Kinder Morgan, Inc. (NYSE: KMI) Q4 2021 earnings call dated Jan. 19, 2022
Corporate Participants:
Richard D. Kinder — Executive Chairman
Steven J. Kean — Chief Executive Officer
Kimberly Allen Dang — President
David P. Michels — Vice President and Chief Financial Officer
Tom Martin — President, Natural Gas Pipelines
Dax Sanders — President, Products Pipelines
John W. Schlosser — President, Terminals
Analysts:
Jeremy Tonet — J.P. Morgan — Analyst
Colton Bean — Tudor, Pickering, Holt and Company — Analyst
Jean Ann Salisbury — Bernstein — Analyst
Keith Stanley — Wolfe Research — Analyst
Spiro Dounis — Credit Suisse — Analyst
Mark — Barclays — Analyst
Michael Lapides — Goldman Sachs — Analyst
Brian Reynolds — UBS — Analyst
Timm Schneider — Citi — Analyst
Presentation:
Operator
Welcome to the quarterly earnings conference call. Today’s call is being recorded. If you have any objections, 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.
Richard D. Kinder — Executive Chairman
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 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’s 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’ll keep these factors I have mentioned in mind when making investment decisions about our stock over the coming year. More to come on all of these subjects at our Investor Day Conference next Wednesday.
And with that, I’ll turn it over to Steve.
Steven J. Kean — Chief Executive Officer
Okay, thank you. I’ll 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’ll take your questions. As is usually the case on this call, which comes the week before our comprehensive investor conference, we’ll defer to next week some of the more in depth and detailed questions on the 2022 budget and the outlook and business opportunities.
As of 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 are — we were running a bit shy of 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 is we’ll 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’re 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 4.3 times,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’re 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’re also generally seeing or we’re continuing the 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 a $1.11 for 2022 and in the form of share repurchases. As we said in our 2022 budget guidance released 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, etc.
As we’ve 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’re 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.
Kimberly Allen Dang — President
Okay, thanks Steve. All right, 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 of 2020. That was driven primarily by continued decline in Rockies production, the pipeline outage on EPNG and FEP contract explorations, which were offset somewhat by increased LNG deliveries and PHP and service volume.
Physical deliveries to LNG facilities off of our pipeline averaged about 5 million dekatherms per day, but the 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.
On our Products Pipelines 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 of ’19 as a reference point, road fuels gasoline and diesel were down about 2% and jet was down 22%. In Q3, road fuels were down 3% versus the 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 the reduction in Eagle Ford volumes, partially offset by an increase in the Bakken. If you strip out Double H pipeline volumes from our Bakken numbers and those 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’ve 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 were 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 project that we decided to do during the year, the impact sustaining capex, we ended the year on plan for both EBITDA and DCF.
And with that, I’ll turn it over to David Michels.
David P. Michels — Vice President and Chief Financial Officer
All right. Thanks, Kim. So, for the fourth quarter of 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 onto 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’ve had contract explorations, NGTL 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 terminal 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, though 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 as much of the spend from earlier 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 million 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 3.9 times, down from 4.6 times at year-end 2020. Removing the nonrecurring Uri contribution to EBITDA, that ratio at the end of 2021 would be 4.6 times, 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 million of DCF, we spent — 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 million of DCF, we paid out dividends of $2.4 billion, we spent $570 million on growth capex and JV contributions, we spent $1.53 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.
Steven J. Kean — Chief Executive Officer
All right, thanks, David. And operator, if you would come back on and we’ll 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 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.
Questions and Answers:
Operator
Yes, sir. Thank you. [Operator Instructions] Our first question comes from Jeremy Tonet with J.P. Morgan. Your line is open sir.
Jeremy Tonet — J.P. Morgan — Analyst
Hi, good afternoon.
Steven J. Kean — Chief Executive Officer
Good afternoon.
Jeremy Tonet — J.P. Morgan — Analyst
Just wanted to 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’re 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 new build 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 do you think it shakes out at this point?
Steven J. Kean — Chief Executive Officer
Yeah, 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 earlier timeframes as early as late 2023. Now, there’s not time from now till 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 new build pipe, which I will make clear. We’ve shown our successful ability to build those pipes, get it done even under a difficult circumstances, but as always, we’re going to be very disciplined and will be taking a very close look at the permitting environment and making sure that we’re getting good contractual coverage etc., etc.
So, we’ll 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 with the conversion. I wouldn’t say, Jeremy, that it can’t happen, but a lot of the pipe that’s out there, well, it’s not fully contracted maybe and is certainly in excess of crude takeaway. There is a fair amount of work to do with the existing shipper arrangements there, at least that’s our perception. And so while it’s a possibility, it kind of tilts toward we think new build capacity. But Tom weigh in here.
Tom Martin — President, Natural Gas Pipelines
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 arrangements around the oil in conjunction with the gas out of the equation has made that pretty tough. We’re still working those opportunities, but I think, like as you said, the more likely next step is going to be a new build 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 timeframe that you alluded to.
Jeremy Tonet — J.P. Morgan — Analyst
Got it. So even with inflation, it seems like a new build more likely than conversion at this point. So just want 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 a bounds of outcomes or how you’re thinking about those as it feeds into your guidance for the year. I imagine the Analyst Day would have a lot of gaudy detail there, but just wondering if you could provide us any other thoughts at this juncture?
Steven J. Kean — Chief Executive Officer
Yeah, 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 that we have obligations, for example, while the cost and revenue studies where we have an existing rate case. Two of them are on our joint venture pipeline. So, while the cost and revenue study are engaged with our customers on NGPL that we own 37.5% of and then FGT energy transfers, the operator there, they are deep into the settlement process have a filed settlements. 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 trying to combining CIG and WIC here together, but — so that’s a 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 that.
Jeremy Tonet — J.P. Morgan — Analyst
That’s helpful. I’ll get back in the queue. Thanks.
Steven J. Kean — Chief Executive Officer
Thank you.
Operator
Thank you. Our next question comes from Colton Bean with Tudor, Pickering, Holt & Company. Your line is open.
Colton Bean — Tudor, Pickering, Holt and Company — Analyst
Afternoon. I appreciate the earlier thoughts on capital allocation, would just love to follow-up there on the balance sheet component. And you have the existing target of 4.5 times, but it looks like you’ll undershoot this year. We’ve also seen the broader midstream group trending lower to large caps now with something below 4 times. So, can you update us on how you think about the appropriate financial leverage for KMI. And any factors that might cause you to ship them up?
Steven J. Kean — Chief Executive Officer
Sure, I’ll start and David Michels you discuss as well. So, we believe that the 4.5 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. We will go into this in some more detail to 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’s appropriate. It is nice to have a little capacity under that this year at the 4.3 times, as you alluded. But David anything else you wanted to add.
David P. Michels — Vice President and Chief Financial Officer
Yeah. 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, the business mix, diversification, contracted cash flow is sort of predictable. We’re comfortable at that longer-term leverage level, but as Steve mentioned, we do see some value and having some cushion underneath it.
Colton Bean — Tudor, Pickering, Holt and Company — Analyst
Got it. Appreciate that detail. And then maybe just back on natural gas, on the RSU 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?
Steven J. Kean — Chief Executive Officer
Yeah, we think it’s a product that increasingly the market is attracted to. We’ve done several of these deals with responsibly sourced gas. We have filed with 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 those. 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 want to add?
Tom Martin — President, Natural Gas Pipelines
I think you covered about well, I mean, we do believe this is kind of the beginning of the trend here and we’ll be looking for opportunities to expand what we’re doing or proposing to do or [Indecipherable] we’ll look for opportunities to expand that on our other assets as well.
Steven J. Kean — Chief Executive Officer
We have gotten a lot of questions and concerns about exactly how it’s going to operate and so we’ll be working with our shippers on trying to come up with an approach that gets as many people as possible on board with it. So, we’re in — we expect it to go through, but we’re in kind of early stages.
Colton Bean — Tudor, Pickering, Holt and Company — Analyst
Thanks for the time.
Operator
Thank you. Our next question comes from Jean Ann Salisbury with Bernstein. Your line is open.
Jean Ann Salisbury — Bernstein — Analyst
Hi. Do you view this 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 pipe kind of reflate over the next year or two?
Steven J. Kean — Chief Executive Officer
We’ve had some variances depending on weather and where people want to go with the gas that they have, but generally GTX and PHP have been operating pretty close to capacity. Right?
Tom Martin — President, Natural Gas Pipelines
That’s correct. Yeah.
Jean Ann Salisbury — Bernstein — Analyst
I think I meant actually more on some of the other ones that perhaps — you are like fully take advantage?
Steven J. Kean — Chief Executive Officer
Yeah. So, we also serve out of the Permian as egress out of the Permian, our NGTL system and also EPNG. We did see some volume reduction on EPNG because we had — we’ve had to reduce activity on our line 6000 following an accident on that pipeline earlier in the year. And as we put on our electronic board we’re 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 will ultimately safely restore that pipeline to service and the market does want that capacity. So, I have little concern that we’ll be able to place that. I don’t know if I’ve used the term trough, but I think if you’re looking at downturn that’s probably what you’re seeing.
Jean Ann Salisbury — Bernstein — Analyst
All right, some extent. And then just to kind of being on the Permian topic, there’s obviously a lot of gas flaring in the Permian in 2019 when we last turned 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 see a little bit more hustle around getting a gas solution in place for 2024. So I’m wondering if you kind of just square that for me, is it like some are determined not to flare, but some are not?
Steven J. Kean — Chief Executive Officer
Yeah. So, I think there are two things that I think have changed since 2019 Jean Ann, one is that, people are not interested in flaring gas and there is increasing pressure even if you might otherwise elect to. There’s 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, a degree of scrutiny, it’s 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 standalone commodity in 2019 and it was almost like to get the oil out. People were just looking for some place to put the gas right and were even willing to flare in the absence of an acceptable takeaway alternative. I think this is a 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.
Jean Ann Salisbury — Bernstein — Analyst
Great. That’s really helpful. Thank you.
Operator
Thank you. Our next question comes from Keith Stanley from Wolfe Research. Your line is open.
Keith Stanley — Wolfe Research — Analyst
Hi, good afternoon. I wanted to start on the 2022 growth capex to $1.3 billion as 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?
Steven J. Kean — Chief Executive Officer
Yes. And we’ll again — we 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, if there will be some need for additional G&P capex, but also natural gas — not natural gases — yeah, natural gas and we do have some placeholder dollars in for a potential additional RNG opportunities that we put in the budget. But beyond that, I’ll ask you to pull off and see our details when we get to next week.
Keith Stanley — Wolfe Research — Analyst
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 is the soonest you think you could complete a new pipeline if you moved forward today as of now?
Steven J. Kean — Chief Executive Officer
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 as kind of a reasonable timeframe to think about. And Tom, do you want to talk about the appetite for the long-term takeaway contracts?
Tom Martin — President, Natural Gas Pipelines
Yeah, I mean. I think the market understands that it’s a minimum of 10 years to support a project of the scale. And I think 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 tenure, but I mean, I think the market understands it and I think given that there’s likely to be more infrastructure needed in the longer term, I think that makes sense to market as a whole.
Steven J. Kean — Chief Executive Officer
And again will be as you expect, keep very focused on risk-adjusted returns here as we think about this project.
Keith Stanley — Wolfe Research — Analyst
Thank you.
Operator
Thank you. Our next question comes from Spiro Dounis with Credit Suisse. Your line is open.
Spiro Dounis — Credit Suisse — Analyst
Thanks, operator. Hi, team, Happy New Year. First question is on natural gas fundamentals and tied somewhat into some of these questions you’re hearing on Permian pipelines. I guess, if we look back at the last two years or so, the downturn associated gas basins really create a lot of breathing room for the Haynesville and Appalachia. We’ve seen that evidence in some growth here. But as we look forward, right, in some of these comments what we’re hearing is sort of CO2 to gas is back, right?
We’re seeing a pretty strong recovery in these basins as evidenced by the prospects for Permian pass. It seems like that timeline keeps moving up a little bit. And so, 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 stymie some of the progress and growth we’ve seen so far?
Steven J. Kean — Chief Executive Officer
Yeah, I’ll focus on the Haynesville, which is of course where we have gathering assets. Really, I think producers have been disciplined about getting back in the Haynesville. I think they still are, but they are back and we have a very good system there, meaning that we’ve 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 place plays out precisely between associated gas and dry gas. That’s always a dynamic to keep track of. I think we’re looking at two new LNG facilities coming online here in early 2022.
We’re 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 out — 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 as pulling hard on both associated gas and dry gas. Tom. Anything else you want to add?
Tom Martin — President, Natural Gas Pipelines
No, Steve, I think you covered it. I mean. I do think that is — those two items are the biggest changes from the last time we saw a major growth in associated gas is the export market is really pulling on this, as well as LNG in Mexico. And then the other factor is capital discipline I make from the producer community. That’s also I think a key determinant in how the timing of these additional volumes come off.
Spiro Dounis — Credit Suisse — Analyst
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 if you could remind us again how to think about the trigger point on when you deploy that cash for buybacks? Is it a yield metric you’re looking at and just how you’re thinking about it?
And maybe outside of that, how you’re ranking alternative highest and best 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, I hate to nitpick here, but just curious since December [Technical Issue] that weren’t there before and how you’re weighing those against buybacks?
Steven J. Kean — Chief Executive Officer
No, I don’t recall a language change, but I think you worked for it. No, I mean, we’ve 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 when we look at them on a risk adjusted return basis and there are a number of considerations that are, but we look at it is obviously the dividends that we’re 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 a 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’re producing available to a smaller group of outstanding shares.
When you’re looking at a project, you’re going to be looking at a lot of things, like well what is the permitting risk here, what is the cost risk here and what’s was 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’s — obviously there’s some weighing back and forth and discussion back and forth on how you get to that. But we’ve tried to do it in a disciplined way based on returns.
Spiro Dounis — Credit Suisse — Analyst
Got it. Thanks for the color, Steve. Look forward to seeing you guys next week.
Operator
Thank you. Our next question comes from Mark [Indecipherable] with Barclays. Your line is open.
Mark — Barclays — Analyst
Hi, good afternoon. So wanted to start on Stagecoach and I was wondering if you could comment on the integration there. You mentioned the assets have been running ahead of your model, but just wondering as we think about ’22 budget what sector as far as some of the commercial synergies that you talked about versus what might be upside as we look a little further out?
Steven J. Kean — Chief Executive Officer
Yeah. So, we have fully integrated the assets commercially and at this point, operationally, maybe a little bit of transition on control rooms 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’d be able to do in the model that we’ve been able to do and actually do a little bit better. And that’s what leaves us slightly above our acquisition model. We think there is more of that to come. We’ve baked what we see realistically for 2022 in our ’22 guidance and down the road. I think we’ll continue to find more. Tom?
Tom Martin — President, Natural Gas Pipelines
I think you covered it well, Steve. I mean it’s gone very well, the integration with not only the asset and to the portfolio, but with our TGP business as well. I think we anticipated some synergies there. I think we’re seeing more, I think, green shoots for more to come as we go forward.
Mark — Barclays — Analyst
Great. Appreciate the color there. And then similar to 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’re working on a potential solution with some partners that would utilize some of your Rockies pipe. So just wondering where that stands today?
Steven J. Kean — Chief Executive Officer
Tom?
Tom Martin — President, Natural Gas Pipelines
Still working that opportunity. Nothing really new to report at this time, but still in the earlier stages. And I think, we’ll continue to try to progress that opportunity.
Mark — Barclays — Analyst
Great. I appreciate the time.
Operator
Thank you. Our next question comes from Michael Lapides with Goldman Sachs. Your line is open.
Michael Lapides — Goldman Sachs — Analyst
Hi guys. Thank you for taking my question. Just curious, trying to think a little bit about the impacts of omicron in the 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?
Steven J. Kean — Chief Executive Officer
Right. Dax I’ll ask you and then John to talk about that from the perspective of each of your businesses. You go first. Dax.
Dax Sanders — President, Products Pipelines
Yeah, 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, we were 15% above. So, as we exited the year, it was — we saw some pretty positive momentum. So, we saw a little bit, maybe 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.
Steven J. Kean — Chief Executive Officer
Okay. And John?
John W. Schlosser — President, Terminals
Sure. No meaningful impact. Q4 December, we saw very strong rack volumes. We were up 15.5%. So coming into January, we’ve only got a couple of weeks as data points, 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’re seeing is in our Northeast facilities, which are down 5%, but net-net, we’re up 1% on a year-over-year. Down slightly to budget, but I think more of that has to do with the two bad snow storms that we’ve had in the Midwest and the Northeast, more so than the omicron impact.
Michael Lapides — Goldman Sachs — Analyst
Got it. Thank you, guys. Much appreciated and look forward to next week’s information.
Operator
Thank you. Our next question comes from Brian Reynolds with UBS. Your line is open.
Brian Reynolds — UBS — Analyst
Hi, good evening, everyone, and thanks for taking my question. I’m just trying to square away some of these Permian nat gas pipe comments and timeline commentary. Just wondering if there’s a limited appetite of flaring value in natural gas in the 24-month build time? Does this simply imply that there’s a slowing in Permian growth at the year-end ’23? Or is there a scenario that we could see potentially more flaring from privates versus publics to get through this period of tightness? Thanks.
Steven J. Kean — Chief Executive Officer
Yeah, Tom, you want to talk about that?
Tom Martin — President, Natural Gas Pipelines
Yeah, I mean, I think, there are limitations as to how quickly a new project can 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.
Brian Reynolds — UBS — Analyst
Great, thanks. And as a follow-up just on the RSG supply aggregation pooling system. I’m just curious if you could talk about how you look to extend that across the system? And if that’s something that you could also expand into the KMI’s Permian nat gas pipe as well? Thanks.
Steven J. Kean — Chief Executive Officer
Yeah. Tom, why don’t you talk to that?
Tom Martin — President, Natural Gas Pipelines
Yeah, 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 test case and we’ll use depending on how well it it goes and how quickly it takes off, is that a sort of a blueprint as to how to go forward.
Brian Reynolds — UBS — Analyst
Great, that’s it from me. Thanks for taking my question and have a great day.
Operator
Thank you. Our next question comes from Timm Schneider with Citi. Your line is open.
Timm Schneider — Citi — Analyst
Yeah, hi, good afternoon. Quick question, higher level question for you as kind of the largest, one of the largest players in midstream land here, how challenging or may be not challenging has it been kind of threading the needle with respect to capital allocation. What I’m getting here — at here is we can 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 may be the right thing for Kinder Morgan and for others, for that matter, to kind of spend money on now to be position it for a place I guess along the energy value chain than the future?
Steven J. Kean — Chief Executive Officer
Yeah, good question. So, we’ve been kind of a broken record on this. I mean there have been times when people want to see backlog builds, there have been times when people want to see dividend builds, times when want to see share repurchase etc. What we try to do is be consistent and principled about how we look at it and do it in a way that’s maybe most valuable for our shareholders and we think that the order of operations that we’ve repeated again and again is the right one, make sure the balance sheet is strong. We’ve gotten there, make sure that we sanction the projects that add to the value, 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 at the low end of our $1 billion to $2 billion that we talked about and we’ve kind of been tilting more toward smaller projects that are on our existing footprint that have nice returns and lower risk building off of your existing footprint. 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 you look at something that maybe adds to the value to firm over the longer term. I’ll point you to an example, real life example from last year of how we’ve looked at that. We do think that renewables — while our assets are going to be needed in the service that they’re in for a very, very long time, there’s no question that there is more growth available in the renewable sector, but we’ve been again disciplined about how we’ve entered into that, make sure that we understand what we’re looking at and dealing with here and that it’s going to produce a really attractive return for our investors and that we’ve got a good line of sight.
We’re not building it based on some hockey stick projection, instead, we were looking at in the acquisition of Kinetrex, which is the example I’m 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, bring it to our Board and bring it to our investors and saying, look, this is a nice example of how we’re looking at something that it is going to be a year or two 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 how we think solar is going to be great and even though we don’t know a whole lot about it, we’re going to pile in. That’s really not the way we’ve traditionally done things and I think we’ve shown you how we’re looking at these and we’ve been consistent in our messaging about we want to be able to demonstrate attractive returns to our investors as we enter these businesses.
Richard D. Kinder — Executive Chairman
I would just add to this. 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’re 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.
Timm Schneider — Citi — Analyst
All right, thank you. I appreciate it. That’s all I had.
Operator
Thank you. I’m showing no further questions in the queue at this time.
Richard D. Kinder — Executive Chairman
Well, thank you all very much and have a good evening. Thank you.
Operator
[Operator Closing Remarks]