Kinder Morgan, Inc. (KMI) Q4 2021 Earnings Report, Transcript and Summary

Welcome to the Quarterly Earnings Conference Call. Today’s call is being recorded. If you have any objectives, you may disconnect at this time. All lines have been placed in a listen-only mode until the question-and-answer session of today’s call. [Operator Instructions] I would now like to turn the call over to Mr. Rich Kinder, Executive Chairman. Thank you, sir. You may begin.

Okay. Thank you, Missy. Before we begin, I’d like to remind you that, as usual, 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. Now to kick this off, the beginning of a New Year, I believe is a good time to take stock of where KMI stands as an investment opportunity for its present and potential shareholders. Whether you look at the results for the fourth quarter of 2021, the full year ‘21 or our budget outlook for 2022, which we released in December, it’s apparent that this company produces substantial cash flow under almost any circumstances. In my judgment, this is the bedrock for valuation, because it gives us the ability to fund all our capital needs out of recurring cash flow. As I’ve stressed so many times, we can use that cash to maintain a solid balance sheet, invest in selected high-return expansion CapEx opportunities, pay a very rewarding and growing dividend and buyback shares on an opportunistic basis. But I believe there is more of the story than that. While we demonstrated by assets that we acquired during 2021 that we are participating meaningfully in the coming energy transition, it’s also become apparent, particularly over the last several months that this transition will be longer and more complicated than many originally expected. In short, there is a long runway for fossil fuels and especially natural gas. Investing in the energy sector has been very lucrative recently with the energy sector, the best performing sector of the S&P 500 during 2021. We expect that favorable view to continue in 2022 and the year has started out that way. Within the energy segment, I would argue that midstream pipelines are a good way of playing this trend. They generally have less volatility and less commodity exposure than upstream and most have solid and growing cash flow underpinned by contracts to a large extent with their shippers. We believe KMI is a particularly good fit for investors. We are living within our cash flow. We paid down over $12 billion in debt since 2016, and 2022 marks the fifth consecutive year we have increased our dividend, growing it over those years from $0.50 per share to $1.11 per share. In addition to returning value to our shareholders through our dividend, our Board has approved a substantial opportunistic buyback program, which we have the financial firepower to execute on during this year if we so choose. Finally, this is a company run by shareholders, for shareholders with our Board and management owning about 13% of the company. I hope and trust you will keep these factors I have mentioned in mind when making investment decisions about our stock over the coming year, more to come on all these subjects at our Investor Day Conference next Wednesday. And with that, I will turn it over to Steve.

Okay. Thank you. I will give you a brief look back on what we accomplished in 2021 and touch on capital allocation principles before turning it over to Kim and David and then we will take your questions. As is usually the case on this call, which comes the week before our comprehensive investor conference, we will defer to next week some of the more in-depth and detailed questions on the 2022 budget and the outlook and business opportunities. As to 2021, we wrapped up a record year financially. Much of that was due to our outperformance in Q1 as a result of the strong performance of our assets and our people during winter storm Uri. Putting Uri aside, we were running a bit shy at plan in the full year guidance that we were giving you through our quarterly updates. But by the end of the year, we closed the gap and met our EBITDA target, even excluding Uri, but including the benefit of our Stagecoach acquisition. We also set ourselves up well for the future, getting off to a fast start in our Energy Transition Ventures business with the acquisition of Kinetrex renewable natural gas business and adding to our already largest in the industry gas storage asset portfolio with the acquisition of Stagecoach. Both of those acquisitions are outperforming our acquisition models. Third, as we will cover in detail at next week’s conference, our future looks strong. Our assets will be needed to meet growing energy needs around the world for a long time to come. And over the long-term, we can use our assets to store and transport the energy commodities of tomorrow. And we have opportunities, as we have shown you, to enter into new energy transition opportunities at attractive returns. We are entering 2022 with a solid balance sheet, including the capacity to repurchase shares with well-positioned existing businesses and with an attractive set of capital projects. Our approach to capital allocation remains principled and consistent. First, take care of the balance sheet, which we have with our budget showing net debt to EBITDA of 4.3x, then invest in attractive return projects and businesses we know well at returns that are well in excess of our cost of capital. Our discretionary capital needs are running more in the $1 billion to $2 billion range annually and at $1.3 billion, we are at the lower end of that range in our 2022 budget, not at the $2 billion to $3 billion that we experienced in the last decade. We are also generally seeing or we are continuing to tilt, I guess, I would say, toward generally smaller sized projects that are built off of our existing network and we can do those at very attractive returns and with less execution risk. The final step in the process is return the excess cash to shareholders in the form of an increasing and well-covered dividend, that’s $1.11 for 2022 and in the form of share repurchases. As we said in our 2022 budget guidance release in December, we expect to have $750 million of balance sheet capacity for attractive opportunities, including opportunistic share repurchases. Given the current lower capital spending environment, we are now experiencing we would expect to have the capacity to repurchase shares even if we add some investment opportunities as the year proceeds in the form of additional projects, et cetera. As we have always emphasized when discussing repurchases, we will be opportunistic, not programmatic. We believe the winners in our sector will have strong balance sheets, invest wisely in new opportunities to add to the value of the firm, have low cost operations that are 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 evolve to meet the challenges and opportunities in the years ahead. With that, I’ll turn it over to Kim.

Okay. Thanks, Dave. Alright. Starting with our natural gas business unit for the quarter, transport volumes were down 3% or approximately 1.1 million dekatherms per day versus the fourth quarter 2020 that was driven primarily by continued decline in Rockies production, the pipeline outage on EPNG and FEP contract expirations, which were offset somewhat by increased LNG deliveries and PHP and service volumes. Physical deliveries to LNG facilities off of our pipeline averaged about 5 million dekatherms per day, that’s a 33% increase versus the fourth quarter of ‘20. Our market share of LNG deliveries remains around 50%. Exports to Mexico were down in the quarter when compared to the fourth quarter of 2020 as a result of third-party pipeline capacity recently added to the market. Overall, deliveries to power plants were up slightly, at least in part, partially driven by coal supply issues, while LDC deliveries were down as a result of lower heating degree days. Our natural gas gathering volumes were up 6% in the quarter. For gathering volumes though, I think the more informative comparison is the sequential quarter. So compared with the third quarter of this year, volumes were up 7%, with a big increase in Haynesville volumes, which were up 19% and Bakken volumes, which were up 9%. Volumes in the Eagle Ford increased slightly. In our products pipeline segment, refined product volumes were up 9% for the quarter versus the fourth quarter of 2020. Compared to pre-pandemic levels using the fourth quarter ‘19 as a reference point, road fuel, ethylene and diesel were down about 2% and jet was down 22%. In Q3, road fuels were down 3% versus the pre-pandemic number. So, we did see a slight improvement. Crude and condensate volumes were down 3% in the quarter versus the fourth quarter of ‘20. Sequential volumes were down approximately 1%, with a reduction in Eagle Ford volumes, partially offset by an increase in the Bakken. If you strip out HH pipeline volumes from our Bakken numbers and that pipeline is impacted by alternative egress options and you look only at our Bakken gathering volumes, they were up 7%. In our Terminals business segment, our liquids utilization percentage remains high at 93%. If you exclude tanks out of service for required inspection, utilization is approximately 97%. Our rack business, which serves consumer domestic demand, is up nicely versus Q4 of ‘20 and also up versus pre-pandemic levels. Our hub facilities, primarily Houston and New York, are driven more by refinery runs, international trade and blending dynamics are also up versus the Q4 of ‘20. But those terminals are still down versus pre-pandemic levels. We have seen some green shoots in our marine tanker business, with all 16 vessels currently sailing under firm contracts. On the bulk side volumes increased by 8% and that was driven by coal and bulk volumes are up 2% versus the fourth quarter of ‘19. In our CO2 segment, crude volumes were down 4%, CO2 volumes were down 13% and NGL volumes were down 1%. On price, we didn’t see the benefit of increasing prices on our weighted average crude price due to the hedges we put in place in prior periods when prices were lower. However, we did benefit from higher prices on our NGL and CO2 volumes. For the year versus our budget, crude volumes and price were better than budget, CO2 volumes and price were better than budget, and NGL price was better than budget. So, a good year for our CO2 segment relative to our expectations and CO2 volumes have started the year above our ‘22 plan. As Steve said, we had a very nice year. We ended approximately $1 billion better on DCF and $1.1 billion better than our EBITDA with respect to our EBITDA budget. And most of that was due to the outperformance attributable to winter storm or all of it was due to the outperformance attributable to winter storm Uri. If you strip out the impact of the storm and you strip out roughly $60 million in pipe replacement projects that we decided to do during the year that impacts sustaining CapEx, we ended the year on plan for both EBITDA and DCF. And with that, I will turn it over to David Michels.

Alright. Thanks, Kim. So for the fourth quarter 2021, we are declaring a dividend of $0.27 per share, which brings us to $1.08 of declared dividends for full year 2021 and that’s up 3% from the dividends declared for 2020. During the quarter, we generated revenue of $4.4 billion, up $1.3 billion from the fourth quarter of 2020. That’s largely up due to higher commodity prices, which also increased our cost of sales in the businesses where we purchase and sell commodities. Revenue less cost of sales or gross margin was up $107 million. We generated net income to KMI of $637 million, up 5% from the fourth quarter of 2020. Adjusted net income, which excludes certain items, was up – was $609 million, up 1% from last year and adjusted EPS was $0.27 in line with last year. Moving on to our segment performance versus Q4 of 2020, our natural gas segment was up driven by contributions from Stagecoach and PHP, partially offset by lower contributions from FEP where we have had contract expirations NGPL because of our partial interest sale and EPNG due to lower usage and park and loan activity. Products segment was up due to refined products volume and favorable price impacts. Our terminals segment was down driven by weakness in the Jones Act tanker business and an impact from a gain on sale of an equity interest in 2020. CO2 was down, as favorable NGL and CO2 prices were more than offset by lower CO2 and oil volumes, the oil volumes were above plan. G&A and corporate charges were higher due to larger benefit costs as well as cost savings we achieved in 2020 driven by lower activity due to the pandemic. Our JV DD&A was lower primarily due to lower contributions from the Ruby pipeline. And our sustaining capital was higher versus the fourth quarter of last year that was higher in natural gas terminals and products and that is a fairly large increase, but we were expecting the vast majority of it has – much of the spend from early in the year was pushed into later in the year. For the full year versus plan on sustaining capital, we are $72 million higher and roughly $60 million of that is due to the pipe replacement project that Kim mentioned. The total DCF of $1.093 billion or $0.48 per share is down $0.07 versus last year’s quarter and that’s mostly due to the sustaining capital. On the balance sheet, we ended the year with $31.2 billion of net debt with a net debt to adjusted EBITDA ratio of 3.9x, down from 4.6x at year end 2020. Removing the non-recurring Uri contribution to EBITDA, that ratio at the end of 2021 would be 4.6x, which is in line with the budget for the year. Our net debt declined $404 million from the third quarter and it declined $828 million from the end of 2020. To reconcile the change for the quarter, we generated $1.093 billion in DCF. We spent or paid out $600 million in dividends. We spent $150 million in growth CapEx, JV contributions and acquisitions and we had a working capital source of $70 million and that explains the majority of the change for the quarter. For the year, we generated $5.460 billion of DCF. We paid out dividends of $2.4 billion. We spent $570 million on growth CapEx and JV contributions. We spent $1.053 billion on the Stagecoach and Kinetrex acquisitions. We received $413 million in proceeds from the NGPL interest sale. And we had a working capital use of approximately $530 million, and that explains the majority of the $828 million reduction in net debt for the year. And that completes the financial review, and I’ll turn it back to Steve.

All right. Thanks, David. And operator, if you would come back on and we will open it up for questions, and I’ll just remind everybody on the line that as a courtesy as we have been doing for years now. As a courtesy to all the callers, we ask that you limit your questions to one and one follow-up. But if you’ve got more questions, get back in the queue, and we will come back around to you. So with that, operator, let’s open it up for questions.

Yes, sir. Thank you. [Operator Instructions] Thank you. Our first question comes from Jeremy Tonet with JPMorgan. Your line is open, sir.

Hi, good afternoon.

Good afternoon.

Just want to start off with a couple of pipeline questions if we could. In the Permian, our analysis points towards mid-2024 need for more gas takeaway, and that depends on Mexico actually absorbing gas they are expected to take, which could be a swing. So just wondering your thoughts here as far as the need for new pipe and do you see that more likely to be a newbuild or have input costs move steel, labor or what have you to the point where a conversion from oil to gas could make more sense to come first. Just wondering, give and take between the two options, how you think it shakes out at this point?

Okay. Good question, and I’ll ask Tom Martin to weigh in on this as well. But we are hearing from the shippers that we’re talking to the customers that we’re talking to, dates as early or time frames as early as late 2023. Now there is not time from now until then to get – actually get something done, but we’re also hearing so late 2023 or 2024. I think our starting assumption is that it really will need to be an additional newbuild pipe, which I will make clear, we’ve shown our successful ability to build those pipes, get it done even under different difficult circumstances. But as always, we’re going to be very disciplined, and we will be taking a very close look at the permitting environment and making sure that we’re getting good contractual coverage, et cetera, et cetera. So we will be disciplined. We don’t need to win the third pipe just for the sake of winning it. We’ll do it on economic terms. The difficulty of the conversion, I wouldn’t say, Jeremy, that it can’t happen, but a lot of the pipe that’s out there, while it’s not fully contracted, maybe and there is certainly in excess of prudent takeaway. There is a fair amount of work to do with existing shipper arrangements there at least that’s our perception. And so while it’s a possibility, it kind of tilts toward, we think, newbuild capacity. But Tom weigh in here.

I agree with you, Steve. I mean I think we certainly had conversations about pre-pipe conversions and I think just the complexity of managing the arrangements around the oil in conjunction with the gas side of the equation has made that pretty tough, still working those opportunities. But I think, as you said, the more likely next step is going to be a newbuild pipe. I think there are some small pockets of expansion opportunities to absorb incremental volumes, but I think the market clearly is going to need another significant pipeline greenfield build in the time frame that you alluded to.

Got it. So even with inflation, it seems like a newbuild more likely than conversion at this point. So I just wanted to touch on that. That’s very helpful. And then shifting gears on gas as well. It seems like there is – there might be a number of, I guess, rate cases across the gas pipeline segment for this upcoming year. And just wondering at a high level, if you can kind of talk through abounds of outcomes or how you are thinking about those as it feeds into your guidance for the year? I imagine the Analyst Day would have a lot of gory detail there, but just wondering if you could provide us any other thoughts at this juncture?

Yes. We think we’ve adequately accommodated that in our outlook. There are a number of discussions going on, as you alluded to. A couple of them are on – and I’m talking about things where we have obligations, for example, to file the cost, revenue studies or where we have an existing rate case. Two of them are on joint venture pipeline. So while the cost and revenue study are engaged with our customers on NGPL that we own 37.5% of an FGT, Energy Transfer as the operator there. They are deep into the settlement process, have a filed settlement. That’s a 50-50 pipe for us. But then we have cost and revenue study that was due late last year on El Paso, that’s still very early stages. And then working with our customers on we’re kind of combining CIG and WIC here together. But – so that’s the set of pipes that are affected. But we think we’ve got good discussions underway with shippers. And while no outcomes are final yet, I think we’ve adequately accommodated it.

That’s helpful. I’ll get back in the queue. Thanks.

Thank you.

Thank you. Our next question comes from Colton Bean with Tudor, Pickering, Holt & Company. Your line is open.

Good afternoon. Appreciate the earlier thoughts on capital allocation. I would just love to follow-up there on the balance sheet component. You have the existing target of 4.5x, but it looks like you’ll undershoot this year. We’ve also seen the broader midstream group trending lower with many of the large caps now looking at something below 4x. So, can you update us on how you think about the appropriate financial leverage for KMI and any factors that might cause you to shift that mark?

Sure. I’ll start and David Michels, you discuss as well. So we believe that the 4.5x is still appropriate. If you look at where we really rate, we rate a little better than BBB flat. And that’s a function of the composition of our business and our cash flows, significant long-haul transmission pipe assets and storage assets that are under long-term contracts with fixed reservation fees and the like. When you look at the composition of our cash flows, and we will go into this into some more detail, the take-or-pay plus fee-based plus hedged, I mean we have, I think, a very attractive profile of the underpinning for those cash flows. And so we think that, that’s appropriate. It is nice to have a little capacity under that this year at the 4.3x as you alluded. But David, anything else you wanted to add?

Yes. In addition to what you just covered, Steve, Colton, we regularly look at if we were to lower our leverage level, if that were to achieve or to result in a meaningful reduction in our cost of capital, in the current markets, we don’t see that – we don’t see a lower, a meaningfully lower cost of capital if we were to lower our longer-term target level. That may change in the future, but as of right now, that plays into it as well. So I think Steve’s points are the right ones to keep in mind. We’re comfortable given our many credit factors, scale, business mix, diversification, contracted cash flows that are predictable. We’re comfortable with that longer-term leverage level. But as Steve mentioned, we do see some value and having some cushion underneath it.

Got it. Appreciate that detail. And maybe just back on natural gas. On the RSG supply aggregation strategy, is that a service that you view as helping attract volumes to the KMI system or something you may be able to monetize in its own right whether that’s through tariff surcharges, marketing or something similar?

Yes. We think it’s a product that increasingly the market is attracted to. We have done several of these deals with responsibly sourced gas. We have filed at the FERC to set up some paper pooling points for people to ship on our system with responsibly sourced gas. And so there is a lot of focus on lowering methane emissions and low methane emissions gas is an attractive proposition to our customers. It is a value add we think. I don’t know that you really – you’re not really seeing that much in terms of pricing. But in the longer-term, it could be a value-added service. But we think we’re given the market what it wants here in that form. And I think all the work that we’ve done to keep our methane emissions low over – really over decades now since the ‘90s, we’ve been working on this. We see that as value add and our customers tell us it is. And so I think this is a trend that we’re at the beginning of and expect to continue to see grow over time and to have a role to participate in it. Tom, anything you wanted to add?

No, Steve, I think you covered it well. I mean we do believe this is kind of the beginning of the trend here, and we will be looking for opportunities to expand what we’re doing or proposing to do a – filing to do on TGP. We will look for opportunities to expand that on our other assets as well.

We have gotten a lot of questions and people and concerns about exactly how it’s going to operate. And so we will be working with our shippers on trying to come up with an approach that that gets as many people as possible on board with it. So, we are in – we expect it to go through, but we’re in kind of early stages.

Thanks for the time.

Thank you. Our next question comes from Jean Ann Salisbury with Bernstein. Your line is open.

Hi. Do you see the past quarter kind of the trough for your Permian gas pipe utilization which obviously came on during the third quarter, and that’s kind of the last new pipe in the queue? So will your pipes kind of reflate over the next year or two?

We’ve had some variances depending on weather and where people want to go with the gas that they have. But generally, Tom, our GCX and PHP have been operating pretty close to capacity, right?

That’s correct. Yes.

I think I meant actually more on some of the other ones that perhaps you were like fully take or pay on.

Yes. Yes. So we also serve out of the Permian as egress out of the Permian, our NGPL system, and also EPNG. We did see some volume reduction on EPNG because we’ve had to reduce activity on our Line 2000 following an accident on that pipeline earlier in the year. And as we put on our electronic [indiscernible], we are in the process of doing some additional in-line inspection on that line now. And so it’s going to be out for a few months but we will ultimately safely restore that pipeline to service and the market does want that capacity. So I have a little concern that we will be able to place that. I don’t know if I’d use the term trough, but I think if you’re looking at downturn, that’s probably what you’re seeing.

All right. That makes sense. And then just to kind of stay on the Permian topic. There is obviously a lot of gas flaring in the Permian in 2019 when we last turn out of gas takeaway. In the Bakken, we’re hearing that E&Ps are kind of committed to not increasing flaring this time around. You kind of hear that from a lot of the Permian E&Ps as well, but it feels like if that were true, you’d see a little bit more hustle around getting a gas solution in place for 2024. So I was wondering if you could kind of just square that for me, is it like some are determined not just flare but some are not?

Yes. So I think – there are two things that I think have changed since 2019, Jean, and one is that. People are not interested in flaring gas, and there is increasing pressure even if you might otherwise elect to, there is increasing pressure from the regulator to not do it. And so flaring is just far less acceptable. Not that it was ever fully acceptable. But you know what I mean, in degree of scrutiny – far greater scrutiny on it now and both inside these companies primarily but also from regulators. The second thing that’s changed, and it’s an important thing, too, is that the gas was less valuable as a stand-alone commodity in 2019. And it was almost like to get the oil out people are just looking for some place to put the gas, right? And we’re even willing to flare it in the absence of an acceptable takeaway alternative. I think this is valuable gas. And I think people are going to want to find a home for it in a pipeline and take away and monetize that for their shareholders. So we’ve seen a change in the tolerance for flaring and also a change in the value of the commodity that was previously flared.

Great. That’s very helpful. Thank you.

Thank you. Our next question comes from Keith Stanley from Wolfe Research. Your line is open.

Hi, good afternoon. I wanted to start on the 2022 growth CapEx, the $1.3 billion is a little higher, I think, than expected compared to the backlog of $1.6 billion over a few years. Is it fair to think you added a fair amount of incremental projects since the last quarter. Any color on what that might be? And I guess I’m particularly focused on RNG and how you might be spending money in that business this year?

Yes. And we will, again, Keith, will give you more detail on this when we get to next week, but I think over $800 million of that $1.3 billion was what was already in our backlog, not necessarily all for ‘22, but for 2022 and subsequent periods. And we do have some expectation as the market has gotten strong and volumes have grown that there will be some need for additional G&P CapEx but also natural gas. Now natural gas is – yes, natural gas. And we do have some placeholder dollars in for potential additional RNG opportunities that we put in the budget. But beyond that, I’ll ask you to pull off until you see our details when we get to next week.

Great, thanks. And sorry to beat a dead horse on the potential new Permian gas pipeline. Can you just give an update on, I guess, appetite you’re hearing from producers for 10-year type of contracts on a potential new pipeline? And then I don’t think you said, but what’s the soonest you think you could complete a new pipeline if you moved forward today as of now?

I’ll take the last one and Tom, I’d ask you to cover the first one. In terms of timing, PHP took 27 months from FID to in-service. And I think it’s reasonable to expect that this will take that long or longer just as a result of permitting uncertainty and the like. But – so I think the 27 months, maybe a little plus is kind of a reasonable time frame to think about. And Tom, do you want to talk about the appetite for the long-term takeaway contracts?

Yes. I mean I think the market understands that it’s a minimum of 10 years to support a project at the scale. And I think the overall, the market understands and believes there may even be another pipe needed down the road. And so I think from a terminal value perspective that kind of makes sense. But I think I can’t speak to whether they enjoy the taste of that 10 year kind of, but I mean, I think the market understands it. And I think given that there is likely to be more infrastructure needed in the longer term, I think that makes sense to the market as a whole.

And again, we will be, as you expect, keep very focused on risk-adjusted returns here as we think about this project.

Thank you.

Thank you. Our next question comes from Spiro Dounis with Credit Suisse. Your line is open.

Hi. Happy New Year. First question is just on natural gas fundamentals and tied somewhat into some of these questions we are hearing on Permian pipelines. I guess if we look back at the last 2 years or so, the downturn associated in gas basins really created a lot of breathing room for the Haynesville and Appalachia. We have seen that evidence in some growth here. But I guess as we look forward, right, in some of these comments what we are hearing is associated gas is back, right? We are seeing a pretty strong recovery in these basins as evidenced by the prospects for Permian Pass. It seems like that time line keeps moving up a little bit. And just curious, as you sort of think about the call on gas-directed basins going forward, is associated gas a risk here again, could that time some of the progress and growth we have seen so far?

Yes. I will focus on the Haynesville, which is of course, where we are – where we have gathering assets. Really, I think producers have been disciplined about getting back into the Haynesville. I think they still are, but they are back and we have a very good system there, meaning that we have got room to run on the capacity that’s already in the ground, if you will, and relatively capital-efficient investments to add additional throughput to that 2 Bcf a day system at kind of the max. How the give and take plays out precisely between associated gas and dry gas, always that’s – always a dynamic to keep track of. I think we are looking at two new LNG facilities coming online here in early 2022. We are setting new records. Kim mentioned the 33% that we saw year-over-year on LNG volumes. U.S. LNG is still a very attractive value proposition to world energy markets and those facilities have been doing – those developers have been doing a good job of getting those out – getting those under contract. So, we still see the demand side of that picture is pulling hard on both associated gas and dry gas. Tom, anything else you want to add?

Steve, I think you covered it. I mean I do think that, that is those two items are the biggest changes from kind of the last time we saw a major growth in associated gas is that the export market is really pulling on this as well as LNG in Mexico. And then the other factor is capital discipline, I think from the producer community that’s also, I think a key determinant in how the timing of these additional volumes come online.

Got it. Thanks Steve. Thanks Tom. Second question, I want to come back to the $750 million of cash flow available for share repurchases. I know you said opportunistic which makes sense. But just curious I think you could remind us and how to think about trigger point on when you deploy that cash for buybacks. Is it a yield metric you are looking at? And just how you are thinking about it? And maybe outside of that how you are ranking alterative highest invest uses for that excess cash. I noticed in this press release, I think you used the phrase attractive opportunities in your commentary as well. I don’t think that was a phrase you used in December. And so hate to nitpick here, but just curious, since December [Technical Difficulty] that weren’t there before and how you are weighing those against buybacks?

No. I don’t recall a language change, but I think it worked to us. No, I mean we have always thought about this as capacity that’s available for attractive opportunities, including share repurchases. And that’s how we still think about it. In terms of how we look at share repurchases and look at other opportunities, and we look at them on a risk-adjusted return basis. And so there is – there are a number of considerations there. But what we look at is obviously the dividends that we are taking off the table. We look at a terminal value assumption assuming no multiple expansion and then we look at variations on that last in terms of the terminal value, and we make a decision based on a risk-adjusted basis. And so in the share repurchase, obviously, you are, for sure, taking the share count down and taking shares out of the denominator and leaving your cash flows that you are producing available to a smaller group of outstanding shares. When you are looking at a project, you are going to be looking at a lot of things like, well, what is the permitting risk here, what is the cost risk here, what’s the terminal value on that, and this is sort of a single-shot investment as opposed to purchasing shares in an existing diversified solid, stable company. And so we – there is – obviously, there is some weighing back and forth and discussion back and forth on how you get to that. But we try to do it in a disciplined way based on returns.

Got it. Thanks for the color, Steve. Look forward to seeing you guys next week.

Thank you. Our next question comes from Mark Sollecito [ph] with Barclays. Your line is open.

Hi, good afternoon. So, I wanted to start on Stagecoach. I was wondering if you could comment on the integration there. I know you mentioned the assets have been running ahead of your model. But just wondering, as you think about ‘22 budget, what’s factored in as far as some of the commercial synergies that you have talked about versus what might be upside as we look a little further out?

Yes. So, we have fully integrated the assets commercially. And at this point, operationally, maybe a little bit of transition on control room still ongoing there. But really fully integrated and especially pointing out the commercial part of it. I mean there are some things that we had assumed we would be able to do in the model that we have been able to do and actually do a little bit better. That’s what leaves us slightly above our acquisition model. We think there is more of that to come. We baked what we see realistically for 2022 in our ‘22 guidance. And down the road, I think we will continue to find more. Tom?

No, I think you covered a well, Steve I mean, it’s gone very well. The integration with not only the asset and portfolio, but with our TGP business as well, I think we anticipated some synergies there. I think we are seeing more. And I think green shoots for more to come as we go forward.

Great. Appreciate the color there. And then similar to the discussion earlier on the Permian gas takeaway outlook. I was wondering if you could share your latest thoughts on the Bakken gas takeaway picture. I know a couple of years ago, you are working on a potential solution with some partners that would utilize some of your Rockies pipes. So, just wondering where that stands today.

Tom?

We are still working that opportunity. Nothing really new to report at this time. It’s still in the earlier stages. And I think we will continue to try to progress that opportunity.

I appreciate the time.

Thank you. Our next question comes from Michael Lapides with Goldman Sachs. Your line is open.

Hi guys. Thank you for taking my question. Just curious, trying to think a little bit about the impacts of Omicron in this quarter and really the cadence during the quarter. When you look at refined products volumes relative to what your expectations were, can you just talk a little bit and obviously, some seasonality plays into it. How refined products volumes kind of appeared in the latter portion of the quarter and maybe entering into January versus kind of the October period when Omicron was not really on the radar screen?

Right. Dax, I will ask you and then John to talk about that from the perspective of each of your businesses. You go first, Dax.

Yes. I would say not – probably not a huge impact. I mean one thing that I think one of the most salient pieces of data if you compare where we were in the fourth quarter compared to the prior year, we were 9% above, as Kim said. We were 10% above the prior year for the year-to-date. But if you look at December only, these were 15% above. So, as we exited the year, it was – we saw some pretty positive momentum. So, we saw a little bit – we saw a little bit maybe – a little bit more downside on jet fuel, but combined, it was pretty positive. So, that’s the way we saw the year exit. We didn’t really see a meaningful downside.

Okay. And John?

Sure. No meaningful impact. Q4, December, we saw very strong rack volumes. We were up 15.5%. So, coming into January, we have only got a couple of weeks of data points, but our Midwest volumes are up 2% on a year-over-year basis. Our Jefferson Street Truck Rack in Houston is up 9%. The only weakness we are seeing is in our Northeast facilities, which are down 5%, but net-net, we are up 1% on a year-over-year. Down slightly to budget, but I think more of that has to do with the two bad snowstorms that we have had in the Midwest and in the Northeast, more so than the Omicron impact.

Got it. Thank you, guys. Much appreciated, and look forward to next week’s information.

Thank you. Our next question comes from Brian Reynolds with UBS. Your line is open.

Hi. Good evening everyone and thanks for taking my question. I am just trying to square away some of these Permian nat-gas pipe comments and time line commentary. Just wondering if there is a limited appetite for flaring value in natural gas in the 24-month build time, does this simply imply that there is a slowing in Permian growth at the year-end ‘23, or is there a scenario that we could see potentially more flaring from private versus public to get through this period of tightness? Thanks.

Yes. Tom, do you want to talk about that?

Yes. I mean I think there are limitations as to how quickly a new project could be brought into service. So, I think the producers will manage the development of their volumes carefully with that in mind to minimize flaring. But I mean it may end up being more of a factor than they desire to be based on the economics.

Great. Thanks. And as a follow-up, just on the RSG supply aggregation pooling system, just curious if you could talk about how you look to expand that across the system and if that’s something that you could also expand into the KMI’s Permian nat-gas pipes as well? Thanks.

Yes, Tom, why don’t you talk to that?

Yes. So, I mean, again, based on the traction that we get on TGP, I think that will give us a lot of guidance as to where we go next and pursue other pipelines to deploy the same concept. But clearly, the market is asking for this type of service and especially the export market, LNG especially, I think the domestic market will catch up. And so I would think the natural candidates would be additional pipes that serve export opportunities would be – those would be sort of additional opportunities that we consider going forward. But I think we view this one as the first sort of first case and we will use depending on how well it goes and how quickly it takes off, use that as sort of a blueprint as to how we go forward.

Great. That’s it for me. Thanks for taking my question and have a great day.

Thank you. Our next question comes from Timm Schneider with Citi. Your line is open.

Yes. Good afternoon. Quick question, a higher level question for you as you are kind of the largest or one of the largest players in midstream land here, how challenging or maybe not challenging has it been kind of threading the needle with respect to capital allocation. What I am getting at here is you can kind of have four buckets, right? CapEx, M&A, balance sheet, dividend, buybacks. Obviously, the narrative has been very much buyback driven and stocks have been rewarded for that. But how do you kind of think about maybe not even short cycle type of CapEx but longer cycle type of CapEx that maybe doesn’t have an immediate return that could be larger capital outlays, but maybe the right thing for Kinder Morgan and for others, for that matter, to kind of spend money on now to position it for a place, I guess along the energy value chain down the future?

Yes, good question. So, we have been kind of a broken record on this. I mean there have been times when people want to see backlog build, there have been times when people want to see dividend build times, when want to see share repurchase, etcetera. What we try to do is be consistent and principled about how we look at it and do it in a way that’s going to be most valuable for our shareholders. And we think that the order of operations that we have repeated again and again is the right one. Make sure the balance sheet is strong. We have gotten there to make sure that we sanction the projects that add to the value of the firm that give us returns that are well above our weighted average cost of capital. The commentary I gave there was we kind of been at the low end of our $1 billion to $2 billion that we talked about. And we have kind of been tilting more towards smaller projects that are on our existing footprint that have nice returns and lower risk building off of your existing footprint. But anyway, you go through those. And then with the excess cash, you look to return to shareholders in the form of a dividend that’s well covered and then share repurchases. Now to your question on how do you look at something that maybe adds to the value of the firm over the longer term, I will point you to an example, a real-life example from last year of how we have looked at that. We do think that renewables while our assets are going to be needed in the service that they are in for a very, very long time, there is no question that there is more growth available in the renewable sector. But we have been, again, disciplined about how we have entered into that, make sure that we understand what we are looking at and dealing with here and that it’s going to produce a really attractive return for our investors and that we have got a good line of sight. We are not building it based on some hockey stick projection. Instead, we were looking at in the acquisition of Kinetrex which is the example I am referring to a good existing platform business that had three shovel-ready projects under contract already and with an EPC contract in place. And so, we felt very comfortable bringing that to our investors, bringing it to our Board and bringing it to our investors and saying, look, this is a nice example of how we are looking at something that it is going to be a year or 2 years down the road before you see this turn into a really attractive multiple, but we have a really defined line of sight on that. And so I think that’s a reasonable way to think about how we will approach this and not, for example, to just say, we think solar is going to be great. And even though we don’t know a whole lot about it, we are going to pile in. That’s really not the way we have traditionally done things. And I think we have shown you how we are looking at these, and we have been consistent in our messaging about we want to be able to demonstrate attractive returns to our investors as we enter these businesses.

I would just add to what Steve said. Really, the primary objective of this management team and our Board is to be really good stewards of this enormous amount of cash flow that we are generating. And so it’s an art, not a science, but we weigh all of these things in making what we believe are disciplined, good decisions about where to allocate this capital. That’s probably the most important single thing we wrestle with every day.

Alright. Thank you. I appreciate it. That’s all I had.

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

Well, thank you all very much and have a good evening. Thank you.

That does conclude today’s conference. You may disconnect at this time and thank you for joining.