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Kinder Morgan (NYSE:KMI)
Q1 2021 Earnings Call
Apr 21, 2021, 4:30 p.m. ET

Contents:

  • Prepared Remarks
  • Questions and Answers
  • Call Participants

Prepared Remarks:


Operator

Good afternoon, and thank you for standing by, and welcome to the quarterly earnings conference call. Today's call is being recorded. If you have any objections, you may disconnect at this time. [Operator instructions] It's now my pleasure to turn the call over to Mr.

Rich Kinder, executive chairman of Kinder Morgan. Sir, you may begin.

Rich Kinder -- Executive Chairman

OK. Thank you, Michelle. Before we begin, I'd like to remind you, as we 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.

To kick the call off, in addition to detailing our first-quarter results, we made two important announcements in our earnings release today. We've revised our full-year 2021 estimate for DCF and EBITDA substantially upward. Steve, Kim, and David will explain the underpinnings of that change. We also increased our dividend to an annualized rate of $1.08 per share as we promised when we released our original outlook for 2021 back in December.

In my judgment, this increase is an indicator of the significant parts of our corporate financial policy. First, it shows we are intent on returning value to our shareholders. Second, it demonstrates the consistent strength of our cash flow. To put this in perspective, this is the fourth consecutive annual increase in our dividend since 2017, when we were paying an annual dividend of $0.50 per share.

And we have accomplished that while maintaining a real focus on our balance sheet, having reduced our debt from its peak of almost $43 billion in 2015 to $30.7 billion today, a decrease of over $12 billion, quite an improvement. Now we're doing all this while continuing to pursue opportunities with our natural gas assets to firm up deliverability and supply to our customers, opportunities that were highlighted by the recent winter storm in Texas, and also while examining opportunities in the energy transition effort. At Kinder Morgan, we remain guided by what we believe is a sound corporate philosophy, fund our capital needs internally, maintain a healthy balance sheet, and return excess cash to our shareholders through dividend increases and opportunistic share repurchases. We think this is a recipe for long-term financial success for KMI and its shareholders.

And with that, I'll turn it over to Steve Kean, our CEO.

Steve Kean -- Chief Executive Officer

All right. Thank you, Rich. I'll focus on our performance during Winter Storm Uri, which is what drove our financial results in the quarter. Then I'll turn it over to our president, Kim Dang, to cover the business updates.

Our CFO, David Michels, will take you through the financials, and then we'll take your questions. So starting with the performance during the February winter storm. We were prepared, and that preparation served us well. Our previous investments in our assets, particularly on our gas storage assets, were a huge help.

We were on maximum withdrawal for days at several of our fields. Also helpful were our investments in backup generators at key compressor stations on our system. Another real key for us was our team. Our operations team deployed in advance to keep our facilities running and quickly repair them if they went down.

We deployed additional generators and tested our generators before the storm got here. Our people were at locations that are normally automated, and they were there in the bitter cold, and undoubtedly, many of them have their own families at home without power and water. Our team went to key compressor stations, storage facilities, and delivery points to keep gas flowing, including a key delivery point to the city of Austin. Our people kept us going.

Our investments and especially our team winterized us against a terrible storm. We also purchased additional gas, some at very high prevailing prices, to serve power plants and gas utilities. The result of all this was that we enabled our wholesale customers to serve needs that would have otherwise gone unmet, mitigating the tragedy that too many Texans endured. We performed well operationally and commercially across our entire gas network, but our financial performance was especially strong in our Texas intrastate pipeline and storage network.

And as I'll mention in a minute, in our CO2 business for reasons I'll explain. A key difference between our Texas intrastate system and our interstate gas pipeline systems is that we have a purchase and sale business in Texas, supported by high deliverability storage assets. In contrast, our interstate pipelines are nearly exclusively selling unbundled transportation and storage services. We do that in Texas, too, but we also have a purchase and sale business.

That business is generally done with reference to an index price. For example, we sell gas at the Houston Ship Channel index plus something and buy at Houston Ship Channel minus something. In normal circumstances, we're effectively getting a transport margin on our purchases and sales and using our proprietary storage to extract margin from price differences across time periods. When prices are in a normal range, this is a very stable business.

And we view our Texas intrastates as roughly 80% or so take-or-pay. In February, supply and demand conditions caused prices to go up by more than 100x and back down by the same order of magnitude over the course of a week. Market volatility like we experienced that week reveals the value of reliable pipeline and storage assets and a reliable operations team. It reveals the value of having gas in storage and previous purchase arrangements in place.

It also reveals the value of preparation in such circumstances in which supply and demand conditions causing prices to go up by more than 100 times, we were able to perform well financially, as well as operationally. Many of our additional sales, whether as a result of higher takes under our existing contracts or incremental sales that we were able to do during that week, took place at prevailing market prices. which during that week at the Houston Ship Channel, range from $180 MMBtu to $400 versus $3 earlier in the same month. What does this mean for our business longer term? We transact with sophisticated customers who have choices.

One of those choices is to purchase firm services from us on a long-term basis, and many of them do. While we view the events in our financial results as largely nonrecurring, we are already pursuing more long-term firm capacity sales and some associated capital investments that will help our customers to be even better positioned for future extreme weather and create incremental value for Kinder Morgan. There is substantial interest in our services following the storm, which should help us in our base business and in new origination. The results could be long-term, additional, and more consistent earnings and investment without the extraordinary and rare gain that we experienced in the first quarter.

The big lesson that should be taken away is that an appropriate amount of contracting for firm deliverability should be in everyone's portfolio. And February's event reveals the value of storage and firm transport capacity. And we would hope that any changes made in the market structure would adequately compensate and incent parties to do so. I mentioned our CO2 business also.

This is a bit of a different effect. That's our biggest power consuming business in the state of Texas. Our power contract with our provider enables us to shed load and be compensated at the prevailing power prices. When they started to see where power prices were headed, Jesse Arenivas and his team started looking at shedding load.

So we shut down oil production and shed the load back into the market, where it could be allocated to higher priority human needs. The contract work, as designed and particularly with prices as high as $9,000 a megawatt hour, we earned a substantial financial benefit, while letting those megawatts be made available to serve human needs. Also notable, for the longer term, Jesse and his team were able to restore production quickly and fully following the storm. That's a great accomplishment.

They had some practice when oil prices went drastically down last year, and we've gotten better at it since then. Our flexibility is greater. This is great flexibility that we've now built into a part of our business that consumes about 340 megawatts in the state of Texas. So good flexibility to have in the power market in the state of Texas.

So we're very proud of our whole team's performance, but we have lessons to learn too. And we'll use those lessons to get even better at severe weather performance for us and for our customers. So what will we do with the proceeds? Initially, of course, it's a reduction to our net debt. But as we repeated many times, our financial principles remain the same.

First, maintain a strong balance sheet. Second, we maintain our capital discipline through our return criteria, a good track record of execution, and by self-funding our investments. And as I mentioned, we may see some incremental investment opportunities as a result of the storm. We don't expect those to be significant for 2021.

Finally, we are returning value to our shareholders with a dividend increase that Rich mentioned. It's a well-covered dividend. And our approach to share repurchases remains exactly the same. We'll be selective, not programmatic.

We'll base our decisions on the returns versus the alternative uses for the cash that we generate, including projects or assets. So strong balance sheet, capital and cost discipline, returning value to shareholders. Those are our principles. One other item before I turn it over to Kim, we announced the formation of an energy transition ventures team during the first quarter.

We put together a team with financial, commercial, and engineering talent to focus on analyzing and quantifying opportunities for additional assets and service offerings tailored to the ongoing energy transition, including things like renewable natural gas and carbon capture and sequestration. This group reports to Jesse Arenivas, who continues as president of our CO2 business and is headed by Anthony Ashley, who previously served as treasurer and vice president of investor relations. While still in our early days for this effort, they've already identified and are working on a number of specific opportunities. More to come.

Also, as I said last time, our business units continue to focus on the energy transition opportunities that fit in with their operations, such as midstream services for renewable diesel and including our -- using our gas transportation and storage services to support renewable power. We are also marketing our low methane emissions performance as responsibly produced and transported natural gas. That's a good synergy between our ESG performance, our low methane emissions, and our commercial opportunities. We participated in our first one of these transactions with Colorado Springs Utilities, which they announced in the first quarter.

And we're working on another as we speak. We believe the winners in our sector will have strong balance sheets, low-cost operations that are reliable, safe, and environmentally sound, and the ability to get things done in difficult circumstances. We're proud of our team and our culture. And as always, we'll be prepared to meet the challenges and opportunities to come.

And with that, I'll turn it over to Kim.

Kim Dang -- President

OK. Thanks, Steve. First, I'm going to go through the business fundamentals for the quarter, and then I'll talk at a very high level about our full-year forecast. Starting with the natural gas fundamentals.

Transport volumes were down about 3% or approximately 1.1 million dekatherms per day versus the first quarter of '20. And that was driven primarily by declines in Rockies production, increase in transportation alternatives, and lower production out of the Permian, those two things impacting our volumes on EPNG and contract expiration on our joint venture pipe coming out of the Fayetteville. These declines were partially offset by higher volumes, which were driven by increased deliveries to LNG export facilities, winter weather in the northeast, and the PHP in service. Physical deliveries to LNG facilities off of our pipeline averaged approximately 4.7 million dekatherms per day.

That's greater than a 25% increase versus the first quarter of 2020. LNG volumes were down from the approximately 5 million dekatherms per day in the fourth quarter of '20. And that was due to the impact of Winter Storm Uri and some coastal fog in February. During the storm, total LNG exports dropped to under 2 million dekatherms per day.

In the first quarter, Kinder Morgan pipes moved approximately 47% of the volume going to LNG export facilities. Exports to Mexico on our pipes were up about 3% when compared to the first quarter of '20. Our share of Mexico deliveries in the first quarter ran about 55%. Deliveries to power plants, they were down due to higher natural gas prices.

Deliveries to LDCs were up due to colder weather. One, on our natural gas gathering volumes, they were down about 25% in the quarter compared to the first quarter of '20. But for gathering volumes, I think the more informative comparison is the sequential quarter. So compared to the fourth-quarter volumes, first-quarter volumes were down about 11%.

Approximately two-thirds of that 11% reduction are related to KinderHawk, which is our gathering asset in the Haynesville. But given that there are 45 rigs deployed in that basin, we expect that our volumes will increase sequentially each quarter for the balance of the year, although it will be a little bit slower than what we've budgeted. Eagle Ford volumes were also down versus the fourth quarter, and we expect that those will be down versus our budget. The Eagle Ford remains a very tough market, given the oversupply of takeaway options.

On the positive side, we expect volumes in the Bakken and Altamont to be on plan or better for the year. In our products pipeline segment, refined products volumes were down about 10% for the quarter versus the first quarter of 2020. And that's just the result of the continued pandemic impact. Gasoline volumes were up 6% versus the first quarter of '20.

That's an improvement from the fourth quarter when they were off about 10% versus the fourth quarter of 2019. Jet volumes remain weak off about 29%, but that's a big improvement from the fourth quarter when they were off 47% versus the fourth quarter of '20. And diesel volumes were up 6%, and that's relatively flat to the percentage in the fourth quarter. Total volumes moving through our pipes did improve each month during the quarter.

March volumes were up slightly versus 2020, and they were down about 6% versus 2019. Currently, we're forecasting refined products to be down versus our plan, and I'll go through that a little bit later in my comments. Crude and condensate volumes were down about 28% in the quarter versus the first quarter of 2020. Sequentially, they were up 2%.

Our terminals business fundamentals have been impacted by two events: the winter storm and the continued impact of the pandemic. The winter storm was short lived, with the impact limited to the first quarter. The pandemic is lingering, and it continues to impact our petroleum product volumes as well as demand for our Jones Act tankers. However, as we've mentioned in prior quarters, the impact of reduced petroleum product demand on our tankage is more muted than in our product pipeline, given the fixed take-or-pay contracts for tank capacity.

Our liquids utilization percentage, which reflects the tanks that we have under contract remains high at 95%. If you exclude tanks out of service for required inspection, utilization is about 98%. On the tankers, we have a number of ships that have contract expirations this year, and the market is relatively weak, given the weakness in refined product volumes. The reduction in crude oil production and the tightening WTI Brent spread also impacts this market, but to a much lesser extent, given a smaller percentage of the fleet engaged in that service.

We expect this market to improve with the recovery in petroleum product demand. But that may take in for later this year because charter activity tends to lag underlying supply and demand fundamentals. Now the CO2 segment was up in the quarter due to our decision to curtail production and deliver power back to the grid that Steve mentioned. Excluding the storm impact, oil production was down approximately 15%.

CO2 sales volumes were down 26%. Our net realized oil price was down about $3.50 per barrel. However, compared to our budget, we're currently anticipating the oil volumes, CO2 volumes and net realized oil price will exceed budget for the year. Now let me give you a very high-level update on our full-year forecast.

As we said in the release, we're currently projecting full-year DCF of $5.1 billion to $5.3 billion versus our budget of $4.45 billion. We estimate that the Uri impact, and this is across all of our segments, was roughly worst-season hand grenades $1 billion, leaving a variance, again, very roughly, of $200 million to $350 million versus our budget. I know $200 million doesn't add up perfectly, but that's because these are very large rounded numbers. Let me start with the $200 million variance.

We estimate that sustaining capex will be approximately $75 million higher than our budget due to the decision to replace some pipe in rural South Texas as opposed to continuing to spend money running inspection tools and repairing the pipe. We were also able to obtain the pipe at very attractive pricing. What I'll classify as pandemic-related impacts is roughly $80 million, and that includes weaker petroleum products volumes and lower renewal rates on Jones Act tankers. Those two items explain about 75% of the variance, but there are a lot of other moving parts.

A couple of the other larger items include lower gathering volumes, primarily in the Eagle Ford, and the impact on DCF of a Ruby impairment. Those two items are roughly offset by positive performance in the CO2 segment, from higher CO2 and oil volumes and price. Finally, the sale of our 12.5% interest on NGPL creates a negative variance versus our budget. The difference in that low and the high end of the guidance range primarily relates to assumptions on petroleum products volumes, Jones Act tanker renewals, natural gas GMP volumes, and the resolution of certain Uri contractual disputes.

I think it's obvious, but just in case, the lower end of the guidance range assumes a more conservative outcome on these items. For example, The high end of the guidance range assumes petroleum products volume 3% below plan for the balance of the year versus the low end of the guidance assumes they're about 5% below plan for the balance of the year. And with that, I'll turn it over to David Michels.

David Michels -- Chief Financial Officer

All right. Thank you, Kim. So for the first quarter of 2021, as Rich mentioned, we are declaring a dividend of $0.27 per share, which is 3% up from last quarter. Now looking at the financial performance for the first quarter of this year versus the first quarter of last year, we generated revenues of $5.2 billion, up $2.1 billion.

We had partial offsets in our -- a partial offset in our cost of sales with an increase of $1.3 billion there. So our gross margin was up $759 million, mostly driven by our strong performance during the winter storm. Our O&M costs declined as a result of the CO2 segment power load shed that Steve walked through. And that's the main item in the $106 million favorable O&M amount.

In the first quarter of 2020, we also took impairments in our CO2 segment of $950 million, which explains most of the $975 million favorable in the item -- the line item called gain and loss on divestitures and impairments. This past quarter, we wrote off the value of our Ruby subordinated note, which was a reduction of $117 million in the earnings from equity investments. And that was driven by greater uncertainty regarding the recoverability of that note receivable. We also reflected a $206 million gain on the sale of a partial interest in NGPL, and that appears in the other net line item.

So overall, we generated net income of $0.62 per share, which is very favorable versus the $0.14 loss in the first quarter of 2020. On an adjusted earnings per share basis, and then that's where we show earnings per share before certain items, we generated $0.60 per share versus $0.24 per share a year ago. Moving to our segment EBDA and distributable cash flow performance. Our natural gas segment was up $915 million for the quarter, mostly explained by favorable intrastate margins as well as increased revenue on our Tennessee Gas Pipeline, both as a result of the February winter storm performance.

We also had favorable contributions from PHP, which was placed in service at the beginning of the year. And these are all partially offset by lower contributions from our FEP pipeline resulting from the 2020 contract rollovers. Product segment was down $10 million, driven by lower refined product volumes on SFPP, lower crude oil volumes on KMCC, and lower recontracting rates at HH, partially offset by greater contributions from our transmix business. Our terminal segment was down $30 million.

And that's really refined product volumes due to continued pandemic-related demand impacts, as well as winter storm-related demand impacts. As has been mentioned, our Jones Act tanker contributions were also down lower due to the lower fleet utilization resulting from the pandemic-related market weakness. Storm-related refinery outages also drove decreased contributions from our pet coke facilities. And these were all somewhat offset by our expansion project contributions.

Our CO2 segment was up $116 million this quarter versus a year ago. Again, due to the shedding load to deliver power to the grid. And partially offset by lower -- and that was partially offset by lower crude and CO2 volumes versus Q1 2020 and lower realized crude prices versus Q1 2020. Our G&A at corporate and corporate charges were higher by $8 million.

And there we had lower capitalized overhead expenses, partially offset by our organizational efficiency savings. JV depreciation, we had less JV DD&A from our Ruby investment there. And that's after Ruby recognized an entity-level asset impairment in the quarter resulting in lower depreciation. That brings us to adjusted EBITDA, which was $966 million, or 52% higher than Q1 2020.

Moving down below EBITDA. Interest expense was favorable by $52 million. They're lower LIBOR rates benefiting our interest rate swaps drove nice favorability as well as a lower debt balance and lower rates on our long-term debt. For the quarter, sustaining capital was favorable by $34 million, and that was driven by lower terminals and natural gas segment capex.

But all of that is timing, and we expect to spend more sustaining capital for the full year versus 2020. In other, we had some lower pension cash contributions versus a year ago. This year, we have a little bit more back-end loaded cash contributions to our pension plan versus more equally spread quarterly contributions last year. So our total DCF was $2.329 billion and was up $1.068 billion, or 85%.

And our DCF per share was $1.02, up $0.47 from last year's $0.55 per share. Moving on to the balance sheet. We ended the quarter with net debt to adjusted EBITDA of 3.9 times, down nicely from the 4.6 times at year-end. And we currently project to end 2021 at 3.9 times to 4.0 times, and that's consistent with the ranges that Kim walked through.

And that's largely a result of the largely nonrecurring winter storm benefits contributing to our EBITDA, but it also is a result of lower-than-budgeted debt balance due to the greater than budgeted cash flow. Our longer-term leverage target of 4.5 times has not changed. We also have a very favorable liquidity position. We ended the quarter with almost $1.4 billion of cash on hand and only have $500 million of consolidated debt maturing for the rest of the year.

So our net debt, which includes our cash on hand, ended the quarter at $30.7 billion, down $1.348 billion for the year -- from the year. And now, our net debt has declined by $12.1 billion or almost 30% since Q1 of 2015, as Rich mentioned, but is worth reiterating. So our quarter change to reconcile the change in debt of $1.35 billion for the quarter. We generated $2.329 billion in DCF.

We paid dividends of $600 million. We made $200 million of contributions to our growth projects as well as to JVs. We received $413 million from the NGPL sale, and we had $600 million of -- approximately $600 million of working capital uses, primarily interest expense payments, AR increases, and a rate case settlement on SFPP. That explains the majority of the net debt change and completes our first-quarter financial review.

So I'll turn it back to Steve.

Steve Kean -- Chief Executive Officer

All right. Thank you. [Operator instructions] Michelle?

Questions & Answers:


Operator

Thank you, sir. [Operator instructions] Our first question comes from Jeremy Tonet with J.P. Morgan. You may go ahead, sir.

Jeremy Tonet -- J.P. Morgan -- Analyst

Hi, good afternoon.

Steve Kean -- Chief Executive Officer

Good afternoon.

Jeremy Tonet -- J.P. Morgan -- Analyst

Just wanted to start with the storm here and kind of the ramifications coming out. And have you been paid, I guess, for everything that you're expecting to get? And you talked about, I guess, the value of your assets being more clear to the market and wondering what -- if you could, you know, quantify that in any sense more, what, you know, recontracting might look like? What type of uplift there could be for the business?

Steve Kean -- Chief Executive Officer

Sure. So most everybody paid in the normal course. It was a pretty big settlement process, as you might imagine, given the numbers involved. But pretty much everybody paid in the normal course.

As Kim mentioned, we do have some disputes, and I'd say mostly unfounded, but we've got some disputes. But most everyone paid in the normal course and anything that we think we need to reflect in a reserve or otherwise is reflected in the numbers that Kim gave you. In terms of the ramifications longer term, I think we still are in early days. But we have had very specific conversations with specific customers about enhancements we could make to our system to make them firm customers of ours.

And some of those enhancements -- the enhancements would require some capital. You know, it's a bit early to really call that. As I said, it will take some time to get that ramped up. I mean I would say it's possible in the triple-digit millions kind of level.

But most of the projects will kind of be singles and doubles, you know, enforcing or upgrading a lateral or increasing compression at a particular location and other sort of upgrades like that. So Tom, is there anything else that you would add in terms of color on that?

Tom Martin -- President, CO2 & President, Energy Transition Ventures

The only thing I would add is just I think we'll see a potential uplift in our existing storage and transportation capacity values, as well. Again, early days, hard to quantify, but I think we'll see some uplift there as well.

Jeremy Tonet -- J.P. Morgan -- Analyst

Got it. That's very helpful. And then just one more, if I could. On the Biden infrastructure plan, it's very early stages here and how they might form eventually.

But just wondering how might that impact KMI's new energy transition ambitions here. Specifically, do you see enough tax credit support to advance initiatives around carbon capture, utilization storage, or anything else on that side?

Steve Kean -- Chief Executive Officer

Yes. So there was some finalization of 45Q regs that happened early in the year, and those have pushed certain CO2 sources into economic territory here, and those are things like ethanol plants, gas processing facilities, and -- that have a high CO2 content in the stream. And so we're looking at those kinds of things. We do believe -- it is early days, as you said, on the Biden plan, and we'll see how that and other actions the administration takes play out.

But we do believe that part of the answer here to where the administration wants to go is going to be carbon capture and sequestration. We sequester carbon today, as you know. And we're looking at the capture part of that opportunity. And we've got the biggest network of CO2 pipelines in the country.

And so we're in a good position for that. But I think there are -- there's a lot more to come there.

Jeremy Tonet -- J.P. Morgan -- Analyst

Got it. I'll stop there. Thank you.

Operator

And our next question comes from Shneur Gershuni from UBS. You may go ahead, sir.

Shneur Gershuni -- UBS -- Analyst

Hi, good afternoon, everyone. Great to see those results today. You know, I just wanted to follow up on the last question on the Energy Ventures Group that Anthony, I guess, is leading now. I was wondering if you can help us frame the expectations of how we should be thinking about it.

Is the group there to try and source singles and doubles, as you like to say, in terms of trying to find capture customers for carbon capture, for the renewable diesel projects? Like is the idea to build a backlog of, let's say, $1 billion worth of capital consisting of eight to 10 projects? Or is it more to go out and hunt for bigger projects maybe with JV partners and so forth? I'm just kind of wondering if you could help frame the expectations or how you've charged that group to proceed.

Steve Kean -- Chief Executive Officer

Yeah. So I'll reiterate something I said. There are really two buckets to think about in terms of these energy transition opportunities. There's a bucket of things that we are already doing in our business that fit.

And so we leave those in our business units. And I'll use as an example that, Shneur, we have. John Schlosser, in his business, he deals with biofuels and renewable diesel today, as does Dax Sanders in the products business dealing with those. We think we're working on projects there, too.

Tom Martin and his team -- and Tom and his team really just -- they did an extraordinary job during the storm. The way their team worked, the integration between scheduling and commercial and operations and gas control was just stellar. But part of what they're doing is out marketing responsibly sourced gas and things like that as well as backup for renewable generation as it increases in penetration. The Energy Transition Ventures group is really more focused on things that we don't do today or are not immediate extensions of our business.

Carbon capture is not a part of our business today. That's something that goes there. Renewable natural gas is something that they're looking at. Look, it's hard to quantify that opportunity set for you right now.

It is a big opportunity set. But in terms of what we're able to ultimately transact on or expect, we're not saying, "Hey, go find $1 billion." We're saying, "Hey, go find good deals and deals that meet our return criteria and things that we can confidently operate and execute on." And so that's what they're doing. And even though it's early, I mean, they've got some specific things that they're looking at and working on.

Shneur Gershuni -- UBS -- Analyst

OK. Great. I appreciate the color there and look forward to future updates on it. Maybe as a follow-up question, in your prepared remarks and part of your response to Jeremy, you had mentioned the potential for the business.

And maybe there's some capital but unlikely to happen this year, certainly in any size. And so when I think about the 1Q results, which clearly, you haven't expected when you sort of set the budget out for this year, does this give you some more confidence around the completion of the $450 million buyback target? I know you had said in your prepared remarks that it's opportunistic and so forth. But can you walk us through the decision-making process on the opportunistic -- your opportunistic framework if you're not really changing your capital budget at this point right now and you sort of have this excess cash that you weren't expecting initially? I'm just wondering if you can give us some color around the thought process.

Steve Kean -- Chief Executive Officer

Yes. So we have the capacity that we articulated at the beginning of the year. As you mentioned, we've done the NGPL sale, which after taking into account what we need to keep our balance sheet metrics in place, provide some additional capacity there. We have the events of Uri, and that provides additional capacity.

And then the offset -- partial offset, is some of the negatives or the headwinds that Kim pointed out when she went through her analysis for you, some of which go away when you get on the other side of pandemic recovery whenever you want to call that. Having said all that though, We're really in the same place that we've been in terms of communicating on these scenarios as we were in 2017, which is, we have capacity, but we're going to use it opportunistically. We're not going to set an amount out for you. We didn't include -- it didn't include actual buyback amounts in our budget.

We just pointed to capacity. We're going to do it opportunistically, and we're going to do it based on returns and base through our -- and compared to our alternative uses of capital. So I know everybody wants a lot more specificity than that, but we're not giving prices, we're not giving amounts, just like we haven't for the last four years. And that's still where we are.

But we do have the additional capacity as pointed out.

Shneur Gershuni -- UBS -- Analyst

It's fair to say that your capacity is larger today than it was when you set the budget out. Is that a fair takeaway?

Steve Kean -- Chief Executive Officer

That's absolutely fair.

Shneur Gershuni -- UBS -- Analyst

Perfect. Thank you very much, guys. Really appreciate the color today.

Operator

And thank you. Our next question comes from Keith Stanley with Wolfe Research. You may go ahead, sir.

Keith Stanley -- Wolfe Research -- Analyst

Thanks. Good afternoon. Going back to Winter Storm Uri, are there any proposals in the legislature you're watching that could impact requirements on your customers to buy from transport or other services, either on the power side or on the producer side? And any proposals or suggestions that you're pushing within the government?

Steve Kean -- Chief Executive Officer

Yeah. There are a number of things that we're watching, and I'll ask Dave Conover to weigh in on this too. I think the way we see things headed right now is there is a continued and determined focus on examining winterization and how we can all do better as an energy industry and make sure that something like this doesn't happen again. There's a very concerted and -- but I do think that a lot of that is likely to be resolved, not by legislation, but by direction given to specialized regulatory bodies and others to develop in more detail.

And we'll want to be participants in that, and we're going to want to show the benefit of what we can do. And we're also going to want to be constructive in relating how the gas and power industry can better communicate in this state going forward. All things that we're working on with our customers and have been working on with our customers already. Dave, anything you want to add to that?

Dave Conover

No. I think you've covered in terms of what the legislature is actively looking at, Steve. There is no strong push within the legislature for mandating or incentivizing firm transport contracts. And I don't think at this stage, given the deadline has passed for the introduction of bills, that it's likely that we'll see anything like that.

Steve Kean -- Chief Executive Officer

And in other news, I guess, the Texas House did pass a securitization bill that's now pending in the Senate that would be helpful in reducing price shock on retail customers' bills.

Keith Stanley -- Wolfe Research -- Analyst

OK. Great. On that last point, you mean just on retail customer bills, like some of the ones who are paying the market prices, not the ERCOT-specific default allocation?

Steve Kean -- Chief Executive Officer

Yeah. This is on the gas side, LDC.

Keith Stanley -- Wolfe Research -- Analyst

OK. Oh, got it. Got it. OK.

Great. Second question on asset sales. I'm just curious. So the NGPL sell-down, it seems like a unique situation with your -- with your partner.

How are you thinking about asset sales going forward? Is there more interest in pursuing opportunities? Do you see the potential to maybe have more opportunities to monetize assets as the energy sector recovers? Just any updated thoughts on how you're looking at selling assets.

Steve Kean -- Chief Executive Officer

You know, we continue to look for the right things to buy as well as the right things to sell. And when those things are at a price that is a premium to our multiple and we can continue as we are with NGPL, continue to get the benefit of that asset, albeit at a smaller ownership percentage, and continue to operate the asset, we just look for those regularly. And when the numbers work, they work. And so I don't have anything more specific.

That's been our approach to this, really, for several years now. We're looking on the purchase side, and we're looking on the sales side, and it's all about value.

Keith Stanley -- Wolfe Research -- Analyst

Great. Thank you.

Operator

Thank you. Our next question comes from Spiro Dounis with Credit Suisse. You may go ahead, sir.

Spiro Dounis -- Credit Suisse -- Analyst

Hey! Good afternoon, everybody. First question [Audio gap] on --

Steve Kean -- Chief Executive Officer

Spiro, you're cutting out a bit. You're cutting out a bit.

Spiro Dounis -- Credit Suisse -- Analyst

Sorry, guys. Is that better, hopefully? Let me know.

Steve Kean -- Chief Executive Officer

Yeah.

Spiro Dounis -- Credit Suisse -- Analyst

OK. Perfect. Hopefully, that stays. Just on responsibly sourced natural gas, something we're seeing a lot of international demand sort of increase on we're seeing.

A lot of the LNG companies now start to market that a little bit more. And I think, Kim, you mentioned, I think, about 47% of the gas going into those facilities goes through one of your pipelines. So just curious, how you can -- I just think -- and basically, playing the middle man between suppliers and the LNG companies in getting more of that RSG into the international markets?

Steve Kean -- Chief Executive Officer

OK. You cut out a little bit there at the end. So if we missed something, you follow up. But Tom, do you want to talk about how we're interacting with our LNG customers on this topic.

Tom Martin -- President, CO2 & President, Energy Transition Ventures

Sure, Steve. Yeah. I mean, actively engaged with our current LNG customers, certainly working with producers. And again, as you mentioned earlier, we're leveraging off our one future and ESG emission metrics that are very favorable to the market.

And so as we identify producers who are able and willing to be certified and, you know and are connected to our system, which given our connectivity, we have, I think, a lot of opportunities there. So I think it is early days. But I think given our footprint and the number of basins and producers that we do business with, as well as the LNG exposure that we have, I think there's some nice opportunities there.

Spiro Dounis -- Credit Suisse -- Analyst

Second question, just on the Haynesville. Hoping you guys could provide an update there on producer discussions? I know that was an area of optimism for you. And then as you're addressing that, just curious if you guys see any fiscal --

Steve Kean -- Chief Executive Officer

OK. You cut out after you got your question on the Haynesville out. You cut out.

Spiro Dounis -- Credit Suisse -- Analyst

Sorry. I'll try again. I apologize. Just wondering if you could provide an update on producer discussions there.

And to the extent you see any risk of pipeline bottlenecks emerging?

Steve Kean -- Chief Executive Officer

OK. Tom, do you want to take that as well?

Tom Martin -- President, CO2 & President, Energy Transition Ventures

Sure. Now as Kim mentioned earlier, I think we're expecting our volumes to increase on KinderHawk through the balance of the year based on business that we have done and are working with our producers there now. Certainly, as those volumes continue to grow and the basin grows, there will be some additional downstream issues that we'll need to work through. We've looked at some opportunities to be part of that solution and are still pursuing those, but nothing really at this point to speak to.

But I think the market has capability and capacity today, just as those volumes grow, there may be a need for additional downstream infrastructure as we go forward.

Spiro Dounis -- Credit Suisse -- Analyst

Got it. It's all I had. Thanks, guys.

Operator

Thank you. Our next question comes from Gabe Moreen with Mizuho. You may go ahead, sir.

Gabe Moreen -- Gabe Moreen -- Mizuho Securities

Hey, good afternoon, everyone. I just had a quick question. I think on the -- in the intrastates, you've talked about the uplift in value of the potential capex. I'm also just wondering, you've got a lot of interstate natural gas pipeline, too, in Texas.

Whether you see any upside there potentially on storage values or some of the capacity you've got on the interstate market for the winter storm?

Steve Kean -- Chief Executive Officer

Look, I think the opportunity is -- I'd focus because a lot of the -- we did well on our interstate network as well, but focused specifically on the intrastate. And yeah, the interest in our services is broader than just the Texas intrastates. I meant that as a comment about our whole network. Tom, do you have anything you want to specifically point out?

Tom Martin -- President, CO2 & President, Energy Transition Ventures

No, nothing specific, Steve, but you're absolutely right. I mean it is a broader -- a broader point to be made here, I mean, definitely an emphasis in Texas. But we are seeing interest from customers much broadly across the whole footprint.

Gabe Moreen -- Gabe Moreen -- Mizuho Securities

Thanks. And then, maybe if I can follow up just on the pipeline replacement in south Texas. Is that on the gathering side, the long-haul side? And I know your system is obviously very large, but any other areas you could see potential spend like that, I guess, occurring in the near to medium term?

Steve Kean -- Chief Executive Officer

Tom, I'll put it back to you again.

Tom Martin -- President, CO2 & President, Energy Transition Ventures

It's on one of our intrastate systems, not a gathering system. And no, I'm not aware of anything that would be at that consequence or that significance coming down the pipe.

Gabe Moreen -- Gabe Moreen -- Mizuho Securities

OK. Thank you.

Operator

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

Michael Blum -- Wells Fargo Securities -- Analyst

Thanks. Thanks for taking my question. I just wanted to clarify kind of a capital allocation question, I guess. If I look at the impact of leverage from this sort of extra profitable quarter, let's call it, once this quarter sort of rolls off after 12 months, it looks like your leverage would still be down around four and a half, maybe slightly lower than that on a trailing 12 months basis is.

So would you say you're kind of at your goal? I just want to make sure I'm looking at that correctly.

Steve Kean -- Chief Executive Officer

Kim?

Kim Dang -- President

Yes. I think if you take our budgeted EBITDA and then you apply the proceeds to the debt balance, I think that will take you to around 4.5 times. That's a reasonable calculation.

Michael Blum -- Wells Fargo Securities -- Analyst

Great. Thank you very much.

Operator

Our next question comes from Jean Ann Salisbury from Bernstein. You may go ahead.

Jean Ann Salisbury -- Sanford C. Bernstein -- Analyst

Hi. I had a question about the NGPL sales. Based on FERC's data, I think it was sold a little under a 12x EBITDA multiple, which seems a little light for what I would consider a pretty good gas pipeline. Is this a good reflection of where the gas pipeline asset market is? Or was there something specific about NGPL's maintenance capex or tax load that caused the multiple to be better than it looks?

Steve Kean -- Chief Executive Officer

Yeah. Those are the two additional considerations, which you said. There's a fair amount of sustaining capex associated with that system. And so you get a multiple that's a little over 13x when you take that off of the EBITDA.

And then also, yeah, it will be a cash taxpayer and we're a C-Corp owner, so you had a little bit of double -- two layers of taxation there. David Michels, anything you want to add to that?

David Michels -- Chief Financial Officer

No. But I think, Steve, just to point out that -- or underscore, you just said we haven't been -- this entity hasn't been a cash taxpayer. So because of the NOL balance that it had, but we'll become one here in the next year or so. So it's something that we haven't experienced, but is a consideration for 2022 and beyond.

Jean Ann Salisbury -- Sanford C. Bernstein -- Analyst

Got it. That's really helpful. That's all for me. Thank you.

Operator

Thank you. Our next question comes from Christine Cho from Barclays. You may go ahead.

Christine Cho -- Barclays -- Analyst

Hi. You've said, you know, it's too early to quantify your energy transition opportunity, but it is a big opportunity set. So curious, is this something that you would fund with your cash flow? Or could there be other accretive ways to do this, to fund it, just given all of the low-cost capital or even things like specs out there chasing these sorts of projects? And when we think about potential carbon capture projects, would you only be interested in leveraging your existing footprint? Or would you step outside that footprint?

Steve Kean -- Chief Executive Officer

OK. I'm going to ask Anthony to supplement this. But yes, we would evaluate having JV partners, evaluate some of the alternative sources of capital that are out and available and very interested in these kinds of investments and might provide a nice synergy with our operational capabilities. And so we will definitely explore those other things.

Anthony, do you want to supplement that?

Anthony Ashley -- Vice President and Treasurer

No, I think you covered it. I think everything is on the table for us.

Christine Cho -- Barclays -- Analyst

OK. And then, you know, as we think about M&A, How should we think about your willingness to step outside your existing footprint there? Energy transition stuff aside, gas LDCs are coming up for sale. And obviously, you're not an MLP anymore, which would have been an impediment to holding that kind of asset. But as the world and regulatory backdrop has changed, how do you think about downstream integration on the natural gas side?

Steve Kean -- Chief Executive Officer

Kim, would you like to answer that?

Kim Dang -- President

Sure. Look, I think that that would obviously be a step out for us on a natural gas distribution system. That's retail customers. We're in a wholesale market.

The returns there are very different. And so traditionally, what we have looked at is things that fit our existing strategy, and that would not -- that would not fit our existing strategy, and so that would definitely be a step out. So yeah, I mean, it's probably unlikely.

Christine Cho -- Barclays -- Analyst

Got it. Thank you.

Operator

Thank you. Our next question comes from Michael Lapides from Goldman Sachs. You may go ahead, sir.

Michael Lapides -- Goldman Sachs -- Analyst

Hey, a couple of just macro questions, and thank you for taking my question. First of all, when you talk to your producer customers, where do you think -- meaning which basins do you think there could be upside to what's in your 2021 plan? Where do you think there could be downside? Could you address that? And also just kind of talk about expectations for gas flows into Mexico and gas flows kind of into the far western U.S., meaning California mostly?

Kim Dang -- President

Well, you know, on the -- talking about upsides and downsides, I mean, I think we've tried to incorporate the upsides and downsides into the updated forecast that we gave you today. And so where we have some downside versus our budget is in the Eagle Ford, where there's just a lot of excess pipe capacity versus our budget. We have a little bit of downside in Haynesville, and that's just because the activity got started there a little bit later than we projected it in our budget. We have some upside, as I said, likely in the Bakken, likely in Altamont.

But again, all those upsides and downsides are taken into account in the guidance that we gave you today.

Michael Lapides -- Goldman Sachs -- Analyst

Got it. And thoughts in terms of gas flows into Mexico and into kind of Western U.S., especially California, just kind of trends during the year relative to, you know, kind of what you were thinking at fourth quarter and maybe even a little earlier than that.

Steve Kean -- Chief Executive Officer

Tom?

Tom Martin -- President, CO2 & President, Energy Transition Ventures

Yeah. I guess I would say the flows in New Mexico have been very resilient. I think the market overall is flowing over six Bcf a day consistently. And so we're certainly -- as Kim mentioned earlier, we're 55% to 56% of those flows.

And so definitely participating in that volumetric upside from a throughput perspective and expect that to continue going forward. As far as flows westbound to California, I don't really have any specific insight there other than from what we hear, there's expectations of warmer summer so that could have some additional volumes flowing to California, may be different than what we saw last year or certainly what we expected at the beginning of the year or late last year.

Michael Lapides -- Goldman Sachs -- Analyst

Got it. Thank you, guys. I'll follow up offline. Much appreciated.

Operator

Thank you. Timm Schneider from Citi. You may go ahead, sir.

Timm Schneider -- Citi -- Analyst

Hey, thank you. I had a question about the renewable natural gas comments you made. Just curious if you could kind of run us through what your RNG strategy would be? I mean, are you looking to develop RNG assets at this point and, you know, take some LCFS-related infrastructure risk and also in the RINs? Or how does that look like for you guys?

Steve Kean -- Chief Executive Officer

We are looking at renewable natural gas assets and opportunities. It's a little bit different from, obviously, our long-haul transmission business. And as you said, I mean it is -- there is a RINs and LCFS component to it. However, there's also, I think, ways to secure this and maybe nail it down a little bit as you see fleet owners that are looking at renewable natural gas as a source of CNG in their delivery fleets or in their transportation fleets, for example.

So there may be some ways to narrow the exposure there. But yeah, there's a lot of this -- so that part of it is kind of driven by customer commitments and people coming out with their plans for how they're going to reduce their own CO2 emissions or they're going to become more green in whatever way. And so there's that driver as well as, as you said, the LCFS and the RINs. And we've got more work to do, as everybody does, to make sure they understand the risks and opportunities presented by those.

But the opportunities look pretty good in this sector, both because of the subsidies, if you will, for the incentives as well as the commitments that people are making about how they're going to get green.

Timm Schneider -- Citi -- Analyst

Got it. And maybe a follow-up here. Can you remind us your refined products terminals on the assets? Can they handle biofuels or a portion of them?

Steve Kean -- Chief Executive Officer

They can. And I'll ask John Schlosser to talk about his and then Dax to talk about his. Go ahead, John.

John Schlosser -- Vice President, President-Terminals of the Kinder Morgan, Inc.

Sure. We handle it today, we're the largest handler of ethanol. We have the pricing point in Argo. We handle over 30 million barrels there.

We handle renewable diesel at our Lower River facilities and add many of our truck racks. And we handle biodiesel at all of our truck racks. So we're more than capable of doing that or we're more than capable of converting any of our existing infrastructure to renewable products as well.

Steve Kean -- Chief Executive Officer

OK. Dax?

Dax Sanders -- Executive Vice President and Chief Strategy Officer

Yeah. And on products, we do -- most all of our terminals are capable of and do handle ethanol and the majority of them handle and do biodiesel. And obviously, ones that can do biodiesel can do renewable diesel as well. And we do have a terminal, a first terminal that has -- a small terminal with renewable diesel capability, specifically in California coming into service here in the next couple of months.

Timm Schneider -- Citi -- Analyst

OK. Got it. Thank you. Appreciate it.

Operator

Thank you. Our next question comes from Tristan Richardson with Truist Securities.

Tristan Richardson -- Truist Securities -- Analyst

Hey, good evening. Thank you for all the transparency on the storm. It's a really great summary of the puts and takes. Just a quick follow-up on the ventures business.

I appreciate all your comments on carbon capture is a core competency and addressing the prospects for RNG. Does renewable power generation fall under the umbrella? Is that an area that could fall into this ventures initiative?

Steve Kean -- Chief Executive Officer

Yeah. And again, I'll call on Anthony. He's been looking at this -- all these opportunities. Anthony, you want to respond?

Anthony Ashley -- Vice President and Treasurer

Yeah. I mean I think we're at very early stage on that. But yes, we are going to be looking at renewable power opportunities. Obviously, we've got a large footprint.

We have quite a bit of the land. But we're pretty early stage in terms of getting our arms around the renewable power opportunities, but it is something we're looking at.

Tristan Richardson -- Truist Securities -- Analyst

Helpful. Thanks, Anthony. And then with respect to guidance versus budget, I think, Kim, you mentioned some of the smaller items, one of which was the $80 million related to refined product demand recovery. Is that exclusively in products? Or is that Jones Act? Or maybe kind of what's driving that smaller item that you called out?

Kim Dang -- President

Yeah. The $80 million is refined product demand versus budget across terminals and products pipelines and also the Jones Act tankers. So it's all three, if you will.

Tristan Richardson -- Truist Securities -- Analyst

Great. Very helpful. Thank you, guys, very much.

Operator

And at this time, I'm showing no further questions.

Steve Kean -- Chief Executive Officer

OK. Well, we'll conclude the call then. Thank you very much for the questions you've asked, and we appreciate your attendance. And have a good evening.

Goodbye.

Operator

[Operator signoff]

Duration: 61 minutes

Call participants:

Rich Kinder -- Executive Chairman

Steve Kean -- Chief Executive Officer

Kim Dang -- President

David Michels -- Chief Financial Officer

Jeremy Tonet -- J.P. Morgan -- Analyst

Tom Martin -- President, CO2 & President, Energy Transition Ventures

Shneur Gershuni -- UBS -- Analyst

Keith Stanley -- Wolfe Research -- Analyst

Dave Conover

Spiro Dounis -- Credit Suisse -- Analyst

Gabe Moreen -- Gabe Moreen -- Mizuho Securities

Michael Blum -- Wells Fargo Securities -- Analyst

Jean Ann Salisbury -- Sanford C. Bernstein -- Analyst

Christine Cho -- Barclays -- Analyst

Anthony Ashley -- Vice President and Treasurer

Michael Lapides -- Goldman Sachs -- Analyst

Timm Schneider -- Citi -- Analyst

John Schlosser -- Vice President, President-Terminals of the Kinder Morgan, Inc.

Dax Sanders -- Executive Vice President and Chief Strategy Officer

Tristan Richardson -- Truist Securities -- Analyst

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