Tudor, Pickering, Holt and Company — Analyst

Great. I appreciate that. And then Rich mentioned the need for incremental U.S. LNG. Are there any optimization opportunities available to you all at Elba Island or alternatively if market interest has increased, could that be a potential divestiture candidate?

Steven J. Kean — Chief Executive Officer

Tom?

Tom Martin — President, Natural Gas Pipelines

Yeah. So the current project is fully utilized by our customers. There certainly is an opportunity to do an expansion there, a small scale expansion. We had those discussions a couple of years ago. Obviously, with what is happening now, we’re testing that off again. Again, very early days to say whether there is a real potential there. But overall, the market opportunity suggest that may be something worth looking at.

Steven J. Kean — Chief Executive Officer

And Colton, the thing I’d add to that is just that, a lot of the way we’re participating in this LNG growth opportunity both what has come to pass already and what we believe is still to come is off of our network. And so we could participate in that market and the growth opportunity by serving them and serving them well with our pipeline infrastructure and our storage assets along our network, and particularly, with a lot of that growth coming in Texas and Louisiana where our footprint is especially robust. And so Elba is something we will evaluate. As Tom said, we’ll work with our customer on that. But really a big play for us in the trend here is to be able to bolster what we do it from a transportation and storage service provider standpoint.

Colton Bean — Tudor, Pickering, Holt and Company — Analyst

Got it. That’s helpful. I appreciate the time.

Operator

Thank you. Our next caller is Jeremy Tonet with J.P. Morgan. Sir, you may go ahead.

Jeremy Tonet — J.P. Morgan — Analyst

Hi, good afternoon.

Steven J. Kean — Chief Executive Officer

Good afternoon.

Jeremy Tonet — J.P. Morgan — Analyst

Just wanted to see with the compression expansions if you are able to provide any thoughts with regarding to capital outweigh there for us to kind of frame it? You talked about being more capital efficient than a greenfield. And then at the same time, as it relates to the new greenfield, does this really change, I guess, the pace of higher exploring those — the pace of that project given how it’s going to take longer to build a pipeline today than it did in the past? And so presumably, there’s going to be need for incremental pipe beyond these expansions pretty quickly, at which point, the Permian Pass could service that need?

Steven J. Kean — Chief Executive Officer

Tom?

Tom Martin — President, Natural Gas Pipelines

Yeah. Again, I don’t think we want to get into capital discussion in a competitive environment on the expansion project. But I think to your second point, yeah, I think you’re exactly right, the market will fill up relatively quickly. We are estimating a greenfield pipe will now be needed some time in 2026 after all the expansions are done to fill the immediate need. And so with that given the timeline on doing greenfield type projects, I mean, that would lend itself towards an FID some time early next year for that kind of the project.

Jeremy Tonet — J.P. Morgan — Analyst

Got it. That’s helpful there. And then just want to kind of pivot towards, you discussed this GHG collaboration study with other partners in midstream here. And just wondering if you could expand a bit about that? I guess, the objectives behind that? And I guess, what were some of the drivers to moving forward with that project?

Tom Martin — President, Natural Gas Pipelines

Yeah. I mean, I think holistically, international LNG markets are driving the bus on getting RSG, a lower methane intensity type volumes. And so we’re certainly working with our good customer in support of that initiative. And really with this initial effort as a pilot program to help identify methane intensity on specific asset at specific locations with hope that that will broaden and ultimately support a certification process that will help earmark lower methane intense gas going to international markets.

Steven J. Kean — Chief Executive Officer

And Jeremy, I’d just add to that, we have seen a bit of an inflection this year. We’ve been talking about our low methane emissions intensity and marketing that as part of our service offerings and we’ll be doing that for a while. And we got a deal last year and we got another couple of deals following that. Got a tariff filing on TGP. There’s all of a sudden an enormous amount of interest in it. And by our estimation, about 25% of the natural gas produced in the U.S. today could qualify. And there, if you take all their targets into account, you get up to a third. And so we think that this is going to be a point of distinction in the future. We’re seeing evidence of that now.

Jeremy Tonet — J.P. Morgan — Analyst

And just to add on real quick there. Do you see this as something that increases profit or is it cost of doing business or how do you think about how this goes?

Steven J. Kean — Chief Executive Officer

Yes. Well, Tom, go ahead.

Tom Martin — President, Natural Gas Pipelines

Too early to say, I mean, I guess, my thought is that the ancillary services that come out of responsibly-sourced gas pooling efforts as well as some of the certification process as we go forward. But I think right now it’s more about identifying what we can do and what we can do on a large scale in the near-term and identifying ways to harness that for the market.

Jeremy Tonet — J.P. Morgan — Analyst

Got it. That’s helpful. Thank you.

Operator

Thank you. Our next caller is Brian Reynolds with UBS. Sir, you may go ahead.

Brian Reynolds — UBS — Analyst

Good afternoon, everyone. Maybe to start off on capital allocation, you talked about EBITDA guidance of roughly $7.2 billion being favors the upside versus the downside as we kind of sector the global macro uncertainty. Curious given the change in the global macro since the Analyst Day, have any assumptions changed around capital allocation and the buyback commentary from January? I guess, in another words, have capex needs been pulled forward with the GCX and PHP expansions or the potential of FID and new Permian pipe impacts Kinder’s process around some of the potential buybacks this year and next? Thanks.

Steven J. Kean — Chief Executive Officer

Yeah. There’s been no change in the principles. We are focused on making sure we keep the balance sheet strong and a refined available capital projects that provide good NPV at well above our weighted average cost of capital and returning value to shareholders with the dividend increase that we’re talking about today as well as share repurchases. So we do have some additional capacity given our performance. We have some additional capex in our forecast. We went up a little over $100 million from where we were in the budget. And we continue to look for those. But we’re into the year a good amount now. And I think we’re still confident in saying that we will have the capacity even with the opportunities coming forward. We’ll still have additional capacity beyond that.

David, anything you want to add?

David P. Michels — Vice President and Chief Financial Officer

No, I think you covered it.

Steven J. Kean — Chief Executive Officer

Okay.

Brian Reynolds — UBS — Analyst

Yeah, that’s super helpful. Maybe as a follow-up on the Ruby bankruptcy proceedings. Just kind of curious if you could talk about Kinder’s position as — it seems like there’s conflicting views on either handing over the pipelines to bondholders versus looking to repurpose the pipe for the long-term for additional purposes potentially at the expense of margin in the medium term. Any color would be helpful? Thanks.

Steven J. Kean — Chief Executive Officer

Yeah. So the overall message on Ruby is the same as it’s been for a long time, which is that we are going to make decisions here that are in the best interest of KMI’s shareholders. We’re hopeful that as we enter into this new process that we’re going to be able to work out reasonable resolutions. We continue to operate the pipeline. And I believe that’s what makes sense in the longer term. And I think you just have to separate out rhetoric in the court room from reality here. And so we’ll continue to work in a constructive way with our counterparties.

Brian Reynolds — UBS — Analyst

Appreciate the color. Have a good day, everyone.

Operator

Thank you. Our next caller is Chase Mulvehill with Bank of America. You may go ahead.

Chase Mulvehill — Bank of America Securities — Analyst

Hey, good afternoon. I guess, first question, I just wanted to come back to the natural gas egress discussion around the Permian. And I think many investors thought that you would probably see an announcement alongside today’s results for brownfield expansions of GCX and Permian Highway. It does obviously sound like it’s moving along, but I don’t know if you’d be willing to kind of provide maybe your thoughts around timing of when something could get officially sanctioned here? And then you said 18 months kind of — I guess, to get in service with sanction, are you ordering any long lead time items that could possibly move things up inside of 18 months? And then last one is just opportunities to expand or do expansions outside of kind of 42-inch pipes. Do you see any opportunities there?

Steven J. Kean — Chief Executive Officer

I’ll start and ask Tom to correct anything I get wrong here. But we’re not yet talking about timing. I think it’s fair to say the market is very interested and they see the wall coming in terms of capacity constrain. And so that has turned up the heat and turned up the volume on commercial discussions. And because of the timeframe that’s required in the timeframe and the speed to market that we’re able to offer, we like our chances very much in this discussion, but we’re not going to project a particular time.

It didn’t come alongside the announcement today because we get contracts before we go. And so we’re working on that and we’re working fast and hard on that. I’m not going to talk about specific commitments, but I’ll just say that we’ve been — obviously, we’ve not been ignoring the supply chain challenges in the marketplace. And so we’ve made what we believe are appropriate mitigation steps to mitigate that risk for us.

Chase Mulvehill — Bank of America Securities — Analyst

Okay. And any changes to when you think this bottleneck really festers in the Permian? I think you said last — last earnings call, you said, year end ’23. Is that kind of still the timeline of when you expect to see a bottleneck?

Tom Martin — President, Natural Gas Pipelines

I think sooner, early — later this year, begins in early ’23. I mean, you can look at just the financial basis markets and it gives you some insight into 2023, appearing to be more towards the train wreck than it is today. So yeah, absolute need for egress as soon as we can out of that basin.

Chase Mulvehill — Bank of America Securities — Analyst

Okay. Last one on repurposing assets. Could you talk about opportunities that you see to repurpose some of your underutilized assets? And then do you think this could be more near-term opportunities or really just really long-term opportunities you see to repurpose assets?

Steven J. Kean — Chief Executive Officer

We don’t have — there’s one project I can think of where we are actively looking at repurposing. It’s not a huge part. I don’t think you should count it as a huge part of our commercial activity right now, but it’s something that we continue to evaluate.

Chase Mulvehill — Bank of America Securities — Analyst

Okay, perfect. I’ll turn it over. Thanks everybody.

Operator

Thank you. Our next caller is Michael Lapides with Goldman Sachs. You may go ahead.

Michael Lapides — Goldman Sachs — Analyst

Hey, guys. Thank you for taking my question, and congrats on a great quarter. We’re a year and two months removed or so from Uri. Can you talk about what customers across the board, whether producers, utilities, power generators, whatever are saying to you in terms of storage rates, meaning gas storage rates, the tenor of new gas storage contracts and whether there’s a physical need for expansion of gas storage capacity?

Steven J. Kean — Chief Executive Officer

A good question. Tom Martin.

Tom Martin — President, Natural Gas Pipelines

Yeah. No, a lot of discussion in that area. And we have seen some contract renewals and a significant expansion on especially multi-cycle storage rates, especially in Texas, but I would say really across the whole footprint. And I think there are opportunities to expand our storage facilities, especially in Texas, we’re taking a hard look at doing that, and there seems to be a lot of interest in it.

So on both the power customers as well as local distribution customers, especially in Texas. I might add to our acquisition of Stagecoach was quite timely as well, kind of right in the middle of this whole trend. And as Steve said earlier, we’re performing well over our acquisition model assumption on that asset and especially as we integrate that with our Tennessee asset as well.

Michael Lapides — Goldman Sachs — Analyst

Got it. That’s super helpful. Just curious, when you get a — and I know it’s going to vary by site, obviously. But when you get a customer or a series of customers interested in having you expand your existing gas storage facility, how should we think about just the process and the timeline to actually physically be able to do so?

Tom Martin — President, Natural Gas Pipelines

Yeah. I mean, it depends on what kind of an expansion we’re talking about. If it’s adding withdrawal capability or compression to add injection flexibility, that’s probably two year timeline. So maybe slightly longer if you’re talking about leaching additional caverns. Again, it depends if it’s a brownfield type opportunity or a greenfield opportunity. But I think that’s generally, I would say, the timeline I would think about as we talk about expansion opportunities.

Michael Lapides — Goldman Sachs — Analyst

Got it. And then one last one and I hate to do back-to-back here, but a different topic. Just curious how you’re thinking about growth in the Haynesville from here after a pretty solid start to the year, kind of what you think the trajectory is? And whether you think Haynesville takeaway towards the Gulf Coast starts to get tight and whether you guys play a role in that?

Tom Martin — President, Natural Gas Pipelines

Yeah. So we’ve certainly seen tremendous growth year-over-year, quarter-over-quarter in our gathering assets, I mean, about 300,000 a day quarter-over-quarter and we’re forecasting upwards of 0.5 Bcf a day year-over-year full year forecast ’22 versus ’21. Yeah, and you’re absolutely right. I mean, I think as that growth accelerates not only on our asset, but other assets in the basin, egress out is going to become more critical.

I think there are some expansion projects that are probably more economical than an incremental greenfield. But I think we expect those to fill and there will be a need for incremental greenfield expansions out of that area as well, especially pointed towards the Gulf Coast for LNG exports. So we certainly are looking at that. I don’t have anything that we’re anywhere close to talking more about today, but we certainly see that as a potential opportunity.

Michael Lapides — Goldman Sachs — Analyst

Got it. Thank you, guys. Much appreciated.

Operator

Thank you. Keith Stanley with Wolfe Research. You may go ahead.

Keith Stanley — Wolfe Research — Analyst

Hi. Thank you. I had two quick follow-ups. First, Steve, you talked to the Elba expansion potential, maybe a long shot, but can you give an update on Gulf LNG as an export facility? I think it’s fully permitted. Is that a project that’s made any progress and any efforts there?

Steven J. Kean — Chief Executive Officer

As we’ve talked about in the past, we have a regas customer at that location who is paying for that capacity. Obviously, in today’s market, that’s not in high use, not in use generally at all, but we have a customer and they’re a paying customer and they reserve the capacity and we made a deal. Now we will work with that customer to see if there’s something that would allow us to bring the potential for a brownfield liquefaction opportunity forward, but we don’t have anything to announce there today.

Keith Stanley — Wolfe Research — Analyst

Thanks. Second one, sorry, another Permian expansion question, but a little different, I guess, than your usual business model. But since it’s less capital intensive, how do you think about contract durations for a Permian Gas Pipeline expansion? Are you willing to go less than the 10 years you’ve historically targeted or maybe not even fully contracted?

Tom Martin — President, Natural Gas Pipelines

Yeah. No, I mean, I think we’re thinking a minimum of 10 years and we’ll plan to sell all of this capacity. I think the market wants it. I think, like honestly, we maybe will be oversubscribed. So I think it’s a good opportunity to fully sell the project out, both projects.

Keith Stanley — Wolfe Research — Analyst

Thank you.

Operator

Thank you. Becca Followill with U.S. Capital Advisors. You may go ahead.

Becca Followill — U.S. Capital Advisors — Analyst

Hey, guys. Sorry, another Permian one. Acknowledging in your comments, Steve, about that you’re preparing for some of these items that you might need, do you feel like that there is sufficient compression that either you have on hand or have ordered that you could do both of these expansions within 18 months assuming that you FID them?

Steven J. Kean — Chief Executive Officer

Yeah. Again, we’re reluctant — we’re very — in a very competitive situation, Becca. I think what is fair to say is what I said, which is we’ve prepared…

Becca Followill — U.S. Capital Advisors — Analyst

Okay.

Steven J. Kean — Chief Executive Officer

Okay. Thank you.

Becca Followill — U.S. Capital Advisors — Analyst

The second one is on a new Permian pipe. Just in light of the Nationwide Permit 12 process that’s underway, do you feel like you could build a new pipe under that — under NWP 12 or do you feel like you would need to get individual water body crossings?

Steven J. Kean — Chief Executive Officer

Yeah. So it’s, first of all, really important on the — and I know you’re not asking about the compression expansions on this question. But one of the great things about these are that they are very permit-light, right? It’s getting an air permit under a permit by rule arrangement at the TCEQ. We think we can avoid issues that would otherwise trigger a more active Federal review by the core or anyone else. There’s some good mitigation built into our plans to avoid endangered species, to avoid open water crossings, etc. So we’ve got all that worked out.

Your bigger question, though, Nationwide 12 has been open to attack and it’s been attacked. There’s a process underway right now at the Federal level where a lot of open-ended questions are being asked about should we change this? Should we change that? Should we change the other thing? So there is some uncertainty around Nationwide 12 right now, no doubt about it.

Hopefully, that uncertainty resolves itself as we get closer to needing to use it for something like a big new greenfield pipeline expansion, but we are to be safe, evaluating in other context with smaller projects where we may be using Nationwide 12 evaluating how we could get individual permits if need be. Now for the most part, what the core will point you toward is Nationwide 12. That’s what it’s there for, use that. But if we were — it’s only prudent for us to evaluate if you end up in a problem there to have a plan B. And so we’re developing those plan Bs.

Becca Followill — U.S. Capital Advisors — Analyst

Perfect. Thank you.

Operator

Thank you. And at this time, I am showing no further questions in the queue.

Steven J. Kean — Chief Executive Officer

Great. Thank you very much. Have a good afternoon.

Operator

[Operator Closing Remarks]