Kinder Morgan Inc - Class P (KMI) — Q4 2020 Earnings Call Transcript

Thank you, Denise, and good afternoon. Before we begin, I want to remind you that KMI's earnings release today and this call include forward-looking statements as defined by the Private Securities Litigation Reform Act of 1995 and the Securities and Exchange Act of 1934, along with certain non-GAAP financial measures. Before making any investment decisions, we encourage you to read our full disclosures on forward-looking statements and the use of non-GAAP financial measures 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 lead to actual results differing significantly from those anticipated in the forward-looking statements. Before handing over the call to Steve and the rest of the team, I would like to make a brief statement. Now that we have actual results for the full year 2020 and have released our preliminary outlook for 2021, this is a good time to evaluate our current results and future outlook at Kinder Morgan. The key takeaway is the strength of the cash flow, which enables us to fund our dividend and all discretionary CapEx from internally generated funds, while still having significant cash available to reduce debt and repurchase shares. This remains central to our financial strategy and should reassure our shareholders as it shows our capacity to deliver value even during challenging times like those faced in 2020. I also want to highlight two important points. First, there is considerable potential for the products transported through our pipelines, especially natural gas. Second, our assets are well-placed to contribute to the transition toward a future with lower emissions. We'll delve into these topics in detail at our upcoming virtual investor conference on January 27, and I look forward to your participation.

Thanks, Rich. I'll provide a brief overview of our achievements in 2020 and outline our plans for 2021 and beyond, which we will discuss in more detail at our annual Investor Day next week. After that, I'll hand it over to our President, Kim Dang, for business updates, and our CFO, David Michels, will take you through the financials before we address your questions. In 2020, we learned the importance of having clear priorities and principles. We maintained our focus on ensuring the safety of our coworkers and keeping our essential assets operational for the people, businesses, and communities that rely on us. We remained operational during the pandemic, adapting our procedures to protect our team while supporting utilities, factories, and other businesses serving our communities. The pandemic and the downturn in U.S. energy markets did affect us, but we upheld our financial principles. We worked to maintain a strong balance sheet, reducing net debt by nearly $1 billion, which brings our total net debt reduction over the last five years to over $10 billion. We've achieved and maintained a BBB flat credit rating. We've also demonstrated discipline in capital spending, reducing our 2020 CapEx by roughly $700 million in response to changing market conditions, while successfully completing our largest project, the Permian Highway Pipeline, despite facing significant opposition and operating during a global pandemic. We maintained cost discipline and achieved about $190 million in savings for 2020, with around $119 million of those reductions being permanent. As a result of our effective management of capital and costs, our DCF less discretionary capital spend has improved compared to both our plan and 2019, showing significant gains. In 2019, our DCF less discretionary capital was $2.2 billion, which grew to $2.9 billion in 2020 and is projected to reach $3.65 billion in our 2021 budget. Additionally, we returned value to our shareholders with a 5% year-over-year dividend increase to $1.05 annualized for 2020, with plans to raise it to $1.08 in 2021. We've continued to focus on financial prudence, capital and cost discipline, and returning value to shareholders. Alongside completing the Permian Highway Pipeline, we achieved several significant milestones that we believe will lead to long-term success. We have reviewed our organizational structure and operations to enhance efficiency and have made necessary changes to our management and staffing. These adjustments have led to substantial savings that we will further detail in our upcoming guidance release. We are building a more effective organization for the future, centralizing specific functions to promote best practices in project management, permitting, safety, pipeline integrity, ESG, and other core operations. We published our third ESG report in the fourth quarter and have integrated ESG reporting and risk management into our ongoing management processes. Sustainalytics has recognized us as a leader in our sector for ESG risk management, and our MSCI rating has significantly improved. These initiatives are vital for our long-term success as a responsible and efficient operator capable of completing large projects even under challenging conditions. Our capacity to maintain such performance during a pandemic and a challenging U.S. energy market is a testament to the strength and resilience of our team and culture. Looking forward, we see several opportunities. Our largest business, natural gas, will continue to be integral in meeting domestic demands and supporting export facilities while contributing to the reduction of greenhouse gas emissions. Our assets play a crucial role in facilitating the use of intermittent renewable resources. We are emphasizing the value of our role in providing safe and efficient transportation and storage capacity. Moreover, we are leveraging our low methane emissions performance to market responsibly produced and transported natural gas, enhancing our ESG credentials. In addition, we are handling liquid renewable transportation fuels, and our involvement in this area is poised for growth. We identify further growth opportunities that can utilize our existing assets and expertise, such as blending hydrogen into our natural gas network and transporting and sequestering CO2. We will remain disciplined in pursuing operations with attractive returns without chasing fleeting trends. We anticipate that successful operators in our sector will have robust financial health, efficient and safe operations, and the capability to navigate challenges effectively. We take pride in our team and culture and will continually adapt to meet future challenges and opportunities. Now, I'll hand it over to Kim.

Okay. Thanks, Steve. I'm going to go through our business units today. First, starting with natural gas. Transport volumes were down 2%, or approximately 600,000 dekatherms per day versus the fourth quarter of 2019. That was driven primarily by declines in Rockies' production and increases in transportation alternatives out of the Permian Basin. These declines were partially offset by higher volume, driven by increased demand for LNG exports and industrial customers. Our physical deliveries to LNG facilities off of our pipes averaged almost 5 million dekatherms per day. That's a 50% increase versus the fourth quarter 2019. That's a big increase versus the third quarter of this year, and it's above Q1 2020, which was largely unaffected by the pandemic. For 2020, Kinder Morgan pipes moved well over 40% of the volumes to LNG export facilities. Exports to Mexico were up about 4%, when you compare it to the fourth quarter of 2019. For 2020, our share of Mexico deliveries ran over 55%. Overall, deliveries to power plants were down about 2%. Our natural gas gathering volumes were down about 20% in the quarter compared to the fourth quarter of 2019. For gathering volumes, I think, the more informative comparison is versus the immediately prior quarter, so the third quarter of 2020. When compared to the third quarter of 2020, volumes were down about 3%. KinderHawk, which serves the Haynesville was down due to lack of drilling and declines in existing wells. However, we're still expecting based on our conversations with producers to see new drilling in that basin this year. Eagle Ford volumes were also down. The bright spot again this quarter was our Highland system in the Bakken. Volumes there were up well over 20% versus the third quarter of this year. On the project side, as Steve said, we completed PHP. We placed that into service on January 1st of this year, which is a really amazing accomplishment by our team. We fought through multiple legal attempts to delay or stop the pipeline including one request for a temporary restraining order and three preliminary injunction requests. Permits took longer than they have historically and therefore we received a key permit approximately 4.5 months later than what we anticipated. Yet, despite the legal, the permit and the other challenges we faced, we put the pipeline in service just three months later than our original schedule. In our products pipeline segment, refined products volumes were down about 13% for the quarter versus the fourth quarter of 2019, as a result of the continued pandemic impact. The 13% is very close to the fourth quarter EIA number. Our gasoline volumes were off about 10%. Jet volumes remained weak at 47%. The diesel was up about 7%. Looking at the most recent data, volumes in December were down about 17% versus December of 2019. That's not surprising given the rise in COVID cases. So, right now, projected January volumes are currently estimated to be down about 13% versus January of 2020. Next week in the investor conference, we'll take you through all of our 2020 budget assumptions and detail, including our refined product volume assumptions. Crude and condensate volumes were down about 26% in the quarter versus 2019, and down about 6% over the third quarter. The one bright spot similar to what we saw in natural gas gathering was in the Bakken, where crude gathering volumes were up slightly. In terminals, refined product volume throughput continued to reflect reduced demand due to the pandemic, but they've recovered since the second half of this year. The impact of throughput volumes on this segment is mitigated by our fixed take-or-pay contracts for tank capacity. Our liquids utilization percentage, which reflects the percent of tanks we have under contract, remains high at 95%. If you exclude the tanks out of service for required inspection utilization is 98%. Given the pandemic, we did see some weakness in our Jones Act tanker business but that was offset by incremental earnings from expansion projects. The bulk side of the business, which accounts for roughly 20% of the terminals' earnings, saw a strong rebound in steel volumes. Industry-wide mill utilization improved to over 70% from the lows of 50% in the second quarter. In CO2 oil production was down approximately 16% and CO2 sales volumes were down about 35%. Our team has done a tremendous job here of adjusting to the current environment finding cost savings and cutting non-economic CapEx to more than offset the degradation in segment performance. As a result, full year 2020 DCF less CapEx for the segment of $466 million was over $100 million better than 2019 and over $40 million better than budget. The last thing I'll point out for you is that for the full year, we were only off $10 million versus the DCF guidance that we gave you in April when the pandemic began. There were lots of puts and takes for sure and EBITDA was slightly weaker, but amazingly close overall. And with that, I'll turn it over to David Michels.

Thank you, Kim. For the fourth quarter of 2020, we are declaring a dividend of $0.2625 per share or $1.05 annualized, which remains the same as last quarter and represents a 5% increase from the fourth quarter of 2019. In comparing the fourth quarter performance of 2020 to 2019, it's important to note that 2019 included several specific items related to gains or losses from divestitures and impairments, as well as earnings losses from equity investments and higher income expenses, which essentially balanced each other out. Consequently, the revenues in the fourth quarter of 2020 were $237 million lower than in 2019, which was mitigated by reductions in O&M expenses, depreciation, and interest, leading to a net income attributable to KMI of $607 million, roughly the same as Q4 2019. Our adjusted earnings of $604 million also remained flat compared to Q4 2019, while the adjusted earnings per share rose slightly to $0.27, an increase of $0.01 from the previous year. Regarding DCF, there was a decline of $59 million in natural gas contributions, largely due to the sale of our Cochin pipeline and decreased contributions from various gathering and processing assets, though this was partially offset by improved contributions from our Texas Intrastate systems and expansion projects. The products segment saw a decrease of $64 million, primarily caused by reduced refined product volumes and lower crude and condensate volumes as a result of ongoing demand impacts from the pandemic. The terminal segment also experienced a drop of $32 million due to the sale of KML and lower contributions from refined products and our Jones Act vessels, although some of these losses were offset by contributions from expansion projects. Our CO2 segment dropped by $18 million because of lower oil and CO2 sales volumes, despite lower operating costs and improved pricing year-over-year. This resulted in adjusted EBITDA of $183 million, which is a 9% decrease from Q4 2019. Below EBITDA, interest expenses were favorable at $63 million, driven by lower floating rates benefiting our interest rate swaps, along with a reduced overall debt balance and lower long-term debt rates. Sustaining capital came to a favorable $30 million, largely due to deferrals in the terminals segment. Additionally, we saw increased cash pension contributions in Q4 2020 compared to Q4 2019. The total DCF for the period was $1.25 billion, down $104 million or 8%, with DCF per share at $0.55, which is down $0.04 from the previous year. Looking at the balance sheet, we closed the year with a debt-to-EBITDA ratio of 4.6 times, consistent with last quarter and up from 4.3 at year-end 2019. We ended the year with $1.2 billion in cash, which will help manage our maturing debt throughout this year. We have already utilized some of that cash to repay $750 million of debt due in the first quarter, leaving us with $1.65 billion of debt maturation remaining for the rest of the year. We are in a strong liquidity position, with an undrawn $4 billion credit facility, and we anticipate generating $1.2 billion of DCF after CapEx and dividends in 2021. Our net debt at the end of the quarter and the year was $32.0 billion, down nearly $900 million from year-end and $556 million from the last quarter. As mentioned, our net debt has decreased by $10.8 billion since the first quarter of 2015. To explain the quarterly change in net debt, we had $1.25 billion of DCF, paid out $600 million in dividends, contributed $250 million for growth capital, received $200 million from asset sales, and experienced a working capital use of $50 million, which accounts for most of the $556 million change in net debt. From year-end 2019 to year-end 2020, we generated DCF of $4.597 billion, had a $900 million share sale from Pembina in Q1, recorded $200 million from asset sales, paid $2.37 billion in dividends, and made $1.65 billion in growth capital contributions. We also accounted for $260 million in taxes from the Trans Mountain sale and Pembina shares, repurchased $50 million of KMI shares, and had a working capital use of $385 million for the year, which explains the majority of the $989 million decrease in net debt for the year. That completes the financial review for the quarter. Back to you, Steve.

Okay. So Denise, we'll open it up for questions now.

Hey, Jeremy.

Hi. Good morning. Hi, good afternoon. Thanks for taking my question here. Just want to start off with a high-level question here. And you've laid out some pieces for kind of dividend growth expectations. But just wondering capital allocation philosophy overall, if you could refresh us on how you're thinking about that, when it comes to dividend increases versus buybacks? And also it seems like the market's continually looking for lower leverage here so that the multiple can be attributed more to the equity side than the debt side. So just wondering how those different things work together. And the industry still seems ripe for consolidation so wondering if you could refresh us on that?

We have done significant work on our balance sheet and believe we are in a strong position with our BBB flat rating and the net debt reductions we've achieved over the years, including this year. We are confident in our standing, but in considering further debt reduction for a potential upgrade, we do not see much benefit for our equity investors in terms of cost of capital. Therefore, we believe we are well-positioned, which allows us to think about expansion capital projects. We are focused on funding high-return projects that exceed our weighted average cost of capital. However, opportunities for such projects are fewer than in the past, so we are selectively funding those that make sense, while also retaining a significant amount of cash. As a result, we have increased our dividend from $1 to $1.05 and now expect it to reach $1.08 for 2021, alongside allocating up to $450 million for share repurchases. We believe we have made sound decisions regarding our balance sheet. We prioritize funding initiatives that create value for the firm and refrain from pursuing projects that do not make sense. In terms of returning cash to shareholders, we recognize that while dividends provide a reliable return, they lack flexibility. Thus, we have chosen to prioritize share buybacks for that flexibility. Regarding consolidation opportunities, we remain attentive to these prospects, as the industry has been primed for consolidation for quite some time. However, any potential consolidation must meet several criteria: it should deliver genuine value to our investors, involve businesses we can operate safely and efficiently, be accretive, and avoid negatively impacting our balance sheet. Our commitment to this discipline remains strong.

Got it, very helpful. And then maybe just one last one on ESG side, if I could. Just wondering in your conversations with the ESG raters with ESG investors do you think they see the role for natural gas and energy transition the same way that you guys have outlined it here? Do they buy into that? And do you guys have internal views I guess on Scope three emissions how natural gas compares to renewables? And when you have these conversations with those stakeholders do they see things similar to you guys?

Yes, there is a lot of diversity in how people evaluate this. The ratings indicate that we are effectively communicating our ESG measures and managing our ESG risk. Our rating reflects how we manage ESG risk rather than just having a strong ESG report. Many recognize the necessity of natural gas and the environmental benefits it has provided over the years. For instance, our annual CO2 equivalent emissions dropped from 6 gigatons in 2017 to 5.1 gigatons now, with a significant contribution from natural gas in power generation, despite economic growth during this period. While not everyone holds this view, we are proud of our progress and actively engage with investors, addressing their questions and concerns. You raised a good point regarding Scope 3 emissions. One enduring advantage of hydrocarbons is their energy density, allowing a substantial amount of energy to be generated from a relatively small physical and capital footprint—think of a natural gas power plant compared to the vast number of solar panels and windmills required for the same output, which come with considerable manufacturing and disposal costs. Eventually, I believe public discourse around ESG will expand to include these considerations for renewables, which could align the environmental impact of natural gas more closely with them. We collaborate with renewable companies and utilities enhancing their renewable portfolios, and we see our business as playing a crucial enabling role in this transition. However, the full narrative surrounding natural gas is more comprehensive when all factors are considered.

That's very helpful. I’ll stop there. Thank you.

Hey, afternoon everyone and Happy New Year. Just wanted to follow-up on Shneur's first question. Just looking at the macro outlook and the improvement since you all guided to in December. And so I'm just curious if producers have changed their tone or their attitude on growth at all since that time? I know Kim you mentioned ongoing discussions in the Haynesville. Curious if you're seeing positive momentum elsewhere since December? And then maybe how you think about the direction of CapEx next year if we do see increased activity?

Sure. I think the situation varies depending on the basin. In the Bakken, we've had a positive start to the year, and we ended the fourth quarter slightly better than expected. The year is progressing well. The Eagle Ford continues to lag behind. In the Permian, the rig count has increased since we hit the lows in August, and we are approaching a rig level that could return us to the volume levels we experienced before the pandemic. However, this won't happen immediately and will require time. Regarding producers and their guidance, I believe they need to feel confident that crude prices will remain strong for an extended period. Currently, the Saudis and others are withholding substantial barrels from the market, which contributes to price uncertainty. Additionally, producers are very focused on free cash flow, so it's uncertain how much they would increase capital expenditure in response to rising prices. There is still much to observe as the year progresses.

Okay, fair enough. Second question on ESG. Steve, I appreciate your comments there and laying out some of those new items and initiatives. I just want to focus specifically on the ones that would require a bit of a step out on your part that a much maybe higher return hurdle line if they're there. Just wondering on the ESG strategy do you contemplate M&A being a part of that specifically, or do you feel like you have enough of the internal core competencies to execute that organically? And then just quickly related to this in terms of timing how should we be thinking about the timing of when those initiatives start to materialize and actually start to really show up in the CapEx budget?

Okay. Yes. So, I distinguish between several different kinds of opportunities. When you think about responsibly sourced natural gas, it's something we're out there marketing today. When you think about blending hydrogen in to the extent that that becomes available or moving renewable natural gas which is something that we already do today the quantities are very small. But when it comes to originating and doing that kind of business we're already very well fixed to do that within our existing business units. That extends also to things like additional renewable liquid fuels like renewable diesel where both in our products group and in our terminals group we are actively looking at and pursuing opportunities there today. And it's in businesses that we understand that we know how to do and that we can help our customers get where they're going. When it comes to the further step outs, I think our approach is going to be again very conservative. We're going to look at the things that are adjacent to us that we think makes sense for us to do. And we think that we can do that with folks in our organization and with us taking and continuing to take a hard look at some of those opportunities, wouldn't rule out M&A. But I think that's an area where you can move to more quickly than is prudent. And we're going to be prudent in how we approach it. And so I think it's more organic, but M&A or acquisitions wouldn't be off the table for the right opportunity. But I'm purposefully emphasizing organic using the tools the assets the people and the opportunities that we have.

Okay. Thanks for the time, guys. Appreciate it.

Hey everyone. I wanted to ask about Hiland being up 20% versus third quarter. I think that's quite a bit more than overall Bakken gas was up quarter-on-quarter, but maybe you were down more on year-on-year. Do you have a sense if it was your specific acreage that really moved up? And can you maybe just give a sense so I can calibrate of where Hiland volumes were in fourth quarter versus say first quarter before COVID?

Sure thing. Tom Martin you want to address that? Tom, are you there or are you muted?

Okay. He's showing disconnected? Okay. Yes. So, we did have a nice uplift in gas volumes on Hiland. So, the story on Hiland as you look through the year there was a significant downturn in the second quarter as we had and this was all talked about publicly. But we had a significant producer there go through a large amount of shut-in on their particular acreage. And then, when things came back they came back nicely. And some of that from shut in some of it from flush production. And those volumes have continued to be strong. But there's no question that some of that was aided by the turnaround in what our producer was doing up there one of our large producers. Kim, anything else to add?

Yeah. And I mean, you're not quite back to first quarter 2020 volumes in the fourth quarter of 2020.

Sure. But you would say that, your market share is so to speak is similar to where it was before?

I don't have a specific…

Yeah. I don't know on the market share how our producers performed relative to how they brought back volumes relative to others.

And I will say, I mean, we've – as we've looked at our producer activity or stated producer activity, where we are now what we're expecting versus what's being reported for Bakken production, it does seem that we and our customers are doing better than just the overall reported numbers for Bakken.

Got it. Okay. Great. I think that's kind of what I was after. And then as a follow-up, you mentioned, weakness in the quarter in Jones Act tankers. Can you expand on that a bit? I believe during the second quarter Jones Act tanker rates went up quite a bit and then have come back down. But what's the customer appetite for re-contracting today in that market?

Yeah. And I'll call on John Schlosser to add a little more detail. But what I'll tell you is that we – John and the team were really nicely positioned for what you were just talking about meaning that, we were going to have vessels rolling off charter right as charter rates were improving, which is where things were headed based on the overall supply and demand fundamentals there. And then the pandemic happened. And so, as you saw in other refined products, volumes and demand for refined products movements, we saw that – we saw that come off and come off relatively hard. Now over the longer term, there aren't new Jones Act vessels that would compete with our MRs anyway that are being built right now. We think that that market does come back into balance over time. But it has created some short-term weakness in demand. Beginning to see some nice uptick in inquiries, and calls for quotes, as we've gotten into 2021, but we did take a reduction there. Now I would say, overall Jones Act vessels are running probably – again this is a pandemic number, Jean Ann so not representative of call it normal refined products operations, but call it 25% off higher. We're about half of that meaning about 12.5%. So better, but we have some expirations coming up over the course of 2021. So, what will really drive this business is, post pandemic recovery in refined products movements. John?

You're correct. The 25% number is for the entire industry. So, we're seeing about 25% of the total tanker volume out. We had maneuvered our way very well through the year and had it boarded that. For the year, we're up $2.3 million, but we did see an impact on two of our vessels, the Lone Star and the Pelican in Q4, which amounted to a negative impact between that and some price compression of about $6.7 million negative in Q4. But we are seeing some green shoots. We're seeing more inquiries here over the last couple of weeks. And we believe that that 25% is overblown and should come back as the year goes on.

Thank you very much.

Good afternoon. So, I think historically, the team has highlighted that you would not expect to pay corporate cash taxes until sometime after 2026. Can you just update us on current thinking given the lower capital spend? And if you have any preliminary thoughts on how that might change in the event that we see a corporate tax increase? I would appreciate those thoughts as well.

Yeah. That's still good guidance. And it doesn't really change with a corporate tax increase, because what we're describing there is NOLs which for that period that we've talked about, which is beyond 2026 more than offsetting taxable income. So, it's less driven by – not driven by the rate. David, anything you want to add there?

No. You covered it, Steve.

Okay. And so, with the lower capital spend still no change there?

That's right. No change to that guidance.

Got it. Okay. And then with Permian Highway now online and Waha pricing much closer to Gulf Coast hubs, can you frame for us the impacts on the interruptible portion of the intrastate business there?

Can you provide more details about the interruptible portion of the intrastate business?

So, thinking the non-contracted portion of the intrastate. So to the extent that you are moving just on a fee-for-service maybe a month-to-month evergreen contract, or you are moving actual basis spreads and take advantage of a bit of marketing opportunity. Just trying to understand, how we should think about that portion of the business now with where Waha is pricing?

We were transitioning to interim service on PHP while we were commissioning compressor stations. We delivered volumes on PHP for November and December until it was fully commissioned and in service, at which point we took nominations under long-term firm contracts that began on January 1. We're also involved in buying and selling gas. I understand your mention of interruptible; much of that business is technically interruptible, although it generally runs smoothly. We're optimizing our Texas Intrastate network, which includes long-term transportation arrangements, including those that PHP shippers hold downstream to reach delivery points. Additionally, we have made transportation agreements with producers and end users to connect production to power plants and other facilities. Currently, we're seeing an additional two BCF a day coming onto our system from two years ago when we launched GCX, along with another two BCF from Whistler. This influx will significantly enhance the amount of natural gas we provide, improving connectivity within our Texas system. The Waha spread has narrowed now that the contracted pipeline system is operational. It will take time for the market to adjust, even with additional rigs returning, as prices in 2022 were significantly higher than what we're experiencing in 2021. We expect that system to be fully utilized and for prices to widen out by the middle of the decade, necessitating additional transportation capacity. Overall, the new facility is under contract and will bring more natural gas to our system, benefiting our existing operations. Did I address your question?

Colton also was asking about, do we have significant business that is subject to that spread, and therefore, because that spread came in we're going to take a hit in EBITDA? And generally, Colton, the way that we contract is we're contracting on a back-to-back basis. And so, we are not generally taking spread risk. And so, the impact of that spread coming in is not going to have a material effect on us.

Understood. That’s helpful.

Yes.

Hi, good afternoon guys. Kim, I appreciate your comments on what you're seeing in January across products. Curious of the fourth quarter commentary around diesel growth year-over-year. Can you talk about that strength either regionally or what you're seeing on the demand recovery side with respect to diesel?

We believe that the increase is primarily due to the rise in online orders and home deliveries. When we compare this to gasoline volumes, those are down. We've observed this trend for a couple of quarters now, and we attribute it to the movement of 18-wheelers transporting goods to various locations and homes.

Great. Yes, I was just trying to make sure there wasn't some specific item or one specific region. That's helpful. And then a quick follow-up just on the Hiland on the crude side. Can you talk about generally just conversations with customers around capacity availability for egress either working with you guys around making contingency plans in the event the basin sees disruption of the major pipeline there or taking on additional contracts with Kinder Morgan, et cetera?

Dax you want to comment on that?

Yeah, yeah. I think overall they're positive and the volume trends we're seeing are positive. We were fourth quarter on Double H. We were about 64 day out of total capacity of about 88. Right now for January, we're looking to be pretty close to the full level. So conversations, I mean, look we have absolutely no idea of what's going to happen with that one and certainly wouldn't speculate on that. But the conversations overall were constructive and we're seeing it in volumes.

Thank you, guys very much.

Thanks. Good afternoon, everyone. I wanted to go back to the Permian natural gas market. You guys commented that El Paso natural gas saw a reduction in volumes. I just wanted to understand that a little better. Is that a result of PHP coming on, or is there weakening demand in California? I just wanted to better understand the dynamics there.

Yes. And so Tom Martin got kicked off the call before the earlier question and he's back on. And so I'm going to ask him to respond. Tom?

Yes. I think the answer to that question is it's a combination of both really just weaker demand in California as well as increased outlets for Permian supply locally if you will had some impact on our volumes on EPNG. Again, I think, once – I think much of that was seasonal related out West. So assuming we get good demand in 2021 out in California we think that likely recovers a bit.

Okay. Great. And just a follow-up on that point. Would you say that that's a long-term secular trend in terms of declining demand into California, or do you think it's going to just remain seasonal and weather-dependent?

Well I think how we serve California is changing obviously with the renewable growth there. So volumes long term may not be as strong especially to Northern California. But I think the amount of capacity need into that market probably actually grows over time as more renewable penetration increases in that area.

Thank you for taking my question. Just one question today for me. Steve in your prepared remarks you mentioned carbon capture as a potential business opportunity for Kinder Morgan. And it sounded like in your prepared remarks that the economics for carbon capture are not favorable at this time. So I was just curious what it would take to make this a more attractive business for Kinder Morgan. And the reason I ask is Kinder has a real expertise in CO2 and this seems like a natural outgrowth of your business and something that you would have a competitive advantage in. So I'd love to just get your overall thoughts on that carbon capture opportunity.

Yes sure. There's quite a hierarchy there. And so, if the recently published regulations on 45Q do make certain parts of the carbon capture opportunity, more economic win used in combination with enhanced oil recovery. And so the allowance, the tax credit allowance for EOR at the rate now approved makes things like gas processing, ethanol facilities more economic and may be economic. And that's an opportunity for us. There's nothing specific right now or deal-specific to talk about there. But it's gotten a lot closer and may actually be economic. And so as we look at it from our business standpoint from our business perspective, we do have in our treating business today, which is just standard, long existing aiming technology to separate CO2 from – whether it's a gas stream or a process facility separated it then also has to be captured. And the purer the stream the better, right? So it's purer in things like processing facilities and ethanol facilities. It's got to be captured. It's got to be powered up. It's got to be transported, which is where we come in. And it's got to be put in the ground and stay there which is also where we come in. And better still you get oil from it and that helps make the whole thing work. And so we're beginning to see some of those applications creep into economic territory. And then marching up from there to things like capturing it from power plants and from other industrial uses that gets more expensive and then direct air capture is extremely expensive given the very low concentration. So CO2 in the atmosphere about 0.04% versus from a flue stream run from between 3% and 20%. So 75 to hundreds of times more economic from the flue stream. So we're just kind of on the edges of that now starting to see some things that are getting interesting. Jesse anything that – anything you want to add?

I think you've covered it Steve. Thanks.

Thank you, Steve. Appreciate it.

Good afternoon. Thanks for taking my question. I just wanted to first follow up on the Permian gas. Do you believe there will likely be more takeaway in Permian next year after the Whistler and some other smaller projects come online? I wanted to follow up on where the discussions on adding third gas pipe in the Permian stand the Permian pass. And what is the competitive environment like for that?

I'll begin, and then Tom can add on. It's not happening anytime soon; it won't be this year or next year. Based on third-party analyses and our own internal assessments, we foresee demand starting to develop around 2025. Companies will likely want to prepare for that, especially considering the time it takes to construct pipelines, even in Texas. We anticipate engaging with stakeholders before then to ensure we can have something operational by around the middle of this decade. We believe we have several advantages in this regard. First, we possess an excellent pipeline network in the Texas Gulf Coast region. Our focus is on getting supply to market, which increasingly involves delivering to LNG markets, exporting, and finding applications in the expanding petrochemical and industrial sectors along the Texas Gulf Coast. We've proven our capability to complete projects even in more challenging situations than what we expect for a Permian pipeline. Therefore, we feel we are well-positioned. However, that's not a guarantee. It's still some time away, but we are in discussions with various long-term planners within the producer community and will keep those conversations going. But again, it's still a long way off. Tom?

Yes, really nothing more to add there. I think just the trajectory of growth and the rig activity in the Permian will tell us a lot over the coming months and a couple of years.

Thank you for taking my question. I actually have two, and I'll ask them in the interest of time. First, you did a good job managing costs in 2020, particularly in G&A and possibly other areas as well. Can you share what the expectation is for 2021? Do you anticipate some of those costs to return, or is this a permanent reduction? Secondly, on a policy note, we're noticing some states starting to take actions regarding the future demand for gas-regulated utilities, aiming to restrict or limit demand growth from these utilities. I'm curious about your thoughts on how this could impact your business going forward, particularly since it seems to be more prevalent in certain East Coast and West Coast states.

Thank you, Michael. Regarding costs, the adjustments we made as part of our efficiency project are permanent. We’ve reduced structural labor and other costs. Each budget undergoes a thorough review, and cost requirements may change based on emerging factors like regulatory or maintenance needs. However, the work we did was intended to be long-lasting. We will provide more details at the conference, with costs being fairly evenly split between segments and corporate expenses like G&A. On the policy front, we are monitoring it with some concern. While we are not directly involved in how states are approaching their gas end users, it's primarily an issue in limited areas, focusing on new construction and homebuilding. Developers prefer homes that feature natural gas appliances, so this may lead to pushback. For instance, we've observed restaurant owners responding negatively to these policies, and one community successfully resisted an attempt to eliminate natural gas usage. In another instance, a jurisdiction faced challenges in establishing natural gas infrastructure, but when the unavailability of natural gas to end users became clear, there was a reversal in support for additional natural gas supply. There are still many developments to monitor, and while the issue is narrow, it is something we consider important and beneficial for society to evaluate closely.

Got it. Thank you, guys. Much appreciated.

Yes. Thank you. I had a follow-up. Two questions that was asked earlier on the whole renewables, the hydrogen, the biodiesel fuels push. Just kind of curious, obviously, look, sounds great when you talk about it, but kind of what inning are we really in here in terms of when you think this could actually meaningfully add to your cash flow? When do you think some of these CapEx expenditures are going to show up? And then what's involved in terms of getting some of these projects from conception through completion?

Okay. That's the ultimate question. We're at different stages with various initiatives. For example, with responsibly sourced natural gas, we're already engaged and speaking with customers about it. Some of our LNG customers find this important. As a low-methane emissions storage provider, we've achieved our one future goal seven years ahead of schedule, and our sector's allocation was 0.30%, while we're at 0.03%. We have a lot of positive initiatives to present to customers. Our gas storage serves as a reliable backup for renewables and is likely the most cost-effective energy storage solution compared to batteries. We're currently well-positioned in renewable diesel as well. In California, the entire market benefits from a low-carbon fuel standard, and our customers are eager to know what we can provide them today. We're discussing renewable diesel hubs where we can build out capacity for strong returns and good customer service. While it may take longer in other regions, as low carbon fuel standards expand, interest will grow. On the topic of hydrogen, it shows promise but has been labeled the fuel of tomorrow for many years. It requires time and potentially subsidies to become viable. Currently, it costs $19 per MMBtu. Hydrogen will likely play a role in meeting energy needs, but it involves converting high-quality energy like electricity into hydrogen through electrolysis and then using it as a transport fuel before converting it back to electricity in a fuel cell. There's much work to do to make this practical, but it could become feasible with the right support and incentives. As Kim pointed out, those willing to invest can blend hydrogen into our existing system now, which can be appealing for those leading the energy transition. If it were ready next year, we could integrate it into our pipelines. It ultimately comes down to our approach and being discerning about what's actionable now versus what’s further down the road. We're focused on what we can do today and tomorrow with our current assets and businesses while also looking ahead, ensuring a disciplined approach for different energy initiatives.

Okay. I really appreciate that. As a follow-up, I want to focus on hydrogen. How do you see the hydrogen environment developing for midstream players? Do you think there will be opportunities for just a couple of companies, or is there potential for a larger group? Also, what is Kinder Morgan's competitive advantage in the hydrogen value chain?

I'll start with the last. I think our competitive advantage is in the existing network we have and the existing customer relationships that we have. Meaning, we are serving a lot of customers who would be taking blended hydrogen, whether that's on an industrial or a power plant or an LDC for example. We're serving those customers today on the network that we have today. And so that's really our advantage. In terms of how broad the opportunity is likely to be, I would say, looking at it right now, it looks like it will be pretty broad. I mean it doesn't look like to your point there's really a dominant player there. One might emerge, of course, as it could be the case in any business, but there doesn't appear to be one now. Right now, I think it's still in the thousand flowers blooming stage.

Okay. I appreciate it. And I'll be back next week for some more questions, but appreciated it for now.

Thank you.

Hi everyone. I wanted to follow up on a previous question regarding the volume change on EPNG. Reflecting back to 2018, before the issues with the Waha spreads arose, I remember you invested some capital that yielded high returns to address those spread challenges. The idea was that once the PHP Gulf Coast started operating, those opportunities would diminish. Are we observing that now, or is it a seasonal effect in response to the question? I’m trying to clarify if the decrease in temporary earnings was anticipated, as it was very profitable at that time.

Okay. Tom Martin?

Yeah. I mean, I think the macro response I gave is probably the bigger picture answer. I think there were clearly some very lucrative opportunities early on. We captured those opportunities by spending a little capital doing some term contracts on those. And clearly as those deals come up for re-contracting they'll be a bit lower. But again we're not talking about material dollars here. I think really the bigger picture answer is the one that matters the most. And it's the macro fundamentals that I described earlier.

Okay. Got it. Thank you very much. I appreciate the colors. Thank you.

Thank you very much. Have a good evening.