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spk01: Good day, everyone, and welcome to the Williams Third Quarter 2022 Earnings Conference Call. Today's conference is being recorded. At this time, for opening remarks and introductions, I would like to turn the call over to Mr. Danilo Giovanni, Vice President of Investor Relations. Please go ahead.
spk11: 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 a Alan Armstrong, and our Chief Financial Officer, John Porter, who will speak to us this morning. Also joining us on the call today are Michael Dunn, our Chief Operating Officer, Lane Wilson, our General Counsel, and Chad Demeron, our Senior Vice President of Corporate Strategic Development. In our presentation materials, you'll find a disclaimer related to Florida Liquor Statements. This disclaimer is important and integral to our remarks, and you should review it. Also included in the presentation materials are non-GAAP measures that we reconcile to generally accepted accounting principles, and these reconciliation schedules appear at the back of today's presentation materials. So with that, I'll turn it over to Alan Armstrong.
spk15: 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 this 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 US 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 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 pipeline 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 GMP 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 costs 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 file 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 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 GMP business, we expect higher volume growth and higher cash flows from expansion projects that are currently underway, and many of those are nearing completion. And we do provide some details of those in the appendix. In the West GMP 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 latent midstream capacity is working. We expect modest growth in other basins as well. For instance, in the Eagleford, 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 a welcome rebound and extend our earnings above that MVC level. The Eagle Board 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 and 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 will 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 is also will be included in our transmission in 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 Crowhart 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 latent 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 benefit 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 Nortec 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 Penn Energy 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. John?
spk10: Thanks, Al. Starting here on slide two 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 fluctuations, and 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 2.4 times for third quarter and 2.29 times year-to-date. Our debt to adjusted EBITDA metric continues to improve based on our strong growth and adjusted EBITDA and our capital investment discipline, now reaching 3.68 times versus last year's 4.04 times. 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 and our core-related gathering assets, and that's certainly what we see happening in 2022. Shifting now to our core business performance, our transmission and 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 Light East-South Expansion Project, which came online in phases last year. Gulf of Mexico was significantly higher in 22 due in part to a 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 GMP 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 2022 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 29th 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 and NGO marketing services business. This increase was despite taking a $54 million lower cost or market adjustment to our gas and NGO 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 four 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 dollars of first quarter 2021 winter storm benefits that we're showing here in gray and then moving to the 182 million dollar contribution from our midstream operations which were warm soda related in the first quarter of 22 and then began to have a more significant haynesville component in the second and third quarters our transmission in gulf of mexico business has seen four percent growth year to date driven by transco's lighty 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 GMP 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 base rates but also strong 11% overall volume growth, excluding the trace acquisition. Finally, our gas and NGO 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 1st of 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 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 10Q 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. Alan?
spk15: 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. And in fact, this is a a 21.7% return on invested capital as we've showed in recent presentations. We've 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's 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 impacts 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, unobstructed build-out of our nation's energy infrastructure to ensure delivery of natural gas is foundational to the U.S.' '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.
spk01: At this time, if you'd like to ask a question, simply press star followed by the number one on your telephone keypad. To withdraw your question, press star one again. Our first question will come from the line of Jeremy Tonette with J.P. Morgan. Please go ahead.
spk08: Hi, good morning. Good morning, Jeremy. Just wanted 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 on what moved that forward at this point? Was it the higher 45Qs coming from Aira here that got over the finish line? And also, I guess, how big could the scope of this project be over time? Thanks.
spk14: Yeah, thanks, Jeremy. This is Chad. Yeah, the IRA and the increase in 45Q credits is certainly a benefit that helped 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 vented 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, you know, 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 length project, which could be in service as early as Q4 of 24.
spk08: Got it. Very helpful there. Thank you. And just wanted to pivot, if I could, to the producing assets in the Hainesville. 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?
spk15: Yeah, Jeremy, I just let me be clear on that. First of all, I think there's been a lot of confusion out there in the market on the forms of those contracts. We expect production, our net interest production to continue to grow in 23. And so we have been very pleased with Geo Southern's efforts out there. They've been a great operator and they've really been hitting it out of the park, so to speak, in their efforts and the performance on wells, both on the cost side as well as delivery side. So we're really excited about their activities out there. So we do, just to be clear, we do expect our net interest production to continue to grow into 23. And so people have been talking about a decline relative to the reversion. Our interest in the undeveloped acreage declines, but not our interest in the existing flood production. And in fact, the nice thing about that is our capital obligations really fall back really hard in 23 after that decline. reversion occurs because we won't be continuing to have to invest so heavily in the drilling operations there. So but in terms of looking for, you know, to sell the asset, we certainly that is our long term objective and continues to be. And we think the acreage is certainly proving itself up to exceed. And I would tell you, though, it's got a long ways to go from where it is today in terms of total volume growth. in that area. In fact, they're really just starting to scratch the surface of that inventory in the area. So yes, we certainly have our eyes and ears open, but no, we are not getting near the peak of the volumes out there at all. And so it's really playing out almost exactly like we intended, except that we've had this nice big upside of pricing here in the current environment. And the volumes this year have been are outperforming where we thought they would be. So great news really kind of all the way around there in terms of upside, and it's going to drive a lot of free cash flow into 23 and 24.
spk08: Got it. And just a quick follow-up on that. Is there a certain production level you're looking for before you would entertain divesting those assets?
spk15: No, I would just say there's a lot more room to grow out there than what people are expecting, I think. I think we continue to be impressed by the kind of numbers that GeoSouthern is informing us on in terms of kind of what the total production out there that's well beyond the current production level. So I would just say we're not waiting, if you will, necessarily. We just want to be assured that the production growth will continue on the pace kind of if we're not the owner. And I think certainly the alignment we've had with Geo Southern out there has been productive for both of us. But no, we're not waiting on any particular volume number. We think that the evidence is pretty clear in terms of the performance out there at this point. So we think that the viability of that acreage has been pretty well proven up already just in terms of the performance of Geo Southern showing already.
spk08: Got it. I'll leave it there.
spk04: Thank you. Thanks, Jim.
spk01: Your next question will come from the line of Praneet Satish with Wells Fargo. Please go ahead.
spk12: Thanks. Good morning. 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 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?
spk15: Yeah, thanks for the question. And first of all, Sequent was a sizable customer there to Nortex, and we were looking at their process as they were going through that. to and realizing what they could charge for that storage. And frankly, we were pretty impressed and from our perspective what they could have charged for storage in that area and recognize that we thought that rates could probably be driven up there just because of the value of that storage in these more volatile markets. And we continue to believe that today. The load from the variability of power generation, gas-fired power generation, as well as LNG, we think is going to continue to drive value for natural gas storage. We're certainly seeing that as sequent with a buyer of storage. It continues to be a large buyer of storage. We understand that market very well, and we think there's a lot of value there. That's the first thing. Second thing, one thing that I commented on in my opening comments that we're excited about as well is we did get an order from the FERC last week to be able to put market-based rates in place on our washing and gas storage. We still have a lot of work to do on that, so we have to go through the process of filing those rates, but we did get a very important order out of FERC last week to be able to go to market-based rates for our washing and gas storage. And so that is a very large deal for us. That's about 75 BCF a day. of working gas storage. And so, that gives us about 110 BCF a day of storage in the Gulf Coast area between Nortex and Washington Gas Storage. So, yes, we are pretty committed to this concept. We think there's a lot of value there and finding ways to extract the real value out of our current assets and out of Nortex is certainly going to be a mission for us in the years looking forward.
spk12: Great. And just switching gears, if I look at the financial metrics this year, the leverage is good and EBITDA is on pace to grow 13% or 14%. But on the capital return side, the dividend is only up 4% and there's been some buybacks, but it's been fairly modest. So I guess my question is, does the strong performance this year influence how you look at capital return heading into 2023?
spk15: Well, that's a great question. And the answer is yes, it certainly does influence how we look. And we recognize we're outpacing both our AFFO and our EBITDA have been outpacing our dividend growth. And we certainly recognize that. And so I would just say we're going to make sure that Our dividend is durable, but we also, you know, we've also said that we're going to continue to grow our dividend along with our cash flows. So it's a great question. Board level decision will be made later this year and into next year that decision will get made. But we certainly have the coverage and the cash flow growth to be able to increase the growth rate in our dividend at this point.
spk04: Thank you.
spk01: Your next question will come from the line of Chase Mulvihill with Bank of America. Please go ahead.
spk09: Hey, good morning. I guess just a quick question and kind of want to follow up. You mentioned a little bit of this during the prepared remarks, but just kind of looking forward to 2023, you know, thinking about some of the puts and takes. I mean, obviously when you look at 23 versus 22, you got, you know, full year of some of the M&A you did. You've got the Spring Ridge gathering expansion and some Northeast gathering expansion. And then you've got some Gulf of Mexico stuff that starts up and you'll probably have some higher EMP volumes. So I guess just am I missing anything there when we think about 23 growth opportunities and then kind of offsets? How should we think about the offsets for 23? the curves backward dated, but you know, the curves, uh, you know, not always right, but just kind of, how should we think about the offsets in 23?
spk15: Yeah. Great, great question. I think you, you know, you laid that out pretty well, actually, you know, 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 warm Sutter JV this year. As I mentioned, we, we have, uh, We're continuing the drilling program, but we are just now starting the completions effort out there, and so the benefit of that, those 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 Eagleford, we're seeing some pretty rapid development going on in the rich gas that will exceed the MVC out there, so that's attractive. In terms of the headwinds, I certainly think, you know, 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, there's probably not likely going to be that big a spread, but I would say we're, you know, we continue to look at the strip. So that's probably the, you know, the primary headwind, but I 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.
spk09: That all makes sense. As a kind of, I guess, maybe a somewhat related follow-up, on slide 24, you show an 8% increase in power demand year-to-date. I obviously don't do too much on the power side, but could you kind of explain kind of what's happening there and how sustainable you think that that growth is in power demand as we kind of look forward?
spk15: Yeah, I would just say, you know, we continue to be surprised. I would say that probably, as we mentioned earlier in the year, probably our biggest surprise has been the resilience of gas demand in the face of higher price. And I think what we learned was that the utilities and the power generators are not really able to flip back to coal for a number of reasons. One, they don't have the long-term contracts. A lot of those expired. And two, obviously, the price of coal has, you know, come up right alongside gas. And so we just did not see the flip back to coal-fired generation we would have expected at this kind of pricing environment. Obviously, I think it's what you're seeing as a result of utilities, and I don't think this is going to end anytime soon, where as renewables come on, the backup for that is going to be natural gas, and it's going to continue to take coal-fired generation out of space, and we're going to continue to see increases. So, if you're listening to the rhetoric in the market and in the media, you would think that gas volumes were going to declined dramatically, if you saw the RFPs for new services coming in our door, you would think otherwise. And so I think, you know, what we are seeing is continued strong demand from gas fire generation from the utilities, particularly in the mid-Atlantic and the southeast. So we remain bullish, not because of rhetoric, but because of what we're seeing for requests for long-term services coming in the door.
spk09: Very perfect. Understood. I'll turn it back over. Thanks, Alan.
spk01: Your next question will come from the line of Gabriel Morin with Mizuho. Please go ahead.
spk00: Hey, good afternoon, everyone. 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 LEG 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?
spk13: Hi, Gabe. Good morning. It's Michael. Yeah, I would expect, as we talked about in previous calls, to see some lumpiness in our growth capex. As you indicated, we've got regional NG access that we'll be ramping up construction next year. The whale project, although we started construction on that, will be ongoing as well in 2023. And obviously, leg will be ramping up as well. So those are some pretty large capital outlays that we'll be ramping up next year. But as we've indicated in the past, we're working real hard to keep our growth capex in line with previous years. And so you think about where we're at this year, the 1.2 to 1.3 billion level. That's what we're targeting on typical years going forward. But you will see some lumpiness when these big projects start construction. So you can anticipate that being a 2023 story with these big projects coming on. But we're still very focused on managing that growth capex to a level that's about $1.2 billion on average per year.
spk00: Thanks, Michael. 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?
spk13: Yeah, 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, put 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 it's 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 admissions 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 is a significant order of magnitude higher than Northwest, but certainly a great opportunity there. very well received by our customers on Northwest Pipeline for us to go and implement these emissions reductions.
spk00: Great. And maybe if I could squeeze just a quick last one. 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?
spk02: Yeah, this is Blaine Wilson. We would anticipate sometime probably late Or late second quarter, early third quarter, maybe even early fourth quarter, depending upon how quickly the dollar moves.
spk04: Great, thank you. Yeah, 2023.
spk01: Your next question will come from the line of Brian Reynolds with UBS. Please go ahead.
spk03: Hi, good morning, everyone. Maybe just talk a little bit about, you know, follow up on capital allocation and the growth capex, you know, with the acquisitions of Trace and Nortex, you know, could you just maybe talk about what the base business kind of growth capex run rate is going forward now?
spk13: Yeah, sure. This is Michael. 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 loneliness anticipated there when these larger projects start to ramp up construction. Regional Energy Access will 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 to $1.3 billion average CapEx on our growth side for the foreseeable future.
spk03: Great, thanks. And then maybe as a follow-up on some of the upstream business, you know, 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 by 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. Thanks.
spk15: Yeah, thank you. Well, we do have some favorable hedges on right now for 23. I think we've got around 15% or so for the year that's on right now. And we'll continue to look at that optimistically. I would tell you that, you know, it's really nice having our sequent team that is joined at the hip when it comes to making those decisions and having a real vantage point on the market and what they're seeing as well. So I would just say we will continue to be somewhat optimistic about that. uh we certainly will continue just like we did this year we'll continue to take on hedges as we see fit but i would say we don't have any particular uh formula or requirement for that it's simply a way of um when we see opportunities in the market we see things flare up in the market we'll we'll hedge into that and uh so i would say it's be fairly opportunistic but with no particular
spk03: requirement for a minimum level of of hedges to be put on right would second half 22 be a good kind of parameter of where we should expect it going forward or um you know i guess remain to be seen i'm sorry i didn't quite follow that Last part of the 50% hedging profile that you kind of had outlaid for the second half of 22.
spk15: Is that kind of a fair estimate for 23 or, you know, I mean, I would just say it's, you know, very dependent on what the markets do versus how we, how we're seeing the fundamentals looking forward. The good news is we, We have such a good read on both what's going on in production because we gather in 15 different basins, so we have a very good read about what's going on in production, as well as we see a good read from the markets as well that we use that to inform our fundamentals. And if we see the pricing obviously get fair relative to those fundamentals, then we will hedge. So again, I wouldn't put a particular percentage on it as much as it is us looking at the fundamentals versus the pricing and the poor markets.
spk14: Alan, it may be worth mentioning that 23 will have less to prove up as far as volumes. In 22, we did have the growth in the Hainesville 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.
spk15: Yeah, 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 production 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 Hainesville, we'll have less of that volume growth risk, not so much in the Wompson. Great.
spk03: No, that's super helpful. I appreciate the color and enjoy the rest of your morning, everyone.
spk04: Thank you.
spk01: Your next question will come from the line of Sunil Saval with Seaport Global. Please go ahead.
spk06: Yes. Hi. Good morning, folks, and thanks for all the clarity. 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?
spk15: 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 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 in into like 25 where we've got some very large growth on a limited amount of capital in the deep water 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 up front on some of those big deep water projects. So obviously those returns are kind of outsized there. And we'll provide better growth. But in general, as Michael said, we're expecting this $1.2 to $1.3 billion capital. And we believe that kind of investment will continue to propel a 5% to 7% growth rate.
spk06: Okay.
spk15: Thanks for that.
spk06: And then regards to the Eagleford, I think you mentioned you're seeing some activity pick up there. I was curious, you know, what kind of, you know, gas or NGL prices kind of support this uptick in activity, and do you anticipate this, you know, activity uptick to kind of go into 2023 and further out? Yeah.
spk14: I would just say that the Eagle Bird is highly economic right now. You know, 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 sell their Eagleford 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, an 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 NBCs. And we're seeing, I think, very strong economics behind the oil 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 that really has just been not the number one priority for kind of the current producer there.
spk04: Got it. Thanks for that.
spk01: Our final question will come from the line of John McKay with Goldman Sachs. Please go ahead.
spk05: Hey, everyone. Good morning. Thanks for the time. I wanted to pick up on the Hainesville again. You guys are obviously adding a lot of your own volumes. You're talking about adding a lot of gathering capacity over the next 12 months. Can you maybe just share some of your thoughts on how we're thinking about takeaway out of the basin and maybe, you know, differential impacts on your upstream business, particularly on the, you know, next nine months until we, or next while until we get leg on. Thanks.
spk13: Sure. Thanks for the question. This is Michael again. I would say we're very well positioned there with our gathering systems being connected to about nine different outlet pipelines out of the basin. And having Sequent alongside us evaluating those takeaway opportunities has been very helpful. I believe they were well in front of any anticipated constraints out there in front of the market. and really went out and acquired some capacity out of the base and it made sure that not only our customers volumes could flow but our partnership upstream volumes could flow as well so we feel very comfortable about our position in getting our gas out of the basin as well as our customers gas out of there we've helped a lot of our customers make sure that they had opportunities to move their gas out of the basin based on what we were seeing with sequin so We feel really good about that. We're certainly working to get the lake project up and running as fast as possible to help make sure that none of those constraints arise for our customers or our partnership.
spk05: All right. Thanks. Maybe one last one from me. Can 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 things from the state side. Maybe just a refresh there would be helpful. Thank you.
spk13: Yeah, I sure think Michael, once again, answering this question. We are awaiting the FERC 7C 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 Station 505 in New Jersey. We've been 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 Corps of 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 from 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 three 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 positioned that air permit in New Jersey to be favorably received with the deployment of new compression there to take off some old vintage reciprocating compression.
spk04: That's great. Thanks for that. Appreciate it.
spk01: At this time, I'll turn the call over to Alan Armstrong for closing remarks.
spk15: 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.
spk01: Ladies and gentlemen, that does conclude today's call. Thank you all for joining. You may now disconnect.
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