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. Your lines are in a listen-only mode until the question and answer session of today's conference. At that time, you may press star followed by the number one to ask a question. Please unmute your phones and state your first and last name. My pleasure to turn the call over to Mr. Rich Kinder, Executive Chairman of Kinder Morgan. Sir, you may begin.
Okay. 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 two 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.
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.
With that, I'll turn it over to Steve Kean, our CEO.
Which is what drove our financial results in the quarter. 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. Starting with the performance during Winter Storm Uri, 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 had 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.
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. 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 100 times, 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 ranged from $180 an 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 and our financial results as largely non-recurring, 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 result 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, February's event reveals the value of storage and firm transport capacity. 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. 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 worked as designed, 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 Arenivas 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, 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.
Good flexibility to have in the power market in the state of Texas. 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. What will we do with the proceeds? Initially, of course, it's a reduction to our net debt. As we've 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. 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. 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. 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 using our gas transportation and storage services to support renewable power. We're also marketing our low methane emissions performance as responsibly produced and transported natural gas. It'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. 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. As always, we'll be prepared to meet the challenges and opportunities to come. With that, I'll turn it over to Kim.
Okay. Thanks, Steve. I'm going to go through the business fundamentals for the quarter, 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 2020. 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 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 2020, 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 2020. Our share of Mexico's deliveries in the first quarter ran about 55%. Deliveries to power plants were down due to higher natural gas prices. Deliveries to LDCs were up due to colder weather.
On our natural gas gathering volumes, they were down about 25% in the quarter compared to the first quarter of 2020. For gathering volumes, I think the more informative comparison is the sequential quarter. 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. 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 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 Pipelines segment, refined products volumes were down about 10% for the quarter versus the first quarter of 2020, that's just the result of the continued pandemic impact. Gasoline volumes were up 6% versus the first quarter of 2020. 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%, that's a big improvement from the fourth quarter when they were off 47% versus the fourth quarter of 2020. 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. As we've mentioned in prior quarters, the impact of reduced petroleum product demand on our tankage is more muted than in our products pipelines, 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's about 98%. On the tankers, we have a number of ships that have contract expirations this year. 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. That may take until 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. Compared to our budget, we're currently anticipating the oil volumes, CO2 volumes, and net realized oil price will exceed budget for the year. 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-$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, horseshoes and hand grenades, $1 billion, leaving a variance, again, very roughly, of $200 million-$350 million versus our budget. I know $200 million doesn't add up perfectly, 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 pipes. 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.
The sale of our 12.5% interest on NGPL creates a negative variance versus our budget. The difference in the low and the high end of the guidance range primarily relates to assumptions on petroleum products volumes, Jones Act tanker renewals, natural gas G&P 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. With that, I'll turn it over to David Michels.
All right. Thank you, Kim. 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. 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 a partial offset in our cost of sales with an increase of $1.3 billion there. Our gross margin was up $759 million, mostly driven by our strong performance during Winter Storm Uri. Our O&M costs declined as a result of the CO2 segment's 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 line item called gain/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. 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. That appears in the other net line item. 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, 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, EBITDA and distributable cash flow performance. Our natural gas segment was up $915 million for the quarter, mostly explained as well as increased revenue on our Tennessee Gas Pipeline, both as a result of the February Winter Storm performance beginning of the year. These were all partially offset by lower contributions from our FEP pipeline resulting from the 2020 contract rollovers. Our 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 Double H, partially offset by greater contributions from our Transmix business.
Our terminal segment was down $30 million, that's lower 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 petcoke facilities, these were all somewhat offset by 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 that was partially offset by lower crude and CO2 volumes versus Q1 2020 and lower realized crude prices versus Q1 2020. Our G&A and corporate charges were higher by $8 million, there we had lower capitalized overhead expenses, partially offset by our organizational efficiency savings.
At JV depreciation, we had less JV DD&A from our Ruby investment there. 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. There, 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. That was driven by lower terminals and natural gas segment CapEx. All of that is timing. 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. 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. We currently project to end 2021 at 3.9 to 4.0 times, and that's consistent with the ranges that Kim walked through, and that's largely a result of the largely non-recurring winter storm benefits contributing to our EBITDA. 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. Our net debt, which includes our cash on hand, ended the quarter at $30.7 billion, down $1.348 billion 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. 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.
We had 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. I'll turn it back to Steve.
All right, thank you. As usual, as a courtesy to everybody, we're going to limit the questions per person to one with one follow-up. If you've got more, get back in the queue, and we will come back to you. Michelle.
Thank you, sir. At this time, if you do have any questions or comments, you may press star one. Please unmute your phones and state your first and last name when prompted. Our first question comes from Jeremy Tonet with JP Morgan. You may go ahead, sir.
Hi, good afternoon.
Good afternoon.
Just wanted to start with the storm here and kind of the ramifications coming out. Have you been paid, I guess, for everything that you're expecting to get? You talked about, I guess, the value of your assets being more clear to the market and wondering if you could quantify that in any sense more or what recontracting might look like, what type of uplift there could be for the business?
Sure. Most everybody paid in the normal course. It was a pretty big settlement process, as you might imagine, given the numbers involved. 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. Some of those enhancements would require some capital. It's a bit early to really call that.
As I said, it will take some time to get that ramped up. I would say it's possible in the triple-digit millions kind of level. 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. Tom, is there anything else that you would add in terms of color on that?
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.
Got it.
Very good point.
That's very helpful. Just one more, if I could, on the Biden infrastructure plan. It's very early stages here in how that 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?
Yeah. There was some finalization of 45Q regs that happened early in the year. Those have pushed certain CO2 sources into economic territory here. Those are things like ethanol plants, gas processing facilities that have a high CO2 content in the stream. We're looking at those kinds of things. It is early days, as you said, on the Biden plan. We'll see how that and other actions the administration takes play out. 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. We're looking at the capture part of that opportunity. We've got the biggest network of CO2 pipelines in the country. We're in a good position for that. But, I think there's a lot more to come there.
Got it. I'll stop there. Thank you.
Our next question comes from Shneur Gershuni from UBS. You may go ahead, sir.
Hi, good afternoon, everyone. Great to see those results today. I just wanted to follow up on the last question on the Energy Transition Ventures 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? 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 was just kind of wondering if you could help frame the expectations or how you've charged that group to proceed.
Yeah. 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. We lead those in our business units. I'll use as an example there, 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 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.
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 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.
That's what they're doing, and even though it's early, I mean, they've got some specific things that they are looking at and working on.
Okay, 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 good business and maybe there was some capital but unlikely to happen this year, certainly in any size. When I think about the 1Q results, which clearly you hadn'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, can you walk us through the decision-making process on the 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?
Yeah. 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. The 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 this scenario as we were in 2017, which is we have capacity. We're going to use it opportunistically. We're not going to set an amount out for you.
We 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 compared to our alternative uses of capital. 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. We do have the additional capacity, as pointed out.
It's fair to say that your capacity is larger today than it was when you set the budget out. Is that a fair take?
That's fair. That's absolutely fair.
Perfect. Thank you very much, guys. Really appreciate the call today.
Thank you. Our next question comes from Keith Stanley with Wolfe Research. You may go ahead, sir.
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? Any proposals or suggestions that you're pushing within the government?
Yeah. There are a number of things that we're watching. I'll ask Dave Conover over 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. 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. We'll want to be participants in that, and we're going to want to show the benefit of what we can do. 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?
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. 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.
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.
Okay. 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?
Yeah, this is on the gas side. LDCs.
Okay. Oh, got it. Great. Second question on asset sales. I'm just curious. The NGPL sell down, it seemed like a unique situation 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.
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. 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 sale side, and it's all about value.
Great. Thank you.
Thank you. Our next question comes from Spiro Dounis with Credit Suisse. You may go ahead, sir.
Hey, afternoon, everybody.
Spiro, you're cutting out a bit.
Hey. Sorry, guys. That better, hopefully?
Yeah.
Let me know. Okay, 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. I think, Kim, you mentioned, I think about 47% of the gas going into those facilities goes through one of your pipelines. Just curious how you guys think basically playing the middleman between suppliers and the LNG companies in getting more of that RSG into the international markets?
Okay. You cut out a little bit there at the end. If we missed something, you follow up. Tom, do you want to talk about how we're interacting with our LNG customers on this topic?
Sure, Steve. Yeah, actively engaged with our current LNG customers, certainly working with producers. Again, as you mentioned earlier, we're leveraging off our ONE Future in ESG emission metrics that are very favorable to the market. As we identify producers who are able and willing to be certified and are connected to our system, which given our connectivity, we have, I think, a lot of opportunities there. 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.
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. As you're addressing that, just curious if you guys see any risk of.
Okay, you cut out after you got your question on the Haynesville out, you cut out.
Sorry. I'll try again. I apologize. I just wonder if you could provide an update on producer discussions there and to the extent you see any risk of pipeline bottlenecks emerging?
Okay. Tom, you want to take that as well?
Sure. Yeah, 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'll 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. Nothing really at this point to speak to. I think the market has capability and capacity today. Just as those volumes grow, there may be need for additional downstream infrastructure as we go forward.
Got it. That's all I had. Thanks, guys.
Thank you. Our next question comes from Gabe Moreen with Mizuho. You may go ahead, sir.
Hey, good afternoon, everyone. I just had a quick question. I think on the intrastates, you talked about the outputs and value, the potential CapEx. I'm also just wondering, you've got a lot of interstate natural gas pipelines here 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.
Look, I focus because we did well on our interstate network as well, but focused specifically on the intrastates. 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? Nothing specific, Steve, but you're absolutely right. I mean, it is a broader point to be made here. I mean, it's definitely an emphasis in Texas, but we are seeing interest from customers much broadly across the whole footprint.
Thanks. Maybe if I can follow up just on the pipeline replacement in South Texas. Is that on the gathering side, the long-haul side? I know your system is obviously very large, any other areas you could see potential spend like that, I guess, occurring in the near to medium term?
Tom, I'll put it back to you again.
It's on one of our intrastate systems, not a gathering system. No, I'm not aware of anything that would be of that consequence or that significance coming down the pipe.
Okay. Thank you.
Our next question comes from Michael Blum with Wells Fargo.
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 4.5, maybe slightly lower than that on a trailing 12-month basis. Would you say you're kind of at your goal? Just want to make sure I'm looking at that correctly.
Kim?
I think if you take our budgeted EBITDA, and then you apply the proceeds to the debt balance, I think that'll take you to around four and a half times. That's a reasonable calculation.
Great. Thank you very much.
Our next question comes from Jean Ann Salisbury from Bernstein. You may go ahead.
Hi. I had a question about the NGPL sale. Based on Spark 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?
Yeah, those are the two additional considerations, what you said. There's a fair amount of sustaining CapEx associated with that system. So you get a multiple that's a little over 13x when you take that off of the EBITDA.
Also, it will be a cash taxpayer and we're a C-corp owner, you had a little bit of double two layers of taxation there. David Michels, anything you want to add to that?
I think, Steve, just to point out that, or underscore what you just said, this entity hasn't been a cash taxpayer because of an NOL balance that it had, but will become one here in the next year or so. It's something that we haven't experienced but is a consideration for 2022 and beyond.
Right. That's really helpful. That's all for me. Thank you.
Thank you. Our next question comes from Christine Cho from Barclays. You may go ahead.
I said it's too early to quantify your energy transition opportunity, but it is a big opportunity set. Curious, is this something that you would fund with your cash flow, or could there be other creative ways to do this, to fund it, just given all of the low-cost capital or even things like SPACs out there chasing these sorts of projects? 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?
Okay. I'm going to ask Anthony to supplement this, but yeah, 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. We will definitely explore those other things. Anthony, do you want to supplement that?
No, I think you covered it. I think everything's on the table for us.
Okay. Then, 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. As the world and regulatory backdrop has changed, how do you think about downstream integration on the natural gas side?
Kim, would you like to answer that?
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. Traditionally, what we have looked at is things that fit our existing strategy, and that would not fit our existing strategy. That would definitely be a step out.
Got it.
Yeah, it's probably unlikely.
Thank you.
Thank you. Our next question comes from Michael Lapides from Goldman Sachs. You may go ahead, sir.
Hey, 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 upsides of what's in your 2021 plan? Where do you think there could be downsides? Could you address that? Also kind of talk about expectations for gas flows into Mexico, and gas flows into the far western U.S., meaning California mostly.
Well, talking about upsides and downsides, I think we've tried to incorporate the upsides and downsides into the updated forecast that we gave you today. 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 a 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. Again, all those upsides and downsides are taken into account in the guidance that we gave you today.
Got it. Thoughts in terms of gas flows into Mexico and into western U.S., especially California, just trends during the year relative to what you were thinking at fourth quarter and maybe even a little earlier than that?
Tom?
Yeah, I guess I would say the flows into Mexico have been very resilient. I think the market overall is flowing over 6 Bcf a day consistently. We're certainly, as Kim mentioned earlier, we're 55%-56% of those flows. 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 a warmer summer, so that could have some additional volumes flowing to California, maybe different than what we saw last year, or certainly what we expected at the beginning of the year or late last year.
Got it. Thank you, guys. I'll follow up offline. Much appreciated.
Thank you. Timm Schneider from Citi. You may go ahead, sir.
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. Are you looking to develop RNG assets at this point and take some LCFS related infrastructure risk and also on the RINS, or how does that look like for you guys?
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, there is a RINS and LCFS component to it. 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. There may be some ways to narrow the exposure there. 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.
There's that driver as well as you said, the LCFS and the RINS. We've got more work to do, as everybody does, to make sure they understand the risks and opportunities presented by those. The opportunities look pretty good in this sector, both because of the subsidies, if you will, or the incentives, as well as the commitments that people are making about how they're going to get green.
Got it. Maybe a follow-up here. Can you remind us, your refined products terminals, the assets, can they handle biofuels or a portion of them?
They can, and I'll ask John Schlosser to talk about his and then Dax to talk about his. Go ahead, John.
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 at many of our truck racks, we handle biodiesel at all of our truck racks. We're more than capable of doing that, we're more than capable of converting any of our existing infrastructure to renewable products as well.
Okay, Dax.
Yeah, and on p roducts, we do. Most all of our terminals are capable of and do handle ethanol, and the majority of them handle and do biodiesel. Obviously, ones that can do biodiesel can do renewable diesel as well. We do have a terminal, our first terminal that has a small terminal with renewable diesel capability, specifically in California, coming into service here in the next couple of months.
Okay, got it. Thank you. Appreciate it.
Thank you. Our next question comes from Tristan Richardson with Truist Securities.
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. Appreciate all your comments on carbon capture as a core competency and addressing the prospects for RNG. Does vanilla power generation fall under the umbrella? Is that an area that could fall into this Ventures initiative?
Yeah. Again, I'll call on Anthony. He's been looking at all these opportunities. Anthony, you want to respond?
Yeah. I think we're at a very early stage on that. 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. We're pretty early stage in terms of getting our arms around the renewable power opportunities. It is something we're looking at.
Helpful. Thanks, Anthony. With respect to guidance versus budget, I think Kim, you mentioned some of the smaller items, one of which was an $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?
The $80 million is refined product demand versus budget across terminals and product pipelines and also the Jones Act tankers. It's all three, if you will.
Great. Very helpful. Thank you guys very much.
At this time, I'm showing no further questions.
Okay. 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.
Thank you. This concludes today's conference call. You may go ahead and disconnect at this time.