Williams Cos Inc (WMB) — Q3 2022 Earnings Call Transcript

Thanks, Gina, and good morning, everyone. Thank you for joining us and for your interest in The Williams Company. Yesterday afternoon, we released our earnings press release and the presentation that our President and CEO, Alan Armstrong; and our Chief Financial Officer, John Porter, will speak to you this morning. Also joining us on the call today are Micheal Dunn, our Chief Operating Officer; Lane Wilson, our General Counsel; and Chad Zamarin, our Senior Vice President of Corporate Strategic Development. In our presentation materials, you'll find a disclaimer related to forward-looking statements. This disclaimer is important and integral to our remarks, and you should review it. Also included in our presentation materials are non-GAAP measures that we reconcile to generally accepted accounting, and these reconciliation schedules appear at the back of today's presentation materials. So with that, I'll turn it over to Alan Armstrong.

Great. Thanks, Danilo, and thank you all for joining us today. Williams reported another great quarter, and John will walk through the details in a moment, but the punchline is that Williams delivered exceptional results in the third quarter with adjusted EBITDA up 15% compared to the same period last year, driven by strong performance across all of our core businesses and our JV upstream operations. Our natural gas strategy has proven that it can capture upside margins and weather commodity price cycles as we work to serve growing demand for clean, secure and affordable energy. These results really speak to the strength of our assets and our long-term approach to business. Williams is the most natural gas-centric large-scale midstream company around today, and there's a reason we've stuck with our natural gas-focused strategy for as long as we have. Not only is this strategy delivering in the current environment, but the signals coming from the market show that it is going to continue to deliver substantial growth for the long term as well. We expect strong fundamentals to drive attractive growth opportunities for Williams, including higher demand for U.S. LNG exports and a faster pace of coal to gas conversion with the lion's share of these projects residing along the Transco corridor. Natural gas demand across various sectors continues to increase in the face of higher natural gas prices. This speaks to the continued inelastic demand for natural gas, both here and abroad and the fact that domestic natural gas remains a bargain versus alternative fuels. We continue to see strong growth in the quarter as our quarterly natural gas gathering volumes and our contracted transmission capacity. And we're seeing progress on important projects like our Regional Energy Access project, the Louisiana Energy Gateway and other Transco projects that are currently in execution. And speaking of execution, our attractive high-return growth backlog in the Gulf of Mexico remains intact, with the six previously announced deepwater projects set to increase EBITDA by over $300 million beginning in '25. And we recently began pipelay operations on the well projects here just recently. Our business continues to fire on all cylinders, driving our financial strength and stability. And despite the current inflationary environment, we will actually see a lift in margins as many of our contracts allow for adjustments that exceed the impact of expenses. For instance, in our G&P business, our contracts are built with inflation escalators that bolster our margins in the current environment. And within our transmission business, we are able to recover cost via rate cases, which minimizes the impacts of inflation over time. I'll note that Northwest Pipeline recently reached a settlement on its rate case, and we remain on track to follow a Transco rate case in '24. The benefits of our long-term approach to business also extend to the current interest rate environment and in fact, all of our debt is fixed rate. John is going to provide some more detail on this in his section. But we are extremely well positioned in this current environment. Also worth noting, our business is well positioned for a recessionary environment. Recall that in 2020, Williams faced a host of challenges, including rapidly declining commodity prices, major producer customer bankruptcies and impactful hurricanes in our Gulf of Mexico business. In the face of these challenges, the company still exceeded the mid of the guidance we set well before COVID raised its ugly head. Our business today remains positioned to thrive even in the face of potential recession. In fact, we announced that we expect to be near the high end of our previously raised guidance, putting us on track to achieve four-year earnings per share CAGR of 22% and an EBITDA CAGR of 8%. This, again, underscores just how well our natural gas strategy is translating into solid financial results for our shareholders. And while we will not be providing our '23 guidance until the next quarterly call, there are some drivers that you should think about for '23. So let me go through those here. First of all, in the Northeast G&P business, we expect higher volume growth and higher cash flows from expansion projects that are currently underway, and many of those are nearing completion. In the West G&P segment, we expect continued contributions from the large number of Haynesville expansion projects that are nearing completion and as well the Trace Midstream acquisition. But equally important are the expected contributions from our upstream JVs, which should provide incremental volume growth in both the Haynesville and in the Wamsutter area, proving that our strategy to fill up weight and midstream capacity is working. We expect modest growth in other basins as well, for instance, in the Eagle Ford, which has been under the radar recently. We also see a very bright spot here next year as we expect increased activity in the rich gas part of the basin to drive volumes well above the minimum volume commitment level for this segment of the business, which will be the welcome rebound and extend our earnings above that MVC level. The Eagle Ford should represent upside longer term as well as new capital will likely be deployed to further develop both the acreage that is already dedicated and some undedicated acreage that we are well positioned to serve. In the Transmission & Gulf of Mexico business, the growth drivers here include the incremental earnings from our recent production that has been connected along our existing deepwater assets. So this is new production that's been recently connected and it'll start to show up here in the fourth quarter; it does not include those projects that will start coming on towards the end of 2024. The NorTex acquisition will also be included in our Transmission & Gulf of Mexico business, and the continued expansion of our fee-based services on our interstate gas pipeline systems that continue to grow. Within our upstream JVs, volume growth will remain the story in the Haynesville; we've stated that we expect an ownership reversion in the first half of '23, where Williams will own 25% of the PUDs, but we will retain a 75% interest in the PDPs. I want to be clear about this. Our interest in the existing flowing production does not get reduced; only our interest in the undeveloped acreage will be reduced. We designed this structure to minimize significant volatility in earnings. And to this end, we expect the Haynesville to remain a source of growth. In the Wamsutter, where we have a much larger acreage footprint, our JV is just now beginning to complete wells from the 2022 drilling program, and these will begin to contribute this volume growth next year. And this, we believe, is going to prove up the benefits of the contiguous acreage in this basin, and we're excited about the Crowheart operations out there and what we're seeing from those recent drilling and completion operations. Our primary goal of getting the volumes and cash flows up on these late and midstream assets will be more than met. But the icing on the cake has been the higher-than-expected pricing for these producing reserves. Over the longer term, we see a steady increase in net cash flows as the drilling capital obligations revert more and more to the JV operator and the benefits of the growing volumes build our midstream cash flows. Ultimately, we expect to find a long-term owner for these upstream properties that we can rely on to further grow production, which will translate into even higher midstream free cash flows for Williams. Looking beyond 2023, we believe that our projects are supportive of a 5% to 7% long-term EBITDA CAGR. The annual growth rate may fluctuate a bit given the timing of new large projects like Regional Energy Access and our big deepwater projects coming on at the end of '24 and into '25, but the bottom line is that we see a clear trajectory to continued earnings growth based on the opportunity set of our footprint today. Finally, as we think about value chain integration, we are further advancing our integrated clean energy value chain strategy. Our acquisition of the NorTex storage facility and last week's approval from the FERC for Transco's Washington storage facility in Louisiana enables us to offer competitive market-based rates to LNG, power generation and other customers in the Gulf Coast area. This will be a critical element of our wellhead-to-water strategy as this combined 110 Bcf of working gas storage and our expansive Transco network are fortified with low emissions Haynesville production from the LEG project. We are also making strides in advancing our wellhead to end-user strategy with our agreement with PennEnergy Resources to support the marketing and delivery of certified low emissions gas that we refer to as next-gen natural gas. This agreement includes an independent third-party certification process that verifies best practices are being followed to minimize emissions and produce natural gas in the most environmentally responsible manner. This is another exciting step to grow the delivery of next-gen gas to markets across the U.S. as well as overseas. So with that, I'll pause and turn it over to John to walk through the quarter and our year-to-date results, and then we'll open it up for your questions.

Thanks, Alan. Starting here on Slide 2 with a summary of our year-over-year financial performance. Overall, 2022 financial performance continues to be quite strong. Beginning with adjusted EBITDA, we saw a 15% year-over-year increase for the third quarter and a 12% increase for the first nine months of '22 versus '21. As we'll see on the next couple of slides, our adjusted EBITDA growth has been led by our core large-scale Natural Gas Transmission and Gathering and Processing businesses, complemented nicely by growth in our upstream joint ventures. Our adjusted EPS increased just over 37% for the quarter and 34% year-to-date. Available funds from operations, AFFO, which is basically our cash flow from operations less working capital fluctuation, the non-controlling interest cash flows grew in line or better than adjusted EBITDA at 15% year-over-year for the quarter or 18% for the nine-month period. Also, you see our dividend coverage on this page based on AFFO was 2.4x for the third quarter and 2.29x year-to-date. Our debt to adjusted EBITDA metric continues to improve based on our strong growth in adjusted EBITDA and our capital investment discipline, now reaching 3.68x versus last year's 4.04x. So now let's move to the next slide and dig a little deeper into our adjusted EBITDA results for the quarter. Again, the third quarter built nicely on the strong start we've seen this year with 15% growth reflecting the combined effect of the performance of our core business and upside from our upstream joint ventures. Walking now from last year's $1.420 billion to this year's $1.637 billion, we start with our upstream joint venture operations that are included in our Other segment, which were up $60 million. Since our first new production in the Haynesville came online in April of this year, we've seen a rapid ramp in volumes that will continue through the remainder of the year. As Alan mentioned, the strategic purpose of our upstream joint ventures is to fuel growth in our core related gathering assets, and that's certainly what we see happening in 2022. Shifting now to our core business performance. Our Transmission & Gulf of Mexico business improved $41 million or 6% due to improved contributions from both Transco and our Gulf of Mexico businesses. Transco saw higher revenues, largely from the Leidy South expansion project, which came online in phases last year. Gulf of Mexico was significantly higher in '22, due in part to the lack of hurricane-related impacts that occurred in 2021. Operating and maintenance costs were higher, driven in part by higher maintenance activities, but we are tracking very close to plan through the first nine months of the year. Our Northeast G&P business increased $22 million or 5%, driven by top line Gathering and Processing revenue growth on slightly lower volumes. Gathering and Processing rate growth was supported by a combination of factors, including higher commodity-based rates, annual fee escalations and other expansion-related fee increases that more than offset the lower cost of service rates at our Bradford franchise. Overall, Northeast volumes were 10.8 Bcf per day and roughly in line with our current forecast for total 3Q volumes. We continue to expect an increase from this volume level for the fourth quarter. But as we've mentioned in past calls, our '22 plan for the Northeast has always been higher EBITDA versus 2021 on pretty flat volume growth. However, as Alan mentioned, we remain well positioned to resume stronger volume and EBITDA growth in the Northeast in 2023, driven by several expansion and optimization projects. Shifting now to the West, which saw another impressive quarter of year-over-year growth, up $80 million or 31% over 2021. I should mention that $27 million of the $80 million was attributed to our Trace Midstream acquisition, which closed on April 29 this year. So even without Trace, the West still increased $53 million or 21%. In the West, we continue to see upside from our commodity price exposed rates, especially in the Barnett and Haynesville, as well as substantially higher volumes in the Haynesville that drove a 12% overall increase in volumes for the West, and that's excluding the Trace acquisition. Next, we saw a $4 million or 12% increase for our Gas & NGL Marketing Services business. This increase was despite taking a $54 million lower of cost or market adjustment to our gas and NGL inventories in September of this year. Generally speaking, most of this adjustment, which was associated with our gas and storage, will result in higher margins when those products are sold out of inventory late this year or early next year. So again, another strong quarter with 15% growth in EBITDA, driven by core business performance and upside in our upstream joint venture operations. Let's move to Slide 4 and look at the year-to-date comparison. Through the first nine months of '22, we've now generated 12% growth in adjusted EBITDA over 2021, three strong consecutive quarters for this year. So stepping now from last year's $4.152 billion to this year's $4.644 billion, starting with the $77 million of first quarter 2021 winter storm benefits that we're showing here in gray, and then moving to the $182 million contribution from our Midstream operations which were Wamsutter related in the first quarter of '22, and then begin to have a more significant Haynesville component in the second and third quarters. Our Transmission & Gulf of Mexico business has seen 4% growth year-to-date, driven by Transco's Leidy South expansion project and strong first quarter '22 seasonal revenues and also higher Gulf of Mexico results due to less hurricane-related impacts in '22 versus '21, partially offset by higher operating and maintenance costs. The Northeast G&P business has now seen 6% growth year-to-date, driven by higher rates on overall flat volumes, as previously discussed. The West has seen an impressive 27% growth year-to-date, driven by higher commodity-based rates, but also a strong 11% overall volume growth, excluding the Trace acquisition. Finally, our Gas & NGL Marketing Services segment is up $32 million, driven by favorable commodity margins as well as the new contributions from the Sequent acquisition that closed on July 1, 2021, and the year-to-date comparison was also unfavorably impacted by lower cost or market adjustments on inventories as discussed in the third quarter comparison, which as we discussed, should result in higher margins in the future. So an impressive $491 million or 12% increase to land us with over $4.6 billion of adjusted EBITDA through the first nine months of the year. Before I turn it back over to Alan, I'll offer a few thoughts for full-year 2022 financial guidance. As we previously announced, based on strong third-quarter performance and expectations for the fourth quarter, we anticipate full-year adjusted EBITDA will be near the high end of our previously announced guidance range of $6.1 billion to $6.4 billion, which implies a strong fourth quarter. We see multiple contributors to this expected strong finish to the year, including continued growth in our upstream joint ventures, but also growth across our other business segments versus our third-quarter results. One other note regarding the third quarter, you probably noticed in our 10-Q that we did initiate share repurchases in September. As we discussed on our second-quarter call, we stand ready to take action on share repurchases when we see a pullback in our valuation, and that's what we did in September. Our share buyback principles center around a returns-based approach considering our current equity yield plus a level of expected growth in the business. We are more confident than ever in the long-term growth of our business, and so we remain ready to purchase additional shares as an important element of our capital allocation strategy. Debt financing costs have also been topical lately with the sharp rise we've seen in borrowing costs. We've included some helpful information on our well-positioned debt portfolio in the appendix, but I'll briefly touch on a few key facts. First off, we have an entirely fixed-rate debt portfolio with an average rate of 4.78% and a weighted average maturity of 12.2 years. Second, following our well-timed August debt issuance and subsequent call of $850 million of 2023 notes recently in October, we now only have $600 million of maturities in 2023. And finally, we will continue to enjoy excellent financial flexibility with our $3.75 billion credit facility. So again, with our expectations to finish 2022 near the high end of our adjusted EBITDA guidance, this would amount to over 13.5% growth versus 2021 and a four-year CAGR of about 8%, driven by continued growth in our core business as well as contributions from our Trace acquisition and upstream JV operations. So with that, I'll pass it back to Alan for closing remarks.

Okay. Well, great. Thanks, John. And I'll close by reiterating my remarks at the top of the call that quarter after quarter, we continue to demonstrate that we have built a core business that has steady predictable growth and is resilient in the face of multiple macroeconomic conditions. In fact, this makes the 27th quarter in a row that we've either met or exceeded the Street consensus. A careful allocation of capital has delivered improving returns on capital employed. In fact, this is a 21.7% return on invested capital as we've shown in recent presentations. We delivered a very strong balance sheet and we have a growing dividend with best-in-class coverage. Our long-haul pipes are in the right places, serving the right markets, our formidable gathering assets are in the low-cost basins that will be called on to meet gas demand as it continues to grow for decades, and our Sequent platform is providing infrastructure optimization services that create value for Williams and our customers while mitigating downside risk in these volatile and fast-growing markets. You've heard me say before that we are bullish on natural gas because of the critical role it plays and will continue to play in both our country and the world's pursuit of a clean energy future. But even more so, we are also bullish on America's ability to lead on all fronts when it comes to clean, reliable, and affordable energy. The United States is positioned better than any other country to solve the energy crisis and the climate crisis we're facing around the world. But I'll stand on my soapbox again and remind you that access to our abundant and low-cost natural gas reserves here in the U.S. is dependent on having the appropriate infrastructure to move energy where it is needed. We're seeing and feeling today the impact of inadequate infrastructure both here at home and especially in Europe, with consumers bearing the brunt of these actions in the form of high energy prices, high utility bills, and energy-driven inflation. The good news is that we have a solution that is readily available, a solution that will support global emissions reductions, keep energy costs affordable, and grow our nation's competitiveness, enabling the efficient unobstructive build-out of our nation's energy infrastructure to ensure delivery of natural gas is foundational to the U.S.' leadership on greenhouse gas emissions reductions and energy security. And we at Williams will proudly continue our efforts to strongly advocate for actionable energy policy solutions and permitting reform in the days, months, and years ahead. And with that, I'll open it up for your questions.

Just want to kind of start off with the Haynesville here and this new project that you talked about in the slides regarding carbon capture. I was just wondering if you could touch base what moved that forward at this point was that the higher 45Qs coming from IRA here that get over the finish line? And also, I guess, how big could the scope of this project be over time?

Yes. Thanks, Jeremy. This is Chad. Yes, the IRA and the increase in the 45Q credit is certainly a benefit that helps that project move forward. The scope of that project is alongside our Louisiana Energy Gateway project as we're gathering large volumes in the Haynesville. We'll be taking the CO2 that today is emitted in the basin into the pipeline, and we'll also be gathering CO2 from third parties and moving that CO2 to the Southern end of the Louisiana Energy Gateway gathering project. And at that location, we're going to install treating facilities that will remove the CO2 and transport it to a sequestration site so that it can be permanently stored underground. We see somewhere around the potential for 2 million tons of annual CO2 to be captured and sequestered. And we think that could increase over time as we continue to further develop that project. So we feel really good about it, and we're focused on bringing that online alongside our Lake project, which could be in service as early as Q4 of '24.

Got it. Very helpful there. And just wanted to pivot, if I could, to the producing assets in the Haynesville. It seems like the ramp in production there is quite strong, and I think it might kind of reach what you guys were hoping for when you attain the assets, getting into a growth trajectory that fill your pipes to serve that purpose there? And if it's on that trajectory, does that kind of make you guys think about potential timeline to divest those assets if they are delivering the volume utilization that you're looking for?

Yes, Jeremy, I want to clarify that there has been a lot of confusion in the market regarding the types of contracts. We anticipate that our net interest production will continue to grow in 2023. We are very pleased with GeoSouthern's performance; they have excelled in their operations, both in terms of costs and well delivery. We are excited about their activities and truly expect our net interest production to keep increasing into 2023. Some have mentioned a potential decline due to the reversion, but while our interest in undeveloped acreage decreases, our interest in current production remains strong. Moreover, after the reversion, our capital obligations will significantly decrease in 2023 since we won't need to invest in drilling operations there. Regarding the sale of the asset, we certainly aim to divest in the long term, and we believe the acreage is proving itself to be valuable. However, there is still a considerable way to go in terms of total volume growth in that area, as we are just beginning to explore that inventory. We are attentive to opportunities, but we are not close to reaching peak volumes yet. Overall, everything is unfolding as planned, enhanced by favorable pricing in the current market. The production volumes this year are exceeding our expectations, which is fantastic news and will contribute significant free cash flow in 2023 and 2024.

Got it. And just a quick follow-up on that. Is there a certain production level you are looking for before you would entertain divesting those assets?

I believe there is significantly more potential for growth than many people realize. We have been consistently impressed by operators providing information that suggests production levels could exceed the current reduction level. We are not in a position of waiting; we simply want to ensure that production growth continues at a steady pace, regardless of ownership. Our partnership with GeoSouthern has proven to be beneficial for both parties. We are not fixated on reaching a specific volume number, as the evidence regarding performance is quite clear at this time. The viability of that acreage has been effectively demonstrated through the performance of the GeoSouthern channel.

In light of the NorTex acquisition, I was just wondering if you could elaborate on the benefits of gas storage right now. Do you think storage has become more valuable? Do you think spreads could widen out? How does this fit with Sequent? And then finally, do you envision building out more gas storage assets organically or doing more acquisitions in this space?

Thank you for the question. Sequent was a significant customer for NorTex, and as we evaluated their process, we recognized the pricing potential for that storage. We were quite impressed and believe the rates for storage in that region could increase due to its value in these more volatile markets. We maintain that the fluctuations in power generation from gas-fired sources and LNG will continue to enhance the value of natural gas storage. Sequent, previously a major buyer of storage, illustrates this market potential well, and we see significant value there. Additionally, we received an important order from the FERC last week allowing us to implement market-based rates for our Washington Gas storage. Although we still need to complete the filing process, this represents a significant opportunity for us as it involves approximately 75 Bcf a day of working gas storage. Together with NorTex, we will have around 110 Bcf a day of storage available in the Gulf Coast region. We are committed to this initiative and are focused on maximizing the value from our current assets and NorTex in the years to come.

Great. If I look at the financial metrics this year, the leverage is good and EBITDA is on pace to grow 13% or 14%. However, on the capital return side, the dividend has only increased by 4%, and while there have been some buybacks, they have been fairly modest. So my question is whether the strong performance this year influences how you approach capital return heading into 2023.

That's a great question. The answer is yes; it does influence our perspective. We realize that our AFFO and EBITDA are growing faster than our dividend, and we are aware of this. We aim to ensure that our dividend remains robust while also committing to grow it in line with our cash flow. The decision regarding this will be made by the Board later this year and into next year. However, we currently have the coverage and cash flow growth to potentially increase our dividend growth rate.

I have a quick question and would like to follow up. You touched on this during your prepared remarks, but as we look ahead to 2023, I’m considering the factors that will influence it. When comparing 2023 to 2022, there’s a full year of the M&A activity you completed, along with the Springridge gathering expansion and some Northeast gathering expansion. Additionally, there are activities in the Gulf of Mexico that are set to begin, and you likely expect higher exploration and production volumes. Am I overlooking anything as we evaluate growth opportunities? Also, how should we consider the offsets for 2023? The curve is backward dated, but that’s not always accurate; how should we approach the offsets for 2023?

Yes, great question. I think you've laid that out pretty well actually. I would say the other thing that we didn't enjoy this year that we will enjoy next year is the investments that we've been putting into the Wamsutter JV this year. I mentioned that we're continuing the drilling program, but we are just now starting the completions effort out there. And so the benefit of that drilling capital we've been spending up there this year will really start to play out in '23 as well. So that's a key issue. As I mentioned, the Eagle Ford, we're seeing some pretty rapid development going on in the rich gas that will see the MVC out there. So that's attractive. In terms of the headwinds, I certainly think pricing is a consideration, but I think it's also important to realize the amount of hedges that we had on this year that kept us from enjoying extremely high gas prices this year. And so I think if you look year-to-year, they're probably not likely going to be that big a spread. I would say we're strip. So that's probably the primary headwind. But from what we're seeing right now, that is going to be dramatically overcome by volumes in the E&P space. And so yes, we could see lower price, but our volumes, I think, will surprise people to the upside next year.

That makes sense. I have a follow-up regarding Slide 24, where you mentioned an 8% increase in power demand year-to-date. I don't have much experience on the power side, but could you explain what is happening there? How sustainable do you think this growth in power demand is as we look ahead?

We continue to be surprised by the resilience of gas demand despite higher prices. One of our biggest surprises this year has been that utilities and power generators are not able to revert to coal for several reasons. First, many long-term contracts have expired, and second, the price of coal has risen alongside gas. Consequently, we did not observe the expected shift back to coal-fired generation in this pricing environment. What we're witnessing is driven by utilities, and it seems unlikely this trend will change soon. As renewables increase, natural gas will be their backup, further reducing coal-fired generation. Therefore, while market rhetoric might suggest a dramatic decline in gas volumes, the requests for new services we are receiving indicate otherwise. We see continued strong demand for gas-fired generation from utilities, particularly in the Mid-Atlantic and Southeast regions. Our optimism is based on these indications rather than market rhetoric, as reflected by the influx of long-term service requests.

Maybe if I could ask another question about '23 and just talking about how to frame CapEx. There's clearly some projects finishing up some bigger ones like Regional Energy Access and legs that are out there where maybe the spend gets spread over '23, '24. So I'm just wondering how to think about growth CapEx within the context of what it was this year and some of these longer-term projects?

Yes, I would expect to see some fluctuations in our growth capital expenditures, as we've discussed in previous calls. We will be ramping up construction next year for the Regional NG Access and the Whale project, which has already begun but will continue into 2023. Additionally, LEG will also see increased activity. These are significant investments that will grow next year. However, we are committed to keeping our growth CapEx aligned with previous years. This year, we are targeting a level between $1.2 billion and $1.3 billion moving forward, though we may experience some variability when these large projects commence. Thus, you can expect that to be a theme in 2023 with the onset of these major projects. Nevertheless, our focus remains on managing growth CapEx to an average of around $1.2 billion annually.

And this might be another one for you. But in the NWP rate case, it seems like you achieved sort of a modernization rider or there's some language about that. Can you talk about that and whether that's going to be significant and also whether that can be a precedent for Transco in the upcoming rate case?

Yes. Great question. We do have our uncontested settlement in front of the FERC right now for approval. We would expect to receive that before the end of the year, but those rates into effect next year and a great outcome by the team there achieving an emissions reduction program rider, as you indicated. And I would say is that certainly a good framework or pattern for us to go into the Transco rate case with that same thought process in front of us where we have a lot of compression on both Northwest Pipeline and the Transco system that we can replace that makes sense to replace in many of these areas where we're in non-attainment or being challenged by some of the regulators like in the Pacific Northwest to improve the emissions profile of our units. And it's just a great opportunity for us to make an investment in our regulated business. And I would say the Northwest Pipeline opportunity is certainly not as great as the Transco opportunity for capital deployment there just with the number of units that we have on the Northwest Pipeline system versus Transco. The horsepower on Transco was a significant order of magnitude higher than Northwest, but certainly, a great opportunity there and very well received by our customers on Northwest pipeline for us to go and implement these emissions reductions.

Great. And maybe if I could squeeze just a quick last one. It seems like you got a ruling in the energy transfer litigation; they're appealing. Is there any timing as far as how long that appeal may take to play out?

Yes. This is Lane Wilson. We would anticipate sometime probably late second quarter, early third quarter, maybe even early fourth quarter, depending upon how quickly the Delaware’s work moves. Yes, 2023.

Maybe just talk a little bit about a follow-up on capital allocation and the growth CapEx. With the acquisitions of Trace and NorTex, could you just maybe talk about what the base business kind of growth CapEx run rate is going forward now?

Yes. Sure, this is Micheal. As I indicated, we think it's going to be about $1.2 billion, very similar to what we see this year on average going forward. But as I've talked about on previous calls, we do have some lumpiness anticipated there when these larger projects start to ramp up construction, retail energy access. We'll be ramping up construction next year. The Lake project will also be starting construction next year and then the Whale project in the Gulf of Mexico will be in some pretty significant construction activities as well next year, although that has started this year. So as always, it will be lumpy, but we're very focused on being efficient in regard to our growth capital. So I would expect you would see a $1.2 billion to $1.3 billion average CapEx on our growth side for the foreseeable future.

Great. And then maybe as a follow-up on some of the upstream business. You guys outlaid some of the hedging profile that you have into 2023. Kind of curious if you can just give an update about where you're comfortable like hedging as a percentage of the overall volumes expected just given some weakness in recent nat gas pricing just given some record U.S. nat gas production and some constraints on the LNG side?

Yes, thank you. We currently have some advantageous hedges for 2023, approximately 15% for the year. We will take a proactive approach to this moving forward. It's great to have our Sequent team closely involved in these decisions, as they provide valuable insights into the market. We intend to remain flexible and opportunistic with our hedging strategy, similar to this year, as we adjust our positions as needed. There isn't a specific formula or requirement for hedging; rather, we will act based on market opportunities as they arise. Overall, our approach is opportunistic without a set minimum level of hedges.

Right. Would second half '22 be a good kind of parameter of where we should expect it going forward, or I guess, remains to be seen?

I'm sorry, I didn't quite follow that last part.

Whether the 50% hedging profile that you kind of had outlaid for the second half of '22, is that kind of a fair estimate for '23 or more to…?

It's very dependent on market movements compared to our outlook on fundamentals. The good news is we have a strong understanding of production since we operate in 15 different basins. This allows us to have a solid perspective on production trends and market conditions, which we use to guide our fundamental analysis. If pricing aligns with those fundamentals, we will hedge accordingly. I wouldn’t assign a specific percentage to this; it really comes down to comparing the fundamentals with pricing in the forward market.

Alan, maybe it's worth mentioning that '23, we'll have less to prove up as far as volumes. In '22, we did have the growth in the Haynesville that outperformed our expectations, which was great. But in '23, we've really proven up volumes. And so we've got much less volume risk coming into '23 as a result of the success we've seen in '22.

Yes, that's a really good point that some of our reluctance to hedge at the beginning of '22 was based on us not wanting to hedge until we actually saw that reduction flowing given the volatility in the markets and certainly didn't want to get caught short in an upswing in the market. So next year, we'll have less of that. In the Haynesville, we'll have less of that volume growth risk, not so much in the Wamsutter.

I just wanted to go back to the opening comments regarding 5% to 7% EBITDA growth. So is that kind of the run rate we can assume based on your asset base now for the next few years?

Yes. That is correct. Obviously, as we mentioned, we've been overachieving on that a bit. We've had that 5% to 7% growth rate out there for quite some time, and that was assuming a $1.2 billion to $1.5 billion capital program back when we first established that level of growth rate. And I would just say we've got some efficiencies coming into like '25, where we've got some very large growth on a limited amount of capital in the deepwater, that gives us some very high return investments because, in some cases, we're being reimbursed for the capital or the producer is providing the capital upfront on some of those big deepwater projects. So obviously, those returns are kind of outsized there and will provide better growth. But in general, as Micheal said, we're expecting this $1.2 billion to $1.3 billion capital, and we believe that kind of investment will continue to propel the 5% to 7% growth rate.

Okay. And in regards to the Eagle Ford, I think you mentioned you're seeing some activity pick up there. I was curious what kind of gas or NGL prices kind of support this uptick in activity? And do you anticipate this activity uptick to kind of go into 2023 and further out?

Yes. I would just say that the Eagle Ford is highly economic right now. Chesapeake has been allocating more of their capital to their gas-focused areas and they have been out in the market talking about the potential to settle their Eagle Ford position. But we see both on the rich gas side and on the oil side of that system. We have really two different systems there in oil-driven system and a rich gas gathering system. And as Alan mentioned, the rich gas gathering system has already been ramping up in activity and is now exceeding the MVCs. And we're seeing, I think, very strong economics behind the oil side of that asset as well. And so we would expect that you'll continue to see increased activity on the oil side as well. So that's a very highly economic asset and really has just been not the #1 priority for kind of the current producer there.

I wanted to revisit the Haynesville. You are clearly increasing your own volumes and discussing the addition of significant gathering capacity over the next year. Could you share your thoughts on the takeaway from the basin and any differential impacts on your upstream business, especially over the next nine months until we get LEG on?

Sure. Thanks for the question. This is Micheal again. I would say we're very well positioned with our gathering systems connected to about nine different outlet pipelines out of the basin. Having Sequent alongside us to evaluate those takeaway opportunities has been very helpful. I believe they have been proactive in addressing any anticipated constraints in the market and have successfully secured additional capacity out of the basin. This ensures that both our customers' volumes and our partnership's upstream volumes can flow smoothly. We feel very comfortable about our ability to get our gas out of the basin as well as our customers' gas. We have assisted many of our customers in ensuring they have opportunities to move their gas based on insights from Sequent, and we feel confident in that. We are also working diligently to get the Lake project operational as quickly as possible to prevent any constraints for our customers or our partnership.

Maybe one last one for me. you just walk us through, again, final steps on Regional Energy Access? I know we're kind of looking for a few things from the FERC, but more importantly, a couple of things on the state side, maybe just a refresh there would be helpful.

Yes, Micheal once again answering this question. We are awaiting the FERC 7(c) certificate. We would expect to have that before the end of the year. The final EIS was issued in July, just as a reminder, that was a very favorable EIS for the project. The other remaining outstanding permits are the air permit. This is a Title V modification for Section 505 in New Jersey. Went through the whole public comment process, and this is a great opportunity for us to once again deploy our emissions reduction program here. We take off some existing compression and replace it with a much better emissions profile. So very favorably received by the state. And certainly, we saw some very positive comments there in the public comment meetings, overwhelming support for that. So we expect that air permit by the end of this year as well. And then finally, the core engineers will issue a 404 permit. This is a water quality permit. We would expect that probably in the first quarter of '23, but it could come as early as the fourth quarter here in '22. We've already had our 401 water certification in the State of Pennsylvania that's been in hand for a number of months now, and no technical issues remaining on the 404 permit just waiting for the process to play out. So those are the 3 outstanding things we're waiting on Regional Energy Access for right now. And just as a reminder, we positioned this project very well to avoid any controversial permits and certainly position that air permit in New Jersey to be favorably received with deployment of new compression there to take off some old vintage reciprocating compression.

Okay. Well, thank you all very much for the great questions and appreciate your continued interest in the company. We're very excited about the way the business is running right now, and we're extremely well positioned for growth in '23 as we discussed, and we look forward to talking to you at our 4Q earnings call and laying out in more detail what '23 looks like. So thanks again for joining us this morning.