Good morning, my name is Chilly (ph), and I will be your conference operator today. At this time, I would like to welcome everyone to the Q3 2021 NiSource Earnings Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. Mr. Turnure, you may begin your conference.

For Joe Hamrock, Chief Executive Officer, Donald Brown, our Chief Risk Officer, and Randy Hugen, our VP of Investor Relations and Treasurer. The purpose of this presentation is to review NiSource's financial performance for the 3rd quarter of 2021, as well as provide an update on our operations and growth drivers, following our prepared remarks, we'll open the call to your questions. Slides for today's call are available on nisource.com. Before turning the call over to Joe, Donald, and Shawn. Just a quick reminder. Some of the statements made during this presentation, we will be forward-looking. These statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in the statements. Information concerning such risks and uncertainties it included in the MD&A risk factors sections of our periodic SEC filings. Additionally, some of the statements made on this call relate to non-GAAP measures. For additional information on the most directly comparable GAAP measure and a reconciliation of these measures, please refer to the supplemental slides and segment information. Including our full financial schedules available on NiSource.com. With all of that out of the way, I'd like to turn the call over to Joe.

Thanks, Chris. Good morning, everyone, and thank you for joining us. Hopefully you've all had a chance to read our Third Quarter earnings release which we issued earlier today. Strong execution of NiSource's significant renewable energy investments continues to be the highlight of our foundation for future growth. And we continue to expect that our core infrastructure programs and renewable generation investments will drive industry-leading compound annual growth of 7% to 9% percent in diluted net operating earnings per share through 2024. Growth driven by our commitment to safety, reliability, customer affordability, and sustainability. As we begin to refine our outlook for longer-term growth, the preferred path from NIPSCO 2021 integrated resource plan identifies additional investment opportunities while advancing the retirement of remaining coal-fired generation between 2026 and 2028. And it supports our plan to reduce greenhouse gas emissions 90% by 2030. Let's turn now to Slide 3, and take a closer look at our key takeaways. We are updating our guidance for 2021 to target the top end of the range of a $1.32 to a $1.36 per share in non-GAAP diluted net operating earnings or and or EPS. We are also initiating guidance for 2022 of a $1.42 to a $1.48. and that is consistent with our 5 to 7% near-term growth commitment. Our long-term diluted EPS guidance of 7 to 9% through 2024 is now based on the expected top end of our 2021 guidance range. And we reaffirm 5% to 7% growth in 2023. As I mentioned a moment ago, the preferred plan from NIPSCO's 2021 IRP advances our plans to retire remaining coal-fired generation between 2026 and 2028. As we shift to lower-cost, clean, and reliable generation. Investments of up to $750 million will be required to replace retiring coal-fired generation. The NIPSCO portion of this investment will be better understood following further evaluation of the proposals, we solicited associated with the IRP. Our regulatory execution progresses with a proposed order approving a settlement in Pennsylvania, a settlement filed in Kentucky, and a proposed order in Maryland. In addition, we filled a gas rate case in Indiana in September. We achieved non-GAAP diluted NOEPS of $0.11 in the third quarter of 2021 versus $0.09 in 2020. Now let's look at some NiSource Utility's highlights for the 3rd quarter. Starting with our gas operations on Slide 9. The Columbia Gas of Ohio rate case continues to progress. Net of the trackers being rolled into base rates, the filing requests an annual revenue increase of approximately $221 $221 million pending its decision next year from the Public Utilities Commission of Ohio, new rates would be effective in mid-2022. NIPSCO filed a gas rate case on September 29th, requesting a revenue increase of a $115 million annually. The case is focused on infrastructure modernization, and providing safe, reliable service while remaining in compliance with state and federal safety requirements. In Pennsylvania an administrative law judge issued a proposed order recommending that Pennsylvania Public Utility Commission approved a settlement in our rate case. The settlement would increase revenue by $58.5 million with new rates effective December 29, of this year. The adjusted rates will help to continue investments in infrastructure upgrades, system reliability, and maintenance enhancements. We expect the commission's final order by mid-December. In Kentucky, we have filed a proposed settlement of our rate case. The settlement includes an overall increase in revenues of $18.6 million to support continued investments in safety and replacing aging infrastructure. Columbia Gas of Maryland received a proposed order from an administrative law judge on Friday, recommending an increase of approximately $2.56 million in revenues as compared to our request of approximately $4.8 million. We expect a final order from the Maryland Public Service Commission in December. Before we move on, I'd like to note that Columbia Gas of Ohio, our largest LDC is ranked number one in the Midwest region in JD Powers ' 2021 Gas Utility, Business Customer Satisfaction Study. Also, congratulations to our customer experience team for the successful launch of the Columbia Gas and NIPSCO mobile apps. They're an important step forward in building our connected digital customer experience. Let's now turn to our electric operations on Slide 10. NIPSCO electric T-disc plan is pending before the Indiana Utility Regulatory Commission or IURC. This is a 5-year $1.6 billion proposal that would replace the previous plan, which NIPSCO filed in April to terminate. The pending plan includes newly identified projects aimed at enhancing service and reliability for customers, as well as some previously identified projects. The other items on this slide relate to our renewable generation strategy. And I'll turn it over to Shawn Anderson to give more detail.

Thank you, Joe. The selection of the preferred path from NIPSCO's 2021 IRP is a significant milestone in our transition from coal-fired generation, towards cleaner and reliable forms of generation, all of which are expected to save NIPSCO customers approximately $4 billion over the long term. The preferred path from the 2021 IRP, refines the timelines to retire coal-fired generation at the Michigan City Generating Station to between 2026 and 2028. It also calls for retirement of 2 vintage gas peaking units, 16A and 16 B, which are both located at the Schahfer Generating Station site. The most viable replacement option calls for a portfolio of resources including incremental solar, standalone battery storage, and natural gas peaking resources. We estimate that investment of up to $750 million will be required to support the retirement of these units. We expect to be able to quantify the NIPSCO portion of this investment opportunity. In the first half of next year, after further evaluating bids and the request for proposals and completing due diligence on projects which align with the preferred path. Meanwhile, we continue to execute on a plan for retirement of remaining coal-fired generation at Schahfer. Units 14 and 15 retired as of October 1st, and units 17 and 18 are on track to retire by 2023. We're making steady progress on the renewables project build-out, informed by the preferred path from NIPSCO's 2018 IRP. Our partners on these projects are some of the strongest developers in the renewable energy space. And we remain in close contact regarding the progress of these projects. We continue to expect to invest approximately $2 billion in renewable generation by 2023 to replace the retiring capacity at As part of the execution of this plan, construction continues on the Indiana Crossroads one wind project, which is on track to become operational in the fourth quarter of this year. Construction has also started on a pair of solar projects. Dunns Bridge Solar I is being constructed by a subsidiary of NextEra Energy Resources under a build transfer agreement. EDP Renewables North America is building the Indiana Crossroads solar project, which will be operated as a joint venture. Both are expected to enter service next year. The IURC provided regulatory approval of the Indiana Crossroads II Wind project on September 1. And with that action, all 14 renewables projects needed to replace the retiring capacity of Schahfer Generating Station have now received approval. In addition to the slate of renewables projects we have announced, NiSource plans to evaluate hydrogen and emerging storage technologies. It's important for us to gain a risk informed understanding of the options and technologies that may emerge as pathways toward further de - carbonization. Now, I'd like to turn the call over to Donald, who will discuss our third quarter financial performance in more detail.

Thanks, Shawn. And good morning, everyone. Before getting into the specific results, I just like to highlight the solid execution and progress that now has us guiding to the top end of our 2021 guidance range of $1.32 to $1.36. This new 2021 expectation also serves as the starting point for both our near-term and long-term growth commitment. We have also initiated 2022 guidance of a $1.42 to a $1.48, which at its midpoint represents a growth rate of over 6.6% from the 2021 top end. Turning to our third quarter 2021 results on Slide 4, we had non-GAAP net operating earnings of about $47 million or $0.11 per diluted share, compared to non-GAAP net operating earnings of about $36 million or $0.09 per diluted share in the third quarter of 2020. The 2021 results reflect our ongoing execution of infrastructure investments, offset somewhat by the sale of Columbia Gas of Massachusetts, which closed in October of 2020. Looking more closely at our segment 3-month non-GAAP results from Slide 5, Gas Distribution operating earnings were about $18 million for the quarter, representing an increase of approximately $8 million versus last year. Operating revenue, net of the cost of energy and tracked expenses, were down nearly $18 million due to the sale of CMA. Operating expenses, also, net of the cost of energy and tracked expenses were lower by about $26 million, mostly due to the CMA sale offset slightly by higher employee related costs and outside services spending. In our Electric segment, 3-month non-GAAP operating earnings were about $130 million, which was nearly $3 million lower than the third quarter of 2020. Net of the cost of energy and tracked expenses, operating revenues decreased slightly by about $2 million due to slightly lower residential usage, offset by increased TDSIC revenues. Operating expenses, net of the cost of energy and tracked expenses were nearly flat compared to 2020. Now, turning to Slide 6, I'd like to briefly touch on our debt and credit profile. Our debt level as of June 30 was about $9.6 billion of which about $9.2 billion of long-term debt. The weighted average maturity on our long-term debt was approximately 14 years, and the weighted average interest rate was approximately 3.7%. At the end of the third quarter, we maintained net available liquidity of about $1.7 billion consisting of cash and available capacity under our credit facility and other accounts receivable securitization programs. As we know that last quarter, all 3 major rating agencies have reaffirmed our investment grade credit ratings with stable outlooks in 2021. Taken together, this represents a solid financial foundation to continue the support for our long-term safety and infrastructure investments. As you can see on slide seven, we've narrowed our 2021 capital investment estimate to approximately $2 billion, and reiterated our 2022 capital forecast of $2.4 to $2.7 billion. Taking a quick look at Slide 8, which highlights our financing plan. There are no changes to our plans since April's equity unit issuance. I would highlight that this balance financing plan continues to be consistent with all of our earnings growth, and credit commitments. As I mentioned earlier, we have updated our 2021 earnings guidance, issued guidance for 2022 and reaffirmed our long-term growth commitments. I would also remind everyone that we're planning to provide an extension to our growth plan at an Investor Day during the first half of next year. So please stay tuned. Thank you all for participating today and for your ongoing interest in and support of NiSource. We're ready now to take your questions.

Thank you. At this time, I would like to remind everyone. . Your first question comes from Richard Sunderland from JPMorgan. Please go ahead.

Good morning. Thanks for taking my questions. Maybe starting with the IRP here. Curious to get outlined the guard rails on the potential investment in any gating items here as we progress to the update in the first-half of next year in terms of the high-low and where that could realistically fall in the $72 million?

Thanks for that question. Good morning, this is Shawn. Ultimately, as you can imagine the range will be informed by the actual project selected. What we know now are the tranches of technology that we believe will provide the capacity. We need to step through the due diligence now to better understand those projects, and that will inform in some way, shape or form the specifics of the range. So certainly, the selection of technology, the actual projects themselves, how efficient they can be constructed, those types of things will have a bearing on the ultimate CapEx for it. I'd also note that the MISO's Resource Adequacy rules, certainly as those finalized, could come into play a bit as well that we think that we've modeled those out and incorporated that in the indicative pathway.

Thanks, Shawn. Rich, let me just add. All else being comparable through that analysis, we have a bias to own these assets as we step through this next progression, and we believe we'll have a strong case and a value proposition for doing that. As Shawn noted the factors or guardrails, as you said, do include the MISO seasonal capacity factor, ultimate requirements in the evaluation of the proposals that is still underway. But also, the federal policy landscape that is a bit unpredictable right now, but that could shape timing and mix of investments as well. We look forward to being able to work through that in the next quarter or two.

Thanks Shawn. Maybe just following up on the federal aspects, could you unpack that a little bit more in terms of what could specifically impact the 2021 IRP considerations or maybe even more broadly, whether it's the financing plan. How could something like direct pay change those plans now?

Hi. I can take the direct pay question. Certainly, think that that provides some additional flexibility on how we finance our renewable investments. Certainly positive, if it allows us to reduce any equity needs for those future investments or external financing needs in terms of tax equity, but certainly need to understand how direct pay would be treated by our 6 jurisdictions from a base -- rate base in deferred tax standpoint.

And then I just add on as it relates to how federal policy could shape the technology costs that we certainly can't speculate to that the 750 is a derivative of what we saw come through the RFP in May, related to the capacity and the technology required to meet that capacity, to the extent that the marketplace changes that efficiency. It again, it could get you back into a different selection of technology to comprise the capacity necessary. But you'd have to see how that federal policy landscape would impact that marketplace versus the due diligence, which we're performing on actionable projects that came through the RFP that we expect to be able to execute against.

Thank you, . Thank you for the time here. Thanks.

Thanks, Rich.

Your next question comes from Insoo Kim from Goldman Sachs. Please go ahead.

Yeah. Thank you. My first question is just going back to the RP, that $750 million potential. Is that the total opportunity set, whether it's Just TPA or owned or does it contemplate some percentage of ownership there? And then the follow-up to that is, if we're taking the more accelerated retirement options in the 2026 retirements, how much of that potential investment could come in the 2025 time period?

Thank you for that. The 750 is the total inclusive number of investments expected to be able to functionally deliver the capacity, once the capacity gap is created through the retirement of Michigan City and units, A and D. So, it'd be everything included. Also inclusive of the transmission that we anticipate necessary to construct to enable that to occur. And then in terms of timing, there is some flexibility because these projects in some ways could be a little bit modular in nature. It provides us a fair amount of flexibility to optimize that. The transmission work, for example, is going to begin immediately, and it could take up to 3 years to complete the transmission work necessary to take those units offline. So, the other resources could be feathered in, likely starting in that 2024-time horizon. But we'll know a lot more through the first half of 2022, after we've gone through the due diligence process and started to select the exact projects that we think can deliver that capacity.

Got it. That's good color. My second question is on the dividend policy, I think over the past, where this time around and then the past couple of years, I think the growth in the dividend has been a little bit more modest versus history, and as we get back into this more robust EPS, growth cycle, and I think you had a 60% to 70% payout ratio target as of the last disclosure. How should we think about some of the future dividend growth trends that we could see over the next few years?

Good morning. For the 60, 70% payout ratio that is still our guidance at this point, we will revisit our dividend on our -- in January as we normally do with the board. But when you look at our long-term plan and 7% to 9% EPS that we've indicated, you certainly would expect to see growth in that range. Seeing growth along annually because of the earnings growth in that range of 60 to 70%. But again, we'll provide an update in January.

Got it. Thank you so much.

Your next question comes from Julien Dumoulin -Smith with Bank of America. Please go ahead.

Hey, good morning, this is actually Cody Clark on for Julien. Thanks for taking my questions.

Good morning, Cody.

First, a housekeeping item and just to clarify, if I'm thinking about 2023 EPS, what base should I be using for the 5% to 7% growth? Is it the top end of '21 or the midpoint of the new '22 guidance?

I would use the top end of '21 as the guidance going forward for '22 and for long-term 7% to 9% EPS

Okay. Got it. And then one of the main variables on NIPSCO share of would be the breakdown of ownership versus PPA, and certainly understand the bias to own here. We're wondering if you can talk about how you, other stakeholders, and your regulators are thinking about ownership percentage of the resources? Have you had any conversations here or how do you think that's going to shake out?

Thanks for that question. We have not had any discussions regarding ownership percentages. We've just focused on the tranche of technology delivered -- to deliver the capacity. And certainly, that's been the main focus to understand what the solutions and the pathway we expect to transpire. And then we would need to complete the full due diligence necessary on the projects themselves to better understand that ownership percentage, although I'd note that certain of these asset classes track towards a higher ownership percentage. For example, a SugarCreek upgrade would make a lot of sense for us to own at our own plant. So, there is a bias down and some of these asset classes could track toward that. However, we'd need to complete the full due diligence to have a final point-of-view which we expect in the midpoint of next year.

I don't -- I'd only add to that, I'd note that key drivers, ultimately, the cost to customers over the life of the projects. And that's probably the first variable we look at for comparability across different ownership structures.

So, looking forward to the first half update then, and we've seen some of your peers introduced longer-term capex and growth plans to highlight kind of the runway for spending. Do you see yourself in a position to be able to provide that level of disclosure when some of these spending items, around generation become a little bit clearer in the first half of next year?

Yeah. Absolutely. We are intending to have an Analyst Day somewhere in that first half of next year. The goal of that Analyst Day would be to provide more clarity around the next-generation investments to replace the Michigan City, as well as to extend the long-range plan for both our gas and electric businesses.

Got it. That's very helpful. Thanks so much for the time and looking forward to seeing you all next week.

Thank you.

And your next question comes from Travis Miller from Morningstar. Please go ahead.

Good morning, everyone. Thank you.

Hey, good morning, Travis.

Question on the electric side of NIPSCO back to the IRP. How do you think about the timing and relationship between the IRP and as you go through the process, therapies, etc., and the T-Desk? Are regulators thinking about these in terms of the need for new transmission and distribution to supply and support the IRP? And how does that work?

Yes, that's a good question, Travis. The TDSIC really operates on kind of the existing transmission assets on maintenance and reliability improvements. Not so much new capacity related to new generation or retiring generation. So, there's no a direct relationship between Tejas. Depending Tejas schedule as you know it doesn't really depend in a meaningful way on the IRP. Typically, the projects we're looking at from the RFP within the integrated resource plan are tied to specific transmission investments that are inside the bids that we solicited. So, with those really don't crossover in a meaningful way.

Okay. So, we could see more transmission investment as you roll out some of the IRP steps?

That's right. Just like we have in the current cycle, we're in the 2 billion includes pretty healthy transmission investment as well.

Okay. Great. And then on the gas side, what are your latest thoughts on all the discussion about methane emissions? Where does that fit into your capex plan? Obviously, we've heard domestically and internationally.

The EPA methane rule is out now. We see clearly opportunities to improve the emissions profile, particularly that's focused on the upstream asset’s exploration production, transmission, storage. A little bit of a light touch on our asset portfolio. But overall, we believe the right way to drive a cleaner profile for the gas business and the gas supply chain. I would go to the other side and say, one of the provisions inside the pending legislation of the proposed legislation is the methane tax, which we are -- we think is a bad mechanism that basically just drives cost to customer without having the same effectiveness as the EPA methane will. Those 2 certainly work together but the methane rule is a better mechanism. And that helps to drive sustainability of natural gas and to do that in an affordable way, which we think is the right recipe.

Is there any upside to the gas capex, if the government U.S. or even international were to come down really hard on methane?

Yes, will handle the methane rule for the distribution entities, still remains to be seen. We have to see how that rule plays out.

Okay. Great. Thanks so much.

Thank you.

Our next question comes from David Peter, from Equity Wolfe Research. Please go ahead.

Hey, good morning, guys.

Good morning, David.

On the higher earnings outlook off the new base -- the 2021 base. Could you talk about some of the factors that are underlying that better outlook in the interim. And then through 24, and now you have a couple of bigger rate cases pending. Just wondering how sensitive to the the plan is to some of the outcomes there. And then just related to that, maybe you could comment where you are where you guys are at in those cases, I guess specifically, Ohio.

Thank you for the questions. Certainly, as we look at our plan it's really built on the modernization investments that we're making. Think about 75% of those investments being track, that gives us lots of confidence on our year-to-year earnings guidance. This year is a heavy year from a rate case standpoint. We did fall 5 base rate cases in our LDCs, we've got two supplements there and one other and Maryland, we're expecting to get an order in December and then the Ohio and NIPSCO case that we filed will have impact, significant impacts, from Ohio by the middle of next year and then the Fourth Quarter for NIPSCO. That gives us confidence in our earnings guidance and the strength of overall growth plan. But that's what continues and really gives us confidence as we think about that 7% to 9% EPS growth, which includes a $2 billion of generation investments that are already approved through the Indiana Commission this year. So that's the strength of our plan. And that's where -- really what's gives us the confidence of being able to execute on that. Otherwise, it comes down to O and M and managing that. We kicked off our nice horse next transformation program a little over a year ago. That is going well with our plan and our guidance. It really is intended to reduce costs to help offset inflation aspects for thinking long-term around customer affordability, but also improve the rigor of our processes and allow us to improve our safety and customer service to our customers.

And let me pick it up there on the related question around Ohio -- the Ohio rate case. Donald touched on its mid-year expectation in terms of the filing itself with the $221 million asked net of riders. So, there's a rider interplay there as well. But as we all know, not not a lot to report at this time as we all know, the PCO has been very busy. And so, as we see the current workload that the Commission play out, we would expect momentum to pick up no concerns with that. We're early in the schedule overall, but that said given that we're early and not a lot to report, as you would expect and as we expected, discovery activities have been heavy so far. This being the first space case since 2008 for Columbia Gas of Ohio. So, no surprise there. And we believe that parties to the case recognize the long duration between the cases. And our strong investment history and commitment to the state across a range of different activities, including economic development. We remain confident in the mid-2020 resolutions and that's all baked into our outlook for next year.

Great. Thank you, I appreciate all the detail. I just had one follow-up just on the financing plan in around some of the things being proposed in Washington. Several of your peers have talked about how meaningful direct pay could be in helping find future renewable investments and lowering equity needs. Assuming that Options included on from guessing, it doesn't impact the approved projects at all since you've done the funding for that. But just in the RSP, there's the $750 million you've outlined. And I think historically you've said something like 60% equity content for new generation investments. But we effectively expect that to be materially reduced with the direct pay option?

Yeah. Let me address the equity content first. So, we think for the future investments, to the $750 million potential investment that we've got, it -- we would not need the same level of equity content. Our Balance Sheet is going to be in much stronger position by the end of 2023. And so certainly be in more typical regulatory cap structure of 50-50. But having said that, direct pay does provide some flexibility and potentially reducing the need for external financing or reducing equity needs. So, we do see it as a positive, but we've got to get more detail to understand how that would impact rate basis and deferred taxes to see what the pure impact would be to our financing plan.

Okay. Great. Thank you, guys.

Thanks, David.

Your next question comes from Shar Pourreza from Guggenheim. Please go ahead.

Hey guys, it's James Moore here on for Shar. How are you doing?

Good morning, James.

Just curious with the IRP. If it's taking into account cost inflation for renewables when determining what the actual project costs will be, and if the submitting parties are going to be held to a fixed cost or if there's any allowance for cost inflation, and I have a second question on the gas side.

Thanks, James. I'll take that. The estimate that we shared derives from the RFP process, which was for actionable projects towards the mid part of this decade which align with the contemplated retirement of 16 AB and initiative city. We have asked for a period of time for us to evaluate those projects. When we go to the RFP marketplace, we ask for the opportunity to evaluate those for a period of time as you can imagine. We are still within that window, so we would be able to execute against those bids for those proposals still into 2022. And then continue through the refinement and due diligence process thereafter.

Once the winners have been decided, just wanted to clarify if there's any potential for pass-through for higher commodity costs, higher other input costs, anything that could delay on components, etc., or if it's just like a fixed price, regardless of who the winners end up being, curious if you -- So it's not decidedly et?

It's not decided yet, generally speaking, you'd think about it as a fixed cost that would then relate to that project, and that project is still executable through a window of time that it's been bid. That's really through 2024, 2025, maybe 2026, depending upon the project, and you'd have that fixed cost related to that project associated with that technology, to the extent that that bid is executed within this window that we're describing. And to the extent that you continue due to -- through the due diligence process, you might understand more or less about what it would take on the total investment side. Most notably, transmission to action those projects.

Got it. Thank you for the clarification there. The second questions on the LDCs. You've mentioned a number of times you're seeing an excess of 10% rate-base growth. First, how long should we think of that level of growth as being sustainable and now the follow up?

Yeah. I'll take the long view side of that question. If you look at the $40 billion of identified investments that we rolled out on Investor Day, just a little over a year ago, that’s really predominantly on the kinds of investments that are already in flight in the gas business in particular. Electric flow a little different with the transition from coal to renewables and clean energy. So those are typically long-dated programs. If you look at the underlying regulatory mechanisms like the T-Desk Gas Plan in NIPSCO, there's almost $1 billion of identified investment approved in the Gas TDSIC planned its multiyear beyond or 24 guidance horizons. Similarly, the Ohio IRP operates that way. In Virginia, the Gas Save program similarly. A lot of these are annualized programs with trackers that support them, that run beyond our current 2024 long-term guidance horizon. I'm not going to guide to a specific point in time where 10% rate-base growth is predictable. That's the kind of update we'll give on Analyst Day next year. But the core point here is the underlying fundamental investment thesis is very long dated across all of the LDCs.

Perfect that's those hoping you'd say and expecting their sort of leads into the second part of the question, given the recent attractive evaluation data points that we've been seeing for where the gas assets have been transacting. How do you think strategically about your 10% plus rate base growers versus long-term horizon station to win that other needs or other types of financing over your forecast horizon? Thank you.

Yes, I will take the front-end and ask Donald to touch on the financing side. So very much the same long-term strategic orientation. When we look at a portfolio of companies that have that kind of fundamental growth opportunity that we see as long dated and constructive jurisdictions that's well supported, any rotation would have to be accretive to a plan that reflects that kind of growth engine build and across really literally, each and every Company that we operate is -- has that same profile right now. So, it's a strategic question about long-term growth first and foremost, that said we're very open-minded, very analytical about that very objective, and work very closely with our board to continuously assess that opportunity. As it comes to capital rotation and alternative forms of financing, let me ask Donald to touch on that side of the question.

It's a good question and certainly one we've gotten in the past. We'll continue to evaluate all forms of financing to finance our growth programs and our growth plan. it is a strategic question and we certainly want to think about how we enhance that plan long-term, certainly as you think about that next level of generation investments, here we'll evaluate that as well to see what makes the best sense for us long-term.

Perfect. Thank you very much for the color and for taking my questions.

Thanks, James.

And there are no further question at this time, I will turn the call back over to the presenters for closing remarks.

Hey, thanks, Julien. Thank you all for your questions. Let me just close by reiterating a few of the key takeaways from our release today. We are targeting the top end of our guidance range for and we the investments needed to replace this capacity will be evaluated in the coming months with an expectation to roll out more clarity and precision on that at an Investor Day to be held in the latter part of the first half of next year. Our progress on the gas rate cases continues. We've got settlements on the table, or orders awaited in three states and filing of a new case in Indiana and along with the Ohio case that's pending. And finally, again, we do look forward to the steps between now and on Investor Day at the end of the first half of 2022. Key opportunity for us to extend this long-term growth trajectory. And we do appreciate you for joining us this morning. We know it's a busy day for all of you, so please stay safe and make it a good day. Thank you.

This concludes today's conference call and you may now disconnect.