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Energy Transfer LP (NYSE: ET) Third Quarter 2021 Earnings Conference Call, November 3, 2021 4:30 PM Eastern Time
Ladies and gentlemen, good afternoon, thank you for your support. Welcome to the Energy Transfer third quarter earnings conference call. [Operator Instructions] Please note that this meeting is being recorded. I will now transfer the meeting to your host, Tom Long, Co-CEO of Energy Transmission. Thank you.
Tom Long-Co-CEO
Thank you, operator. Good afternoon, everyone, and welcome to the Energy Transfer 2021 third quarter earnings conference call. Thank you for joining us today. Today, Mackie McCrea and other members of the senior management team joined me as they helped answer your questions after our prepared speech. Hope you have seen the press release we issued earlier this afternoon, as well as the slides posted on our website.
As a reminder, we will make forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. These statements are based on our current beliefs, as well as certain assumptions and information currently available to us, and are discussed in the quarterly Form 10-Q for the quarter ending September 30, 2021, which we expect to submit tomorrow, November 4 This is explained in more detail in the report. I will also refer to adjusted EBITDA and distributable cash flow, or DCF, all of which are non-GAAP financial measures. You can find the reconciliation of our non-GAAP measures on our website.
I want to start today and look at some of the highlights of our third quarter. We generated an adjusted EBITDA of US$2.6 billion and DCF attributable to energy transfer partners, which is US$1.3 billion after adjustment. Our excess cash flow after distribution is approximately US$900 million. On the basis of what has happened, after allocating USD 414 million and approximately USD 360 million of growth capital, we have approximately USD 540 million of excess DCF.
In terms of operations, our NGL transportation and fractionation and NGL refined product terminal volumes set a new record this quarter, mainly due to sales growth, surpassing our Mont Belvieu fractionation tower and Nederland terminal. As the market continues to recover, we are in a good position to benefit from growing demand and higher profit margins. The switch to the latest news of the acquisition of Enable Midstream Partners will expand the scale of the Mid-Continent and the Ark-La-Tex region and provide our natural gas and NGL transportation customers with better connectivity. We look forward to the combination of energy transfer and complementary assets that will enable us to provide our customers with flexible and competitive services as we seek more business opportunities with our improved connectivity and increased footprint.
As a reminder, we expect that the combined company will generate more than $100 million in operating cost synergies per year, which precedes potential commercial synergies. We still believe that the transaction will be completed before the end of the year. I will now take you to the latest developments in our growth project, starting with our Cushing South pipeline. At the beginning of June, we started to provide transportation services for approximately 65,000 barrels of crude oil from Cushing Dock to Dutch Dock, providing access to the Dutch Dock for barrels in the Powder River and DJ Basin as an upstream connection to the White Cliffs Pipeline.
The pipeline has been fully utilized. As we mentioned in the last conference call, we are advancing the second phase, which will increase production capacity to 120,000 barrels per day. The second phase is expected to be put into use at the beginning of the second quarter of 2022, and is supported by third-party commitments. As a reminder, the capital expenditure required at this stage is minimal.
Next, the construction of the Ted Collins link is underway and is now expected to be put into use by the end of the first quarter of 2022. The Ted Collins link will allow us to fully load and export unmixed low-gravity Bakken and WTI buckets. The Houston market demonstrated Energy Transfer's unique ability to provide net bucken barrels to the Gulf Coast market. Now turn to our Mariner East system. We have commissioned the next important phase of the Mariner East project, which brings our current capacity on the Mariner East pipeline system to approximately 260,000 barrels per day.
Year-to-date, the volume of NGL passing through the Mariner East piping system and Marcus Hook terminal has increased by 12% during the same period in 2020. We are waiting for the issuance of a license modification to convert the final directional drilling rig to open cutting, which will allow us to put the last part of Mariner East into service in the first quarter of 2022. , This winter will begin to move refined products. Now briefly introduce our Dutch terminal.
As a reminder, with the completion of the remaining expansion of our LPG facility in the Netherlands, earlier this year, we are now able to export more than 700,000 barrels of NGL per day from our Dutch terminal. Coupled with the export capacity of our Marcus Hook terminal and our Mariner West pipeline for exporting ethane to Canada, our total NGL export capacity exceeds 1.1 million barrels per day, the largest in the world. In our expanded Dutch terminal, NGL production continued to increase in the third quarter, including the export volume of our Orbit ethane export joint venture, which has remained strong. From year-to-date to September, we have loaded more than 16 million barrels of ethane from this facility.
Overall, our percentage of global NGL exports has doubled in the past 18 months to nearly 20%, which is more than any other company or country in the third quarter of 2021. Looking ahead, we expect our total NGL exports from the Netherlands to continue to increase throughout the next year. In addition, the supply demand for refineries remains strong, and our crude oil inventory in the Netherlands has been fully contracted. In Mont Belvieu, we recently introduced a 3 million barrels high-speed storage well, which brings our NGL storage capacity in Mont Belvieu to 53 million barrels.
Our Permian Bridge project connects our acquisition and processing assets in the Delaware Basin with our G&P assets in the Midland Basin. It was put into use in October and has already been heavily utilized. This project allows us to transport approximately 115,000 Mcf of rich gas daily from the Midland Basin and operate our existing capacity more efficiently, while also providing additional takeaway options. In addition, it can be easily expanded to 200,000 Mcf per day if needed. Finally, in July, we announced the signing of a memorandum of understanding with the Republic of Panama to study the feasibility of jointly developing the proposed Trans-Panama Gateway pipeline.
We believe that this project will create the most liquid and attractive LPG supply center in the world, and we are excited about the opportunities it brings. Now to introduce the latest situation of our alternative energy activities, we continue to make progress in many aspects. In September, we signed a 15-year power purchase agreement with SB Energy to provide 120 MW of solar energy for its Eiffel Solar project in northeastern Texas. This is the second solar project we have participated in, and these agreements provide a good fixed price per MWh.
Therefore, we only pay for the electricity that is actually generated and delivered to us. We are also continuing to explore several opportunities for solar, wind, and forestry carbon credit projects on existing land in the Appalachian region. In particular, we will continue to work with a large utility company to jointly seek solar and wind energy development on the Energy Transfer track in Kentucky, and we are in discussions with other large renewable energy developers. In terms of carbon capture, based on preliminary cost estimates and design feasibility studies, our Marcus Hook project looks financially attractive.
The project will involve capturing carbon dioxide from flue gas and delivering it to customers for industrial applications and for use in the food and beverage industry. We have also carried out several carbon projects related to our assets, including projects involving the capture of carbon dioxide from processing plants for enhanced oil recovery or storage. We still believe that as we continue to reduce our carbon footprint, our franchise will enable us to participate in various projects involving carbon capture or other innovative uses. Finally, we expect to release our annual corporate responsibility report for our website soon.
Now let us take a closer look at our third quarter results. Consolidated adjusted EBITDA was US$2.6 billion, compared to US$2.9 billion in the third quarter of 2020. The adjusted DCF attributable to partners in the third quarter was US$1.31 billion, compared to US$1.69 billion in the third quarter of 2020. Although we have seen higher transaction volumes in most of our market segments, including record sales in the NGL and refined product segments, these gains did not offset the significant gains related to our various optimization groups in the third quarter of 2020. To optimize revenue, and our midstream one-time revenue portion of 103 million US dollars.
In addition, the third quarter of 2021 includes higher utility costs and other costs associated with winter storm Uri. On October 26, we announced that the quarterly cash distribution per common unit was US$0.1525, or US$0.61 on an annual basis. The distribution will be paid on November 19 to unitholders of record as of the close of business on November 5. Turning to our segment performance, we will start with NGL and refined products.
Adjusted EBITDA was US$706 million, compared with US$762 million in the same period last year. The increase in terminal service and transportation margins related to the increase in throughput of the Nederland and Mariner East pipelines in the third quarter of 2021 was offset by a reduction of US$55 million in our optimized business in Mont Belvieu and the Northeast, as well as increases in operating expenses and G&A. We are all The NGL transportation volume of capital and joint venture pipelines increased to a record 1.8 million barrels per day, compared with 1.5 million barrels per day in the same period last year. This increase was mainly due to the increase in exports into our Dutch terminal after our propane and ethane export projects started service, the increase in exports in the Eagle Ford area, and the increase in exports of our Mariner East and Mariner West pipeline systems.
Our fractionation tower also set a new record this quarter, with an average fractionation volume of 884,000 barrels per day, compared with 877,000 barrels per day in the third quarter of 2020. Throughout 2021, we continue to add capacity to our system and it works well-as demand improves, we can capture more sales and take advantage of new opportunities. For our crude oil division, adjusted EBITDA was US$496 million, compared with US$631 million in the same period last year. Due to the recovery of production in the third quarter of 2021, the performance improvement of our Bakken and Bayou Bridge pipelines did not offset the approximately US$100 million one-time project in the third quarter of 2020.
In addition, we reduced approximately US$20 million in other optimizations, and increased operating expenses and G&A expenses year-on-year. For the midstream, adjusted EBITDA was US$556 million, compared to US$530 million in the third quarter of 2020. This is mainly due to favorable NGL and natural gas prices, and sales growth in the Permian and slopes related to the increase of 156 million US dollars-the recently completed asset increase in the Northeast region partially offset due to the third quarter of 2020 in the Ark-La-Tex region. The reduction of USD 103 million due to the reorganization and transfer of these contracts. The amount of natural gas collected was 13 million due to increased transaction volumes in the Permian, Ark-La-Tex and South Texas regions, compared with 12.9 million MMBtus per day in the same period last year, MMBtus per day.
The water volume in the Permian Basin continues to be strong, and the water volume at the Midland inlet remains at/or close to historical highs. Therefore, we are already using our Permian Bridge project to increase our processing efficiency in the area by transferring some volume to our Delaware Basin processing plant. In our interstate division, adjusted EBITDA was US$334 million, compared to US$425 million in the third quarter of 2020. This was mainly due to the expiration of the contract between Tiger and FEP at the end of 2020, and the bankruptcy of Tiger’s shipper and Panhandle And due to more favorable market conditions, Rover's increase in transportation volume partially offset the mainline. For our state sector, adjusted EBITDA was $172 million, compared with $203 million in the third quarter of last year.
This is mainly due to the transfer of long-term contracts by third-party customers from the Permian to the Gulf Coast, resulting in reduced optimization volume, lower spreads, and increased operating expenses. This was largely offset by the increase in transportation. Leaving the Permian, reserved Fuel revenue and storage profit increased. Although it had an impact on us during the comparison period, we are expected to benefit from additional long-term contracts with third-party customers from the Permian to the Gulf Coast due to the significant tightening of Waha and Katy basis. In order to reduce the volatility of our earnings and protect us from the decline in basis, as we have seen from the third quarter of 2020 to the third quarter of 2021, we have strategically taken measures to lock in long-term fee-based contracts The additional transaction volume under this is surpassing the current difference. Now turn to our 2021 adjusted EBITDA guidance.
Our adjusted EBITDA for the full year of 2021 is still US$12.9 billion to US$13.3 billion. As a reminder, this scope does not include any contributions from the announced Enable acquisition. Turning to growth capital renewal, in the nine months ending September 30, 2021, Energy Transfer spent US$1.08 billion on organic growth projects, mainly in the area of NGL refined products, excluding SUN and U.S. capital expenditure reduction. For the full year of 2021, we continue to expect growth capital expenditures of approximately US$1.6 billion, mainly for NGL refined products, midstream and crude oil sectors.
After 2022 and 2023, we expect to spend approximately US$500 million to US$700 million per year. Now briefly introduce our liquidity situation. As of September 30, 2021, the total available liquidity under our revolving credit facility was approximately US$5.4 billion, and our leverage ratio was 3.15 times each credit facility. In the third quarter, we used operating cash to reduce outstanding debt by approximately $800 million.
So far this year, our long-term debt has been reduced by approximately $6 billion. In the past few years, we have done a lot of heavy work. We have worked hard to accelerate debt reduction, increase leverage, and return value to our unitholders. We expect a large amount of cash flow to be generated in 2022, and debt repayment remains our top priority. In addition, our strong performance in 2021 means that we are likely to return value to our unitholders in the form of increased distribution and/or repurchase starting next year.
In the third quarter, we continued to see the recovery of trading volumes in our multiple systems and improved fundamentals. In addition, our Nederland and Mariner East expansion projects have driven record sales in our NGL and refined products divisions, and we expect total NGL exports to grow throughout 2022. Overall, our assets continue to generate strong cash flow, which allows us to fund growth projects for our business internally and further reduce debt in the third quarter. We will continue to work to maintain and improve our investment grade rating, and continue to attach great importance to capital discipline, deleveraging and maintaining financial flexibility.
We continue to be excited about the acquisition of Enable, and we believe we will be able to use our enhanced footprint to increase efficiency and seek new business opportunities. How we participate in the ever-evolving energy world is a key focus. We will continue to make progress on some of our alternative energy projects. We can use preliminary cost estimates to enhance and effectively develop our energy concessions. Operator, please open our first question lineup.
[Operator Instructions] Our first question comes from Shneur Gershuni from UBS.
Shneur Gershuni - UBS - Analyst
Hi. good afternoon everyone. Tom, maybe we can start with quarterly results and how we should consider unchanged guidance. We saw some higher sales, but we also saw some lower profit margins.
For example, in the NGL transportation department, costs are rising, but you have already hinted that costs will rise earlier this year. Just wondering if the results of the quarter are the way you think the guidance was originally constructed, and whether we should consider the midpoint or the low end. For all contract restructurings that are taking place, should we consider some seasonal factors? I just want to know if you can give us some colors about the shape and how we should think about this particular quarter, just considering some of the profit compression we have seen.
Tom Long-Co-CEO
Yes. Good afternoon, Schnur. Obviously, when we started the year, we gave the initial guidance, and then we obviously had a very, very strong first quarter. So when we look back on this year, I think this is the first part of your question about our expectations, which is almost unanimous.
I would say that in certain market segments, NGLs and refined products, we may expect higher optimization activities. Crude oil may be another. So this may really be softer than we expected, but we are still satisfied with the guidance we provided. I think the last part of your question is about where we are expected to enter.
I think it's fair to say that it may appear at the lower end of the range, which may be what we are seeing now. But once again, we have a lot of good positive trading volumes, and with continued optimization opportunities, we feel very, very good about this year.
Shneur Gershuni - UBS - Analyst
great. Perhaps as a follow-up question, on Slide 6, you have maintained annual growth capital of US$500 million to US$700 million in both 2022 and 2023, and this does not seem to have changed. You have made progress in repaying your debts during this quarter and other periods. You talked about the return of capital along the way of distribution increase, repurchase, etc.
Is there a new leverage target that we need to consider? Is it still lower than 4.5 before we can make some kind of pivot point? Just want to know what your latest thoughts are in this regard.
Tom Long-Co-CEO
We will-our goal is still the 4 to 4.5 range. But Shneur, as I said in the past, we always focus on forecasting. Therefore, when we make these decisions, we are not just looking at any one specific point in time. We are studying our forecasts and the leverage we see.
So this is more of a prospect. So if you want, there are no clear boundaries. Therefore, this is why we say that we are considering returning some funds to our unitholders, even in the form of distributions or unit buybacks.
Shneur Gershuni - UBS - Analyst
Tom Long-Co-CEO
Yes, I said from next year. I want to make sure I add it to the answer.
Shneur Gershuni - UBS - Analyst
great. thank you very much. I will jump back into the queue.
Our next question comes from Chase Mulvehill of Bank of America.
Chase Mulvehill-Bank of America Merrill Lynch-Analyst
I think the first question is about the ethane market. Specifically, for ethane demand, we have approximately 280,000 barrels/day of cracker capacity, which will be put into use in the next year and a half. So this will have a considerable boost to the amount of ethane in the United States. So I think maybe you can talk about your thoughts-or the source of these volumes, where do these ethane amounts come from, do you think it's a bit more potential NGL growth? Or do you think it is more of less ethane rejection? Or do you think that as these crackers come online, will the amount of ethane you actually export will decrease?
Mackie McCrea - Co-CEO
Chase, this is McGee. Yes, I will tell you what a good question. We like these types of questions because Energy Transfer has positioned itself as a true leader not only in ethane but also in all NGLs. As you know, we were the first exporter to export ethane to Canada, and then we developed the ethane export business outside of Marcus Hook and the Netherlands.
We are also unique in that we control most of the ethane received from the fracturing tailgate. Therefore, unlike some of our colleagues, we actually control the large amount of ethane the world is looking for. We have already-together with RB and his team, we have had an ongoing dialogue with companies all over the world. South America, Asia, Europe, China.
We expect this business to grow. As you know, we brought satellites this year, and they will bring their second fracturing next year. So we will increase these numbers. We have approved Marcus Hook's 70,000 and 140,000 barrels per day capacity expansion, and we are looking for and negotiating with customers to obtain FID on these projects.
So the prospects for ethane and propane are so bright, and we are very happy to be able to participate in these markets.
Chase Mulvehill-Bank of America Merrill Lynch-Analyst
OK. perfect. Irrelevant follow-up, but I kind of have to ask Biden's "rebuild better" plan. How do you think this will affect ET's mid- and long-term strategy?
Mackie McCrea - Co-CEO
Gosh, this is McGee. I will start. I want to follow up. I don't know how to answer.
We are not really-whatever comes out of these plans and all legislation, we will deal with it when it comes up and in the budget. But we kept our heads down. We are engaged in the fossil fuel business. We play an indispensable role in producing, transporting, fracturing and exporting, and selling large amounts of energy to the domestic market, which have improved our living standards here and around the world.
We are excited about our industry. We see a long future for this industry. We are seeing a significant increase in demand for natural gas, especially for propane and ethane, ethylene and propylene, and other very critical products that play such an important role in daily life. So we are not really-we try-of course, we pay attention to politics.
Of course, we are concerned about any tax implications that it might have on our partnership, but we are not really worried about it and get caught up in it. We will deal with it when it comes out. But at the same time, we just want to generate income for our unitholders.
Our next question comes from Jean Ann Salisbury and Bernstein.
Jean Ann Salisbury - Sanford C. Bernstein - Analyst
Can you talk about why the main optimization lags behind your estimates? Is there a minimum for optimization? Are we around here?
Mackie McCrea - Co-CEO
This is McGee again. Yes, as Tom said, optimization opportunities, especially the substantial opportunities we see in 2020, you cannot predict. You cannot predict a pandemic. You cannot predict that the price of oil will fall to minus zero, and you cannot predict that it will rebound to the mid-1940s or $50 per barrel in a relatively short period of time.
Therefore, our assets, including crude oil assets, NGL assets and natural gas assets, fortunately we have a large amount of storage. Therefore, it does allow us to put the product in the warehouse and hedge it, for example, this winter. Then, if we have any type of winter event or any type of price fluctuation event, we can really benefit from withdrawing our products at a much higher profit margin than we expected. So it is difficult to predict.
We will certainly position ourselves to take advantage of any volatility in the market, as we saw in February last year. But of course we will not include it in our budget or outlook for the next few years.
Jean Ann Salisbury - Sanford C. Bernstein - Analyst
OK. I mean, I think it's fair to say that since Uri, the market has been less volatile than you predicted at the beginning of the year.
Mackie McCrea - Co-CEO
Yes. Yes, we don't-sorry, I didn't fully understand the issue, but we are in a good position to benefit not only our income, but also Uri's customers and the people of Texas. But-as I mentioned, we are also established this year. If there is any type of cold snap or any type of significant price fluctuations, we will be able to provide the required services to customers in the state and across the country.
Jean Ann Salisbury - Sanford C. Bernstein - Analyst
OK. That makes sense. Then-you mentioned that the next satellite cracker will appear sometime next year. Do you know when it will start this year? You get-do you start getting paid when these goods start?
Mackie McCrea - Co-CEO
Yes, for the second question, I believe the latest news we heard is the third quarter of next year. I can't say with absolute certainty. That was the last sentence we heard. I plan to check before this call, but I haven't heard the update yet.
So I believe this is accurate.
Jean Ann Salisbury - Sanford C. Bernstein - Analyst
Cool. thank you very much. This is all I have.
Our next question comes from Keith Stanley and Wolfe Research.
Keith Stanley-Wolf Research-Analyst
Hi. good afternoon. A small part is just a follow-up of this quarter. So I think you have talked about the headwind of optimization.
Another driving factor is unfavorable crude oil inventory valuation adjustments. Is this a big driving force for the crude oil sector? I guess whether the expansion of the Bakken Pipeline is also fully reflected in the performance of the crude oil sector in the third quarter?
Tom Long-Co-CEO
Let's start with inventory gains. This quarter, you saw approximately $33 million. Part of the reason is because we maintain an absolutely low inventory balance compared to the current quarter’s 67 million dollars. In last year’s quarter, both of these were gains, but you can see that this is-this is really spreading there. . I think as far as the second part of it is concerned, yes.
The Buchan Pipe is there.
Keith Stanley-Wolf Research-Analyst
Mackie McCrea - Co-CEO
I might add there that it is still increasing. That's-Keith, your question, just to make sure of this, are you talking about expansion?
Keith Stanley-Wolf Research-Analyst
Yes. this is correct. OK. So I think this will still enter the fourth quarter.
Mackie McCrea - Co-CEO
Yes. I will make it clear. This is McGee. We brought it in August.
When we optimized the project to increase capacity, the demand charge began. Therefore, the transaction volume will be the same as the transaction volume, and drilling in Bakken is needed to really see the growth of these transactions. But most importantly, we are charging demand fees for the incremental capacity we create for a large portion of it.
Keith Stanley-Wolf Research-Analyst
understood. Thanks for that. Separate question on capital allocation. So Tom, you said that paying off debts is still the company's top priority.
I guess you have an expiry date of about $1 billion or more in the first quarter. Should we assume that this is consistent with what you did in 2021, and you will also use free cash flow to repay it? Then about the distribution, I'm curious that when you talk about an increase in the distribution next year, is it-look at it-I mean you cut the distribution last year to basically put cash on the balance sheet because it was not because you couldn't afford it. So when you enter next year, how will you see it? Is the goal to return to the original position? Have you considered the rate of return? Just want to understand, once you are satisfied with the position of the balance sheet, how you will think about the distribution.
Tom Long-Co-CEO
OK. Keith, let's start with the first part of your question about debt. You may have seen that we already have $1.9 billion. On November 1st, we had $1 billion.
On December 1, we will pay off another 900 million US dollars. Therefore, as these maturities come, we will continue-as these maturities come, we will continue to pay them. If there is an opportunity, you may want to exclude certain opportunities. I will not exclude them completely. But now, we are continuing to repay these due dates, even calling ahead when they are due.
I think the second part of your question is - these are our continuing discussions with the board. I will not say that I can tell you anything more explicit at this time, except that repurchase and distribution are very important in our view. But I want to make sure that the first part of your statement is that maintaining financial flexibility is absolutely the top priority.
Keith Stanley-Wolf Research-Analyst
Our next question comes from Jeremy Tonet and JP Morgan.
Jeremy Tonet-JPMorgan Chase-Analyst
Hi. good afternoon. I just want to start, I think, on a higher level, if you can provide any color you see in producer activities. Especially as you are about to enter 22 years, we have seen the differences between private pursuit and the public's more self-discipline.
Do you expect these trends to continue? Or do you see any changes there? How big is the change in the entire basin?
Mackie McCrea - Co-CEO
Jeremy, this is McGee. You said it well, this is what we saw this year. This is what we will see next year. Professionals are just more cautious.
They follow capital more closely than many independents. Therefore, at least in many of our assets, we see smaller companies and smaller independent companies that are carrying out more activities and more production. However, some of these large drilling rigs, especially in the Permian Basin, northern Louisiana, and even in the Marcellus Utica area, we all see drilling rigs put back into use, as we all know. I think the drilling rigs in Northern Louisiana have increased by about 45% from a year ago-more than a year ago-and we have seen similar growth in the Permian.
There are still many DUCs that have not yet been completed in the Permian. Some of them have been completed, but as we enter 2022, we see that many of them are now being completed. So I think we will describe it, at least around our system, only continuous growth, not just the first or second quarter, but in terms of Permian rigs and number growth, continuous growth throughout the year . We do expect faster growth in the poorer natural gas in northern Louisiana.
We saw a similar gradual increase in our assets there at Eagle Ford in southern Texas.
Jeremy Tonet-JPMorgan Chase-Analyst
And just want to know some of your previous comments. Of course, hydrocarbons are important for improving the global standard of living here. But look at Slide 7, you are talking about the alternative energy group here. I just want to see what specific opportunities you are focusing on now? Do you see opportunities for black carbon or the use of power transmission methods? I know everything about DC
Clear as mud. But if we get a higher 45Q or renewable energy, including qualified income, what does this mean to you?
Mackie McCrea - Co-CEO
Yes. Of course, Tom Mason is paying attention to this matter every day in his team, and is looking for the results of Congress passing 45Q and other tax incentives around renewable energy. As we said before, our focus is actually on the mission of our assets, in other words, around our processing plants and processing facilities. We are looking to capture carbon, whether we do it, work with someone or allow others to capture it.
We are also studying some-capture some carbon from some of our facilities in the northeast. We have our Marcus Hook factory. We are looking for some gas. We did some preliminary research.
At some meaningful rate of return, they actually look very promising, so we will continue to pursue these. We are also studying some carbon captures in southern Texas, which are either segregated or part of the ERR project. So we are continuing. We do this every day.
Tom and his team are fully studying the transaction, whether it is black carbon, or the conversion of natural gas into gasoline, or renewable diesel and transported through our diesel pipeline system, we are studying and we will continue to participate in it, just like we are in solar As we did in the business, from a capital point of view, we did not invest in it, but we would definitely invest in the promise of buying electricity that we consider to be very cheap. Therefore, we are supporting renewable energy in one way or another. But we will continue to pursue those that are meaningful. We do hope to complete some of these projects in the distant future. It does not necessarily require a lot of funds, but we do see several projects that may involve up to 20 million or 30 million US dollars around carbon dioxide storage. Capital. Therefore, as we enter 22 years and beyond, this will remain our focus.
Jeremy Tonet-JPMorgan Chase-Analyst
understood. This is a very helpful answer.
Our next question comes from Colton Bean with Tudor, Pickering, Holt.
Colton Bean - Tudor, Pickering, Holt and Company - Analyst
So maybe just go back to the comments about the inner state. Compared with the first half of the year, the unit transportation profit rate seems to have dropped a lot. So I just want to clarify, this sounds mainly due to short-term. Feel sorry.
Mackie McCrea - Co-CEO
Colton Bean - Tudor, Pickering, Holt and Company - Analyst
Internal, Texas pipeline. Yes. Compared to what we saw in the first half of the year, the transportation profit margin per unit seems to have fallen a bit. I think, Tom, you may have talked about this, but just want to clarify.
It sounds like this is mainly due to short-term contracts with higher interest rates, and maybe Whistler has changed the dynamics there. Just want to know what happened between the first half of this year and the third quarter.
Mackie McCrea - Co-CEO
you bet. This is McGee again. Therefore, before the last three, 42 inches in the past few years, --we - this is our bread and butter. It is transporting natural gas across the state.
We see that the spread is $1.50 and $2. Of course, these are beginning to appear. So we started a strategy about a few years ago to ensure that the long-term commitment is not a dollar, but a spread of $1.50, but a good healthy spread. This is what we started to do. Therefore, when you look at the third quarter of 2020, the average spread for that quarter is as high as $0.75 or $0.80.
We were indeed safe before—I mean, I’m sorry, last year’s impact on the third quarter of this year was less than $0.75 or $0.80, but much higher than today’s spread. This is a strategy that makes sense to us. We can see interest rate differentials appearing at least in the short term, and we think it will be short-lived. After two to three years, we believe that the basis will fall back. There will be more needs.
Looking at the growth of the Permian Basin, natural gas is simply incredible. But at the same time, we do hope to secure some of our production capacity with long-term contracts with healthy profit margins.
Colton Bean - Tudor, Pickering, Holt and Company - Analyst
understood. In this case, even if it is the last green space, is this a safe operating rate? Let us first see where the basis comes from?
Mackie McCrea - Co-CEO
Yes. I will answer this way. As of recently, we have seen the spread drop to 0.25 USD-0.20 USD, 0.25 USD, 0.30 USD. We do believe, and I believe the industry believes that in the next one and a half to two years, this will begin to withdraw. We might see $0.75 or $1.
Some of our competitors are talking about the possibility of making another 42 inches. Before they submit another project, we try to tell the market, manufacturers and shippers that we will be able to. We have the ability to be available in two or three years. We are happy to lock in it at a price similar to the price they paid on a new project.
So we are very capable of weathering the storm here, because all these 42 inches have been completed, because the gas starts to grow and fill them up. Once they are all filled, we are in a good position to get a greater distribution of capacity on our natural gas system.
Colton Bean - Tudor, Pickering, Holt and Company - Analyst
understood. Maybe this is just a niche topic. For the legacy PVR assets, do you still have any exposure in terms of the coal market price increase we are now seeing? Or is this a more attractive seller's market in which you might divest some of your legacy assets?
Tom Long-Co-CEO
No, I will not say that there will be any chance of soaring. As you know, it is a very small-very, very small piece, put it there. This is a franchise. So I will not lead you to anything there.
As for the divestiture, there is no plan in this regard, and no dialogue is ongoing.
Our next question comes from Michael Blum from Wells Fargo Bank.
Michael Blum-Wells Fargo Securities-Analyst
I want to ask Rover. You emphasized that the income has increased by $13 million. I just want to hear what Rover is doing now. How many of them are signed? And I guess considering the fact that the basin is very tight, is it possible to contract more producers at higher prices?
Mackie McCrea - Co-CEO
Yes. Michael, this is McGee. What a great project. This is really good for us.
We saw—for example, a few months ago we saw a small problem with Petco’s pipeline, and we saw the value of this pipeline increase even more, so the difficulty we saw was—at least in the near future, more than In the next two, three, four, and five years, how difficult it will be to approve another interstate pipeline from the region. So we are in a good position. We may have about 90% of long-term contracts signed on a monthly basis. Many times, we sell capacity based on monthly tariff rates, depending on whether they are going to fall or enter Zone 1a southward.
Therefore, this is a strategically located asset. When we see Marcellus Utica's production growth, it can transport barrels from the north to Canada, which is a unique feeling. As you know, it can ship barrels all the way to the Gulf Coast to supply LNG facilities and other markets along the Gulf Coast. So we-we have been moving between 3.2 and 3.4.
We can move up to 3.55, I believe it is. Therefore, as we move into the future, we will continue to see this growth, whether it is in filling to the maximum or in the highest tariff rate in the future.
Michael Blum-Wells Fargo Securities-Analyst
understood. Then follow me up quickly. Therefore, your 22-year and 23-year capital expenditures in the range of US$500 million to US$700 million per year, I am assuming that this does not include any potential expenditures for these programs that you have undertaken in Panama. So I think the question is if this MOU becomes Panama’s FID project, how will these numbers change?
Mackie McCrea - Co-CEO
It will definitely increase these numbers, but submit the project to FID for its future. We may be talking about submitting it to FID for at least 12 months. Therefore, we may not see any material expenditure until 23 years.
Michael Blum-Wells Fargo Securities-Analyst
Our next question comes from Pearce Hammond and Piper Sandler.
Pearce Hammond - Piper Sandler and Company - Analyst
Yes. Good afternoon, thank you for asking my question. I have only one question today. Mackie, when you look at the NGL supply demand in the next few years, when do you think Mont Belvieu needs more fractionation capacity?
Mackie McCrea - Co-CEO
Well, what a good question this is, and when we find the answer to this question, we can use it. We are very strict in terms of capital, so we have not completed our 8 fracturing yet, but we will definitely monitor it very closely, whether it is the output of our factory or the output of a third-party factory. Therefore, only from-from our point of view, the eyes of energy transfer, we think that at least one is not needed for the next six to nine months, but we evaluate it every quarter. We do expect that at some point in 2022, we will have to seriously consider completing these eight fractures.
We do expect that as long as commodity prices continue to remain at their current levels, transaction volumes will begin to grow. It looks like they will definitely.
Pearce Hammond - Piper Sandler and Company - Analyst
Our next question comes from Christine Cho of Barclays Bank.
Christine Cho-Barclays-Analyst
Hi, everybody. Thank you for letting me join. I just thought-how should we view the rising costs of O&M and G&A in 22 years? And is there any upper limit for your inflation tracker? And to some extent it tracks things like CPI or PPI, should we think-should we assume that the entire growth will be reflected in interest rates next year? Or, competitive pressures will limit some of them-the growth you actually achieve?
Mackie McCrea - Co-CEO
I can start from the second half, maybe most of the time. Yes, in most of our contracts, of course, in all our liquidity contracts around transportation and fractionation and crude oil contracts, we have an index. It is usually the FERC index. But for example, I believe this year's FERC index, I believe that from July to July to July of the following year, it is negative.
So we actually didn't have any rise-although we are seeing this kind of inflation. However, that is for July next year, and we expect it to rise significantly. We heard an increase of 5% or 6%, and we do have these increases in most rig contracts and many (if not most) natural gas contracts. So we do have, whether it is the CPI index in our natural gas contracts or the FERC index in our liquidity contracts, we do have in most of them, and we will benefit-or at least not be hurt by inflation Cost growth.
Christine Cho-Barclays-Analyst
Should we expect you to grow through the whole? Just like competitive pressure will not prevent you from doing only part of it.
Mackie McCrea - Co-CEO
It may be in a future contract. But when I refer to all existing contracts that we transfer products to our system today, this language is already included.
Christine Cho-Barclays-Analyst
OK. Then in the NGL section, out of curiosity, one of your colleagues talked about the incentive rate in the Permian. I wonder if you guys did the same thing, or if the market segment is really just optimized headwind.
Mackie McCrea - Co-CEO
Yes. I'm not sure what the incentive rate is and what-the rate we will take is the highest rate we might get from the shipper if the market allows.
Christine Cho-Barclays-Analyst
Well, I think, would you say that their quarter-on-quarter trend is lower?
Mackie McCrea - Co-CEO
Feel sorry. So if you say-where is the market, yes. ——Just like crude oil, like short-term leases of natural gas, NGL crossovers have been overbuilt. Fortunately, most of the barrels that enter our system and enter our system in the future are already dedicated.
However, we go out every month to try to obtain those barrels at the tailgate of third-party facilities, and it becomes very competitive. T&F prices are significantly lower than they were a few years ago.
Christine Cho-Barclays-Analyst
Our next question comes from Michael Lapides from Goldman Sachs.
Michael Lapides-Goldman Sachs-Analyst
Thank you for answering my question. Look, we have been eight or nine months since the winter storm Uri. Can you give some insights on what you see in the natural gas storage contract market (especially Texas), whether you have signed important new contracts and have taken on some to some extent-maybe profit The increase in the rate but the decrease in the price difference will move around, but will get more fixed fee payments, and the overall trend of the natural gas storage market after the event.
Mackie McCrea - Co-CEO
You bet, this is McGee again. Yes, it is diverse. We have affected more needs or more desperate needs, and what I want to say is the need for secure storage. We certainly sold more storage space at a better price than last year, and we still have some swing rights.
This winter, we are still discussing the swing service and warehousing service this winter with many parties and power generation companies. But some companies are already panicking or not panicking-after what happened in Uri, they don't seem to be as worried as we thought. But once again, whether we have completed some new transactions or we are ready to provide the services they need this winter, we are in a good position.
Michael Lapides-Goldman Sachs-Analyst
understood. thank you all. Grateful.
Ladies and gentlemen, this concludes the question and answer session. Now I want to turn the call back to Tom Long’s closing speech.
Tom Long-Co-CEO
Thank you again for joining us today and supporting us, and we look forward to talking with you in the near future.
Tom Long-Co-CEO
Shneur Gershuni - UBS - Analyst
Chase Mulvehill-Bank of America Merrill Lynch-Analyst
Mackie McCrea - Co-CEO
Jean Ann Salisbury - Sanford C. Bernstein - Analyst
Keith Stanley-Wolf Research-Analyst
Jeremy Tonet-JPMorgan Chase-Analyst
Colton Bean - Tudor, Pickering, Holt and Company - Analyst
Michael Blum-Wells Fargo Securities-Analyst
Pearce Hammond - Piper Sandler and Company - Analyst
Christine Cho-Barclays-Analyst
Michael Lapides-Goldman Sachs-Analyst
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