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Good afternoon, and thank you for standing by, and welcome to the Quarterly Earnings Conference Call. Today’s call is being recorded. [Operator Instructions] Your lines are in a listen-only mode until the question-and-answer session of today’s conference. [Operator Instructions]
It’s 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.
Just 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 a $1.08 per share as we promised when we released our original outlook for 2021 back in December. 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. Put this in perspective, this is the fourth consecutive annual increase in our dividends 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. And we are 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 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.
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 will 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 storage assets were a huge help. We were on maximum withdrawal for days at several of our fields, also helpful where our investments in backup generators at key compressor stations on our system.
Another real key for us is 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, 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 system is that we have a purchase and sale business in Texas, supported by high deliverability storage assets. In contrast, our intrastate 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 are 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 intrastate as roughly 80% or so take-or-pay.
In February, supply and demand conditions cause 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, the supply and demand conditions causing prices to go up by more than a 100x, 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 a $180 at MMBtu to $400 versus $3 earlier in the same month.
What did 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 is 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 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 in 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 power – where power prices were headed, Jesse Arenivas and his team started looking at shedding load. So we shutdown 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 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 great. 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 are 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've repeated many times, our financial principles remain the same. First, maintain a strong balance sheet. Second, we maintained our capital discipline through our return criteria and 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 on 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 it’s 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. It's a good synergy between our ESG performance, our low methane emissions and our commercial opportunities.
We participated in first one of these transactions with Colorado Springs Utilities, which they announced in the first quarter, and we are working on another, as we speak. We believe the winners in our sector will have strong balance sheet, low cost operations that are reliable, safe and environmentally sound and the ability to get things done in difficult circumstances. We are proud of our team and our culture, and as always, we will be prepared to meet the challenges and opportunities to come.
With that, I will turn it over to Kim.
Okay. Thanks, Steve. First, I'm going to go through the business fundamentals for the quarter, and then I will talk at a very high level about our full-year forecast. And 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. 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 and 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 2020. LNG volumes were down from 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 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 2020. 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 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 budgeted.
Eagle Ford volumes were also down versus the fourth quarter and we expect that those will be down versus our budget. Now 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.
And our Products Pipelines segment, refined product 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 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%, but that's a big improvement from the fourth quarter when they were off 47% versus the fourth quarter of 2020. 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. The March volumes were up slightly versus 2020, and they were down about 6% versus 2019. Currently, we are 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 is 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 the demand for our Jones Act tankers.
However, as we have 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 tank 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 until later this year because the charter activity tends to lag underlying supply and demand fundamentals.
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 is down about $3.50 per barrel. However, compared to our budget, we are currently anticipating the oil volume, 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 are 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 segment was roughly [indiscernible] $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 impact 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 there are about 5% below plan for the balance of the year.
And with that, I'll turn it over to David Michels.
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 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 about $950 million, which explains most of the $975 million favorable in the item – 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. 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 favorable versus the $0.14 loss in the first quarter of 2020. On an adjusted earnings per share basis and 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 completing 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 re-contracting rates at Double H, partially offset by greater contributions from our transmix business. Our Terminal segment was down $30 million and that's a 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 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, and 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 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 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 entity level asset impairment in the quarter resulting in lower depreciation. That brings us to adjusted EBITDA, which was $966 million, a 52% higher than Q1 2020.
Moving down below EBITDA, interest expense was favorable by $52 million. Their 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. 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 3.9x down nicely from the 4.6x at year-end. And we current projected in 2021 at 3.9x to 4.0x and that's consistent with the ranges that Kim walked through. And that's largely resulted – largely non-recurring 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 4.5x 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, that it 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 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 rate case settlement on SFPP. That explains the majority of the net debt change, and completes our first quarter financial review.
So I will turn it back to Steve.
All right. Thank you. And so as usual, as a courtesy to everybody, we are going to limit the questions per person to one with one follow-up, and if you got more, get back in the queue and we will come back to you. Michelle?
Thank you, sir. [Operator Instructions] Our first question comes from Jeremy Tonet with JPMorgan. You may go ahead, sir.
Hi, good afternoon.
Good afternoon.
Just want to start with the storm here and kind of the ramification coming out. And have you been paid, I guess, for everything that you are 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 quantify that in any sense more what re-contracting might look like? What type of uplift there could be for the business?
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, 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. 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 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?
The only thing I would add is that, I think we'll see a potential uplift in our existing storage and transportation capacity values as well. Again, early days for the quantified that I think we'll see some uplift there as well.
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 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?
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's a lot more to come there.
Got it. I'll stop there. Thank you.
And 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 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 near to try and source singles and doubles as you like to say in terms of trying to find capture customers versus – for carbon-capture for the renewable diesel projects? Is the idea that to build a backlog of, let's say, $1 billion worth of capital consisting of each of that projects? Or is it more to go out and – 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.
Yes. So I'll reiterate something I said. There are really two buckets to think about in terms of these Energy Transition Ventures 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 there. Shneur, we have John Schlosser and 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 work and the integration between scheduling and commercial, 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 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 dollars.” We're saying, “Hey, go find good deals” and deals that meet our return criteria and things that we can constantly 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 are looking at and working on.
Okay. Great. Appreciate the color there and look forward to [indiscernible]. Maybe as a follow-up question, in your prepared remarks and in part of your response to Jeremy, you had mentioned the potential for good visits and maybe there was some capital blight unlikely to happen this year, certainly in any size. And so 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, but 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 then you sort of have this excess cash that you weren't expecting initially? And just wondering if you can give us some color around the thought process.
Yes. So we had 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 to provide some additional capacity there. We had 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 where 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, but we're going to use it opportunistically. We're not going to set an amount out for you. We didn't include it. 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 compared to our alternative uses of capital. So I know everybody wants a lot more specificity in that around given prices, not given 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.
It's fair to say that your capacity is larger today than it was when you set the budget out. Is that a perfect way?
That’s correct. That's absolutely.
Perfect. Thank you very much, guys. Really appreciate the color 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? And then any proposals or suggestions that you're pushing within government?
Yes. There are 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 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?
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.
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.
Okay. Great. On that last point, you mean just on retail customer bills like some of the ones who were paying the market prices not the ERCOT specific default allocation?
Yes. This is on the gas side LDCs.
Okay. Got it. Okay. Great. Second question on asset sales, I’m just curious, so the NGPL sell down, it seems like a unique situation with your partner. How are you thinking about asset sales going forward? Is there more interests 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 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, we're looking on the sales 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. Good afternoon, everybody. First question…
Spiro, you're cutting out a bit. You're cutting out a bit.
Hey, sorry guys. Is that better? Hopefully?
Yes.
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 increased on 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 – and basically playing the middleman between suppliers and the LNG companies and getting more of that RSG into the international markets?
Okay. You cut out a little bit there at the end. So if we miss something you follow-up. But Tom, do you want to talk about how we're interacting with our LNG customers on this topic?
Firstly, yes, I mean, actively engaged with our current LNG customers certainly working with producers. And again, as we’ve mentioned earlier, we're leveraging off our one feature 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 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 is some nice opportunities there.
Second question, just on the Haynesville. I hope you guys can 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…
Okay. You cut out – after you got your question on the Haynesville, you cut out.
Sorry. I'll try again. I apologize. I'm just wondering if you provide an update on producer discussions there and to the extent you see any risk of pipeline bottlenecks emerging.
Okay. Tom, do you want to take that as well?
Sure. 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, but nothing really at this point to speak to that. But I think the market has capability and capacity today just as those volumes grow, there maybe 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.
Good afternoon, everyone. I just had a quick question. I think on the intrastate, you talked about the outputs and value, the potential CapEx. I'm also just wondering, we've got a lot of intrastate natural gas pipeline here in Texas, whether you see any upside there potentially on storage values or some of the capacity you've got on the intrastate market [indiscernible] winter storm?
Look, I think the opportunities I focus because a lot of the – we did well on our interstate network as well, but focused specifically on the intrastate. And yes, the interest in our services is broader than just the Texas intrastate. I meant that as a comment about our whole network. Tom, do you have anything you want to specifically point out?
No. Nothing specific, Steve, but you're absolutely right. I mean that is 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.
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? 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?
Tom, I’ll put it back to you again.
It’s on one of our intrastate systems not a gathering system, and no I'm not aware of anything that would be of that consequence or significance coming down the pipe.
Okay. Thank you.
And our next question comes from Michael Blum with Wells Fargo.
Thanks. Thanks for taking my question. I just want to clarify kind of the 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 months basis. So would you say you're kind of at your goal? Just want to make sure I'm looking at that correctly?
Kim?
Yes. I think if you take either our budgeted EBITDA and then you apply the proceeds to the debt balances, I think that will take you to around 4.5x. 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 sales. Based on FERC data, I think it was sold a little under a 12x EBITDA multiple, which seems a little light or what I would consider a pretty good gas pipeline, it looks like a good reflection of where the gas pipeline at that market is. Or was there something specific about NGPLs maintenance CapEx or tax load that caused the multiple to be better than it looks?
Yes. 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, yes, it will be a cash tax payer 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?
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 an 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 it is a consideration for 2022 and beyond.
Okay. 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.
Hi. You said, it's too early to quantify your energy transition opportunity, but it is a big opportunity side. 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 SPACs 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?
Okay. 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 that 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?
No. I think you've covered it. And I think everything's on the table for us.
Okay. And 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 [indiscernible] are coming up for sale, and obviously you're not in 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?
Kim, would you like to answer that?
Sure. Look, I think that that would obviously be a step out for us on 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 was not – that would not fit our existing strategy, and so that would definitely be a step out. So, yes, I mean, it's probably unlikely, so.
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 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 most likely?
Well, on the – talking about upsides and downsides, I mean, I think we 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 a downside in Haynesville and that's just because the activity got started there a little bit later than what 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.
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 kind of what you are thinking in fourth quarter and maybe even a little earlier than that?
Tom?
Yes. I guess I would say the flows in the Mexico have been very resilient. I think the market evolves 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 don't really have any specific insight there other than from what we hear. There is expectation of a warmer summer. So that could have some additional volumes flowing to California maybe different than what we saw last year, certainly what we expected at the beginning of the year or late last year.
Got it. Thank you, guys. I will 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. I mean, are you looking to develop RNG assets at this point and take some of the LCFS related infrastructure risk and also on the REMS, 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, I mean, it is – there is REMS 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 maybe some ways to narrow the exposure there.
But yes, 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 REMS, 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.
Got it. And then 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 [indiscernible] facilities and add many of our Truck Rack, and we handle biodiesel at all of our Truck Rack. So we're more than capable of doing that. And we're more than capable of converting any of our existing infrastructure to renewable products as well.
Okay. Dax?
Yes. 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, one that can be biodiesel can do renewable diesel as well. And we do have a terminal – first terminal that has a small terminal with renewable diesel capabilities specifically in California coming into services 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. So 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 and is that an area that could fall into this ventures initiative?
Yes. And again, I'll call on Anthony. He's been looking at this – all these opportunities. Anthony, do you want to respond?
Yes. I mean, I think we're at very early stage on that. But yes, we’re going to be looking at renewable power opportunities. Obviously, we've got a large footprint, we have quite a bit of land. But we're at pretty early stage in terms of getting our arms around that renewable power opportunities, but it's something we're looking at.
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 an $80 million related to refined product demand recovery. Is that exclusively in products or is that Jones Act or maybe kind of what [indiscernible] smaller item that you called out?
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.
Great. Very helpful. Thank you guys very much.
And at this time, I'm showing no further questions.
Okay. Well, we'll conclude the call. And thank you very much for the questions you've asked and we appreciate your attendance and have a good evening. Good bye.
And thank you. This concludes today's conference call. You may go ahead and disconnect at this time.