Afternoon, and thank you for joining NorthWestern Corporation's financial results webcast for the Q1 of 2021. My name is Travis Meyer. I'm the Director of Corporate Finance and Investor Relations Officer for NorthWestern. Joining us today to walk you through the results are Bob Rowe, Chief Executive Officer; Brian Bird, President and Chief Operating Officer; and Crystal Lail, Vice President and Chief Financial Officer. We also have other members of the management team on the line with us to address questions as appropriate. All participant lines are currently muted. After the presentation, we have allowed time for a Q&A session. I will provide instructions for asking questions at that time. However, if you intend to ask a question and are joining us by computer, please set your Zoom identity to your first name, last name, and firm name so we can call on you by name to let you know when your line is open. Regarding the results, NorthWestern's results have been released, and this release is available on our website. We have released our 10-K, or excuse me, 10-Q pre-market this morning. Please note that the company's press release, this presentation, comments by presenters, and responses to your questions may contain forward-looking statements. As such, I'll direct you to the disclosures contained in our SEC filings and the safe harbor provisions included on the second slide of this presentation. Please also note this presentation includes non-GAAP financial measures. Please see the non-GAAP disclosures, definitions, and reconciliations also included in this presentation today. Webcast is being recorded. The archive replay of today's webcast will be available for one year, beginning at 6:00 P.M. Eastern Time today, and can be found at our website at northwesternenergy.com under Our Company, Investor Relations, Presentations and Webcast link. With that, I'll hand the presentation over to NorthWestern CEO, Bob Rowe. Travis, thank you very much. Just a couple of quick comments to start. First, happy Earth Day. If you haven't, I really do encourage you to take a look at our environmental stewardship report on our webpage. Today, the electric industry has made some good announcements about progress. Do be mindful that from a carbon perspective, our overall company portfolio, and particularly our Montana portfolio, is in just exceptionally good shape. Brian will come back and discuss ESG, and we'll also talk about steps we've taken to address our substantial and critical capacity shortage in Montana. Second, just very quickly, two tremendous board members, Board Chair Stephen Adik and Governance Committee Chair Julia Johnson, have stepped down after tremendous 16-year careers. They've led this company effectively on a remarkable journey. They've done a great job, too, of leaving behind a board of directors that is as effective, as engaged as possible. Third, this is Crystal Lail's Q1 fully at the helm. Crystal has spent her entire career preparing to take over as Chief Financial Officer, is doing a great job. Your old friend, Brian Bird, has jumped into a new role as President and Chief Operating Officer. He's doing a fantastic job, really helping to focus our entire operations part of the business on the future and really, again, pulling that whole part of the company together. Congratulations and thanks both to Crystal and to Brian. In terms of significant events, net income for the Q1 increased to $12.4 million. That as compared to the same period last year. Diluted EPS increased $0.24 or 24% as compared to last year. After adjusting for weather, non-GAAP adjusted EPS increased $0.20 or about 18.9% as compared to last year. The board of directors has declared a quarterly dividend of $0.62 payable on June 30th to shareholders of record as of June 15th. Bid submissions for the January 2020 request for proposals have been evaluated by an independent administrator. After reviewing the independent analysis, the following portfolio project was selected. First, the Laurel Generating Station. This would be a 175 MW natural gas-fired generating facility, a very efficient set of RICE units. Second, a five-year agreement with Powerex to purchase capacity for 100 MW. That is primarily a hydro-based contract. Third, we have signed, as of today, an agreement with esVolta for a 50 MW storage unit. It's a 20-year contract to be located in the Billings area. A little bit of reflection as we think about NorthWestern, we are a pure electric and gas utility. We are proud to be providers of critical infrastructure and essential service across an extraordinary part of the U.S. We're proud of our history as a 100-year operating history. Our bill is consistently below national averages. We produce the highest ever customer satisfaction scores, the best safety record, and one that, as you all know, is particularly important to me, continue to adopt best practices, approaches to corporate governance, and receive recognition for the strong earnings growth, stable and flexible, and investment-grade balance sheet. We, as you may know, increased our liquidity, doubled it last year, due to the uncertainty we were facing. Stable growth in our annual dividends, a very disciplined capital investment program, $450 million this year to start, really focused on investments to serve our customers and our part of the country. Stable and consistent customer growth we've seen, particularly on the residential side, across our service territory. This is where people really do want to be. Mentioned our supply portfolio and the accomplishments there, but again, the substantial exposure to a market where we really just do not want to be. With that, Crystal, I'll hand it off to you. Thank you, Bob. As Bob mentioned, my first earnings call as CFO at the helm, and it's not lost on me that it's nice to have my first call be after a solid quarter, and also to have important news on our capacity deficit and how we're going to address that. The thing I will say is as Brian is transitioning into his operating role, he seems to be gaining new religion on how to spend dollars. However, certain things will never go away, and I don't think you'll find him buying drinks at the bar and that his frugal ways will go away anytime soon. With that, on slide five, you'll see the P&L for the quarter, and again, a solid quarter from that perspective. On a net income basis, Bob mentioned $63.1 million for Q1 2021 compared to $50.7 million in Q1 2020. That's a $12.4 million improvement or 24.5% driven by improvement really at the margin line and some lower operating costs. On a GAAP basis, diluted earnings per share of $1.24 versus $1 in the Q1 of 2020. As we move into slide six to give you a bit more detail on the gross margin breakout, really the performance there was driven by colder weather in Q1 2021 as compared with Q1 2020. While that was still a bit warmer than normal, we have seen strong residential usage in the quarter. That's $6.9 million of electric natural gas retail volumes. We also saw an improvement in electric transmission. Those are partially offset by Montana electric supply costs being a little bit higher. Then you'll also recall in Q1 of 2020, we had some other non-recurring items that were detrimental in that period. Here in Q1 2021, the absence of those leads to an improvement. When you take out the items that don't fall to the bottom line, that's a $10 million improvement from a gross margin perspective and driving a lot of the performance for the quarter. As we move into slide seven, you get more of a perspective of what happened in Q1 here. January was really warmer across our service territory. February is where we saw the February cold snap and broadly more cold, and in March, warmer again. What that resulted in, again, is how I would break that apart is ultimately colder winter weather in Montana and Nebraska, slightly warmer in South Dakota, but again, colder than last year, which was quite warm and still not compared to normal. It's still warmer than normal. You'll see that in our non-GAAP adjustment here in a bit. Slide eight gets into our operating expenses. Really when you look at the operating general administrative expense line and you remove the things that don't fall to the bottom line, after adjusting those, it's a $3.6 million decrease at that line, and that's really driven by collecting some of the uncollectible accounts that were written off in prior year and ongoing cost controls. The thing that I would mention there is, as we look forward, we do expect to have an overall increase in operating expenses for the year. From a property tax perspective, you see that increase is $3 million quarter-over-quarter. Again, we collect a piece of that at the revenue line through a tracking mechanism. And then depreciation is also up $1.7 million based on our increase in plant additions compared to prior year. Slide nine, again, operating income of $80.9 million for the Q1 compared to $75.2 million in 2020, or a $5.7 million or 7.6% increase. We also saw a decrease in interest expense of $0.8 million or 3.3%. That was primarily due to lower interest on a revolving credit facility and higher capitalization of AFUDC, slightly offset by incrementally slightly higher borrowings. Our other income line, you see a big increase there. What I would remind you is there's some items in there that don't fall to the bottom line. You remove those, what that shows is an improvement of capitalization of AFUDC after removing those offsets, that's approximately $1.3 million net after those numbers. From an income tax perspective, last year, we had an income tax benefit. This year we're flat for the quarter, that's a $1.8 million decrease. You'll see as we move into slide 10, that's primarily driven by the increase in net income and improvement in that line. From a deductions perspective, we're right in line with where we would expect to be, and you'll see our typical flow-through and other deductions detailed on slide 10. Slide 11, moving into the balance sheet. The thing I would just draw your attention to there, and we've talked about this before, a little bit higher debt-to-cap ratio than we've run in the past. We are initiating an at-the-market ATM equity issuance program coming out of this quarter, and currently, obviously, we didn't issue equity in 2020 and expect to do that in 2021 to bring that debt-to-cap ratio of debt back down. Cash flows is on slide 12. You'll see at the operating cash flow line a significant decrease there of $92.5 million. A lot of that was due to the pricing of supply in Q1. That drove a significant piece of that decrease of $80.9 million. We also had some refunds associated with our FERC rate case to wholesale customers of $20.5 million. The thing I would think about there is we certainly expect to get quite a bit of that back by end of year. On a funds from operations or FFO basis, when you adjust out working capital, that's only an $8.6 million decline from the prior year Q1. Slide 13. Our standard non-GAAP adjustments here, the only adjustment we have for the quarter is the unfavorable weather. You'll see an add back of $1.3 million on a pre-tax basis. That compares to an add back last year, Q1. When I was speaking to the weather piece and saying unfavorable weather, so warmer than normal, but colder than prior year, you'll see that comparable add back last year was $4 million. From a GAAP basis of $1.24, adding back $0.02 to be $1.26 for Q1 2021. That's a $0.20 improvement over our non-GAAP adjusted earnings of $1.06 in the Q1 of 2020 last year. Moving to slide 14, we talked about our guidance for the year of being $3.40-$3.60. We understand that's a bit higher range and have mentioned that we expect to narrow that in the back half of the year. The quarter for us was in line with our expectations, and there's still a lot of the year to go. We continue to evaluate our credit metrics and certainly want to protect our ratings. We believe that we can manage the equity issuances that we plan in line with the dilution that we've indicated on the earnings guidance slide here on 14. Slide 15, just an ongoing reminder of where earnings per share and dividend history has been. Obviously, 2020 was a tough year for us from a COVID impacts perspective and also outcomes at the Commission. Even with that 2020 performance, we ended from a 2013- 2020 on a EPS growth of 4.3%. Remind you that the 2021 midpoint of our guidance puts us at a strong growth percentage for 2021 as well. From a dividend payout ratio, again, a little bit higher than we'd like to see, but a strong dividend growth moving into 2021. With that, Bob, I would turn it back to you. Thank you, Crystal. Great job. We did pull up this one slide. If you're looking at an older version of the deck, this was slide 20. We're maintaining our capital forecast, $2.1 billion over the next five years. We expect to finance this with a combination of cash from operations, first mortgage bonds, and equity. We do anticipate initiating a $200 million ATM in the Q2. Any equity issuances will be sized, of course, to maintain and protect our current credit ratings. As you probably all know, I'm extremely excited about this capital plan. This is investing across all aspects of the company, across all jurisdictions, and really doing the right thing for our customers. This does include about $100 million of incremental investment for South Dakota generation in 2021 through 2023. This does not include the results of the Montana request for proposals, which we have announced. All in, we expect this will result in an annualized rate base growth of 4%-5%. Very good. Then, as you saw, the Laurel plant will be right around $250 million for the plant proper. On the regulatory front, there's always questions about will we be filing a general rate case. We do not expect to make any general rate case filings in 2021. We do have a number of other extremely important filings either pending or anticipated. On the 15th, we filed a request to further delay implementation of a fixed cost recovery mechanism pilot in Montana for another year. This is because of the ongoing uncertainty and disparate impact on load from the COVID-19 pandemic. The mechanism really doesn't align terribly well with what we've seen in the business over the last year. Second, we've now filed a request in our Power Cost and Credit Adjustment Mechanism proceeding in Montana to increase the PCCAM by $17 million. That's a result of changed costs in multiple different elements, but particularly changing to more accurately reflect the cost of procuring peak capacity for our customers. In mid-May, we will be filing a request for approval for two of the three resources identified coming out of the RFP. We've now, as Crystal mentioned, have successfully concluded the FERC transmission rate case in parallel to the Montana proceeding and have refunded $20.5 million to wholesale customers. We've also submitted a compliance filing with the Montana Commission to adjust the FERC credits, and that has been approved on an interim basis. It's an awful lot of regulatory focus for this year. Next. February cold weather. This played out a little bit differently in each jurisdiction. One of the most important things was in each state, through really great work by our people, the systems held, and we were able to keep our customers safe, warm, and in service. In Nebraska, we've recorded a regulatory asset of about $26 million for natural gas. Considering customer impacts, we've proposed recovery of our costs there over a two-year period. We had just a wonderful meeting with the Nebraska Public Service Commission in recent weeks. Three of the five commissioners, along with staff, talked through operations. They were appreciative of the investments we've made in capacity in Nebraska recently, and will continue to make, talked through customer impacts, customer communication, did talk about the customer impact and the $26 million. We're hopeful to receive a decision from the commission. Again, we've proposed a two-year recovery period there, and we hope to receive a commission or in the coming weeks. In South Dakota, we have about a $17.8 million regulatory asset for natural gas supply costs. Similar in South Dakota, the commission has already issued an order authorizing a one-year recovery period. As in Nebraska, we had a great meeting with the entire commission and staff just a few weeks ago, talked about lessons learned both at the SPP level, Southwest Power Pool, and in terms of our local operations and communication. Very good result there. In Montana, things played out differently, equally, or in fact, even more positively. We did not see the substantial gas price increases in Montana. As you know, in Montana, we have a gas transmission system with gathering and storage at both ends of the system, north and south. It's particularly valuable that we have some on-system gas, and that we're able to draw gas from the north end of the system. Overall, on both the electric and the gas sides, the system's performed exceptionally well. There again, we had a great meeting with the Montana Commission, one of several that we've already had this year. We really appreciate their interest and support in how we managed through in February. Then as is true every year, we will be filing, in addition to the ECAM, natural gas, and other purchase power trackers, property tax trackers, that will lead to a pretty busy regulatory year next. Going to share two slides to really set up Brian. This is a look at what was happening in Montana during the February weather event from a Montana supply perspective. You see to the left, that's the capacity we have by categories. We've got an awful lot of wind on our system. The thermal resources include Colstrip, but also other natural gas and some QF coal that will be rolling off over the coming years, and then hydro. Fundamentally, the hydro system performed just as you would hope. Thermal resources performed, but our resources are substantially below the resource adequacy requirement, the target we really need to aim for, let alone below the actual load we were experiencing on the system. Then overlaid with that, you see what was happening to price. The lesson here is that as the Western power market becomes tighter and tighter, your customers are subjected to substantial price volatility that can pretty quickly eat up any savings from low market prices, and greatly increased availability risk. Let's now look at it from the transmission perspective. This is what was happening in our balancing authority. This includes our retail load, as well as other resources being brought into Montana over our system. You see 850 MW of net import during this period. Historically, Montana has been a net exporter, and we are seeing increasingly at times of high demand and low production from wind, that Montana overall is becoming increasingly a net importer. The challenges that we faced in February are of concern both for our retail customers, but also for others in Montana who may be responsible for their own supply, but have to bring that supply in over what is an increasingly constrained transmission system. That is one very important set of challenges that Brian and our operations leadership are addressing. As I hand it over to Brian, I said he's doing a great job. Crystal pointed out that despite his new role, Brian still does not pick up the tab for a round of drinks. Now, typically Brian decides when the check comes, it's a good idea to go out to the alley to check the electric service drop and inspect the gas meter. Brian, off to you. Thanks, Bob. I've been known to actually pick up a check now and then, but I'll take that. Fiscally prudent next provided. By the way, I appreciate Bob setting up. I think everybody in this call understands the capacity issue we've been speaking about for years, and particularly during 2020 and into 2021, as we kicked off our RFP in Montana in early 2020 and received bids midyear that year. We finally have come to the conclusion of that, and we're very pleased to announce a very strong portfolio that will provide great capacity to our customers, and effectively help us achieve end up halfway there, if you will, at least to get to 2025, 2026 time period of really putting capacity in place to help us with our capacity shortfall that we've been explaining to investors and other stakeholders for years. That portfolio, first and foremost, we're pleased to announce the Laurel Generating Station, construction of 175 MW of flexible reciprocating internal combustion engines. You've heard us speak to RICE units before. Those will be located near Laurel, Montana, and we will own those units, in fact, if we're able to get proper approval from the Montana Public Service Commission. The cost to construct this plant is expected to be approximately $250 million, and should be available for commercial operation in late 2023, early 2024. The second component of the portfolio is a Powerex transaction, a five-year Power Purchase Agreement for 100 MW capacity and energy projects, as Bob pointed out earlier, originally predominantly from hydroelectric resources. The third, Bob let the cat out of the bag a bit, we did sign contracts today, and we're pleased to announce we have signed a 20-year battery energy storage agreement with esVolta on a 50-MW facility to be located near Billings, and expected to be in operation on October 1st, 2023. We'd expect to request MPSC approval of the Laurel contract, the esVolta energy storage contract, expect to make that filing in May, with the decision anticipated about approximately nine months after filing. That's the great news out of Montana that I know many of you have been waiting on. The good news out of South Dakota is we continue the construction of the 60-MW RICE project in Huron, South Dakota, the Bob Glanzer Generating Station, that's to be online in late 2021, with a total construction cost of approximately $80 million. An additional 30-40 MW of flexible generation in Aberdeen, South Dakota, is in its planning stages and expected to be online in 2023, with an approximate cost of $60 million. Again, we're taking great steps in these two jurisdictions where we provide electric service to our customers to meet our capacity needs. Go to the next slide 22. From an ESG perspective, we point out here we've got a new landing page where you can find our ESG information. We work really hard, and I credit not just the IR group, who's done a nice job kind of spearheading this effort, but company-wide, a renewed focus on ESG. I think there always has been a focus on the G aspect, really almost for the 20 years that Sarbanes-Oxley's been in place. A very good focus on that, and I feel very strongly that this company will take the same pride we did in the G aspect and focus on the E and S. We have a great story to tell, and we just need to, over the next year, continue to do a good job of capturing and actually disclosing what we're doing from an E and S perspective. We've seen some trajectory already in doing that, grabbing, I'd argue, the lowest hanging fruit, if you will, from an ESG perspective, and we've seen improvements at MSCI. We're using one report tool from Nasdaq, and we're seeing some of the benefits of being part of Nasdaq, and that'll help us capture other ESG-related items that we will then feed on to the ESG-rating entities. We'll continue to make efforts company-wide, not only to provide good disclosure, but we believe ultimately be a leader from an ESG perspective in the space. With that, I'll kick it back to Bob. I'll pass it over to Travis. Thank you, Bob and Brian and Crystal. If you're joining us by computer today and would like to ask a question, please signal your intent by using the Raise Hand button that's typically found at the bottom of your screen. You can also simultaneously press Alt + Y on a PC or Option + Y on a Mac to raise your hand. Please ensure that your microphone is unmuted if you are in the queue to ask a question. If you're dialed in by phone, you can press star nine to raise your hand and star six to unmute your line to ask the question. Again, that's star nine to raise your hand and star six to unmute your line. We'll give it a few seconds to get our first questions in the queue. If you have not provided your name and your Zoom ID or are dialed in by phone, please be listening for us to announce your Zoom ID or last four digits of your telephone number to notify you that your line is open and ready for a question. Again, please be sure to make sure your line is unmuted on your end. Travis, if they're using the raise hand emoji, they should be sure to select the all five finger emoji, right? Thank you for the reminder, Bob. We'll take our first question from Brian Russo. Brian, your line should be open. Hi, good afternoon. Hey, Brian. Just any more details you can provide on the Laurel Generating Station? Is this a new site? Is it brownfield development or greenfield development? Is there kind of additional space for more units, maybe in the next RFP? Brian, I don't believe we had specifically disclosed the site. We haven't, Brian, but it is a greenfield site, and we'll disclose that here shortly. Matter of fact, many of the questions associated with Laurel and the esVolta will be covered, of course, in our filing that we're going to make in mid-May. Okay. Understood. Is there any discussion at the commission or the legislature regarding earnings or sort of intruded return on PPAs going forward? Yes, there has been discussion on both sides of the subject. Commissioners have spoken to it over a number of years favorably. It was a point of debate in the legislature, and a number of legislators spoke up against it. As you know, it's something that a number of electric companies are now requesting and receiving. I'm thinking particularly Michigan and Hawaii. Okay, great. Hypothetically speaking, assuming the Montana Commission pre-approves the filing, what are the scenarios of cost recovery and return on the investment? Could it be a one-off filing where it's added to base rates and reflect any customer rates? Would you need to file an actual general rate case to get that included once it's operational? Just remind me, what was the treatment for the hydro transaction and the pre-approval? Actually, before our last general rate case, we used to include a table which showed the authorized ROE by asset for assets that came in through the approval process. Typically, the approval filing is first, it's subject to an after-the-fact prudence review, just to be sure we did a good job with what we said we were going to do. It does include an authorized ROE, and typically that will be picked up from whatever the most recent authorized ROE is. Crystal, do you want to add some color to that? Sure. If you look at how our approval filings have worked in the past is what will happen there is, it's subject to the commission's approval. When that asset is placed into service, so think used and useful, it is added to customer rates at that time. It has its own cap structure and return calculated based off the revenue requirement for that asset, but it does allow for immediate rates in place upon used and useful. Then it's captured in the following rate case and layered into our broader rates. Certainly, it allows for an adjustment to regulatory lag there of not experiencing the lag between used and useful and when you do a next rate case. Okay, thanks. That's helpful. There wasn't much discussion on Colstrip. Can you just provide us an update there? I think you have a coal supply contract coming due in 2025, around the same time where some of the co-owners are looking to exit. Just curious if there's any update there that you can provide. Yeah. What I could say there is that our existing ownership at Colstrip continues to be extremely important to serve our customers. Absent that, the capacity gap would be just that much greater. You're right, we certainly have been talking to Westmoreland about terms of the coal contract, and we're focused on price, but also say a contract that is more accommodating to a resource that's being used for capacity. Okay. Thank you very much. Thank you, Brian. We'll take our next call from the line of Jonathan Reeder. Jonathan, your line should be open. You're on mute, Jonathan. We all need T-shirts with that slogan. You're on mute. Star six, Jonathan, if that helps. Can you hear me now? Now we can. There. Good work. Sorry about that. Sorry. Maybe I should have raised the middle finger for you, Bob, and got your attention that way. Ouch. Thanks for taking my question. Since we're just on Colstrip, might as well stay there. I saw Senate Bill 379, it's related to potentially acquiring more interest and had passed the Senate earlier this month. I saw it was tabled in the House committee yesterday. Does this mean efforts to potentially acquire more Colstrip interests are definitively dead? I kind of thought it was dead last year after the Puget deal fell through, then this kind of somewhat unexpectedly crept up. What I would say there, to be clear, our interest at Colstrip was always tied to our ability to serve our retail customers and not more. Certainly, as things stand as of 1:30 Mountain today, after 379 was tabled, we have no interest in owning an additional share at Colstrip. Okay, great. Appreciate you clearing that up. Could you expand upon your decision not to file a rate case this year in South Dakota? Was it to just be mindful of the customer bill impact given the recovery of the higher February gas costs? I think previously you indicated South Dakota was likely in 2021, in part to incorporate the new gas plant into rates. Following on that, do you expect to be able to get the new gas plant still into rates when it enters service through alternative standalone recovery filing? We'll have to wait until the 2022 rate case filing? Crystal, this is your first shot to answer the rate case question. Sure. I'll take the South Dakota rate case question. The one thing I would point out about 2020 is certainly, I think, Jonathan, where you went is there's a lot of sensitivity around the country to customer bill impacts and where you go from there. The other thing I would say is 2020 isn't the greatest test period for a lot of reasons. One is we certainly had cost control, in the South Dakota jurisdiction. The other thing I would say is South Dakota is quite flexible in the sense of we have a couple of options for how we can come in and seek recovery of the capacity investments we're making in the state. While we're not filing based off a 2020 test period, I'm certain that from a regulatory perspective and with minimal regulatory lag, we can bring those assets in when needed. Okay. I understand that. On the $17 million PCCAM request, is that just a standard annual update, that goes every year under the way the PCCAM mechanism and process works? Is this some sort of one-off request that you're trying to update the baseline, outside of a rate case? Crystal, you're on top of that as well. I can take that one. The PCCAM, we certainly can update that base. Just as a reminder of how that mechanism works, right, is you set a base and there's a couple of buckets of cost. Part of the buckets of cost you share above or below the baseline on a 90%/10% basis. We reset that for the last time in our last general rate case. You can file outside of a rate case to reset that base. That's what we're doing here. The thing that I would mention there is, I think as was seen in February and all across the country, capacity is more expensive. Having those types of contracts, we're certainly seeing that as assets shut down in the Pacific Northwest and particularly in Montana. Montana, think of it as a net exporting state. It's becoming more of an importing generation at peak times when needed. We're seeing those cost pressures on our PCCAM as to, as you all know, the amount of capacity that we have to go out into the market and purchase. With that, we're filing separately to reset that base and assist. What you'll see is certainly an under collection and cash flow lag in the amount that's currently in the base. Okay, great. That's very helpful. Last question, I think probably for you again, Crystal, just the miscellaneous beneficial drivers of growth margin on both the revenue and the expense side during this quarter. It's actually just, I think you said this, but it's just the absence of those miscellaneous headwinds during the same period last year. Is that right? Right. If you recall, Jonathan, last year, unfortunately, we had to talk about our other and Brian, as a very experienced CFO, covered it well. We had some items in last year that were non-recurring. They were detrimental in the prior period. The absence of those in this year provides a bit of lift. Great. Thank you so much. Appreciate you taking the questions and great job, Crystal. Thanks, Jonathan. We'll take our next call from the line of Shar Pourreza. Shar, your line should be open. Star six, Shar. Hey, guys. Can you hear me? Yes. Perfect. All right. Travis made this way too technological. Not at all. Just- I think you can handle it. Bob, don't worry about it. Brian usually makes me buy him drinks, too, so we're on the same page. Good. Just real quick around, just with the Montana generation, the $250 million in CapEx, can you just remind us if you can hit the high end of your growth rate on it? I think you guys seem to have alluded to that on the Q4 call. Then just maybe how you're thinking about financing the $250. Sure. Yep. Sorry, Bob, were you tossing that one to me? That's a totally CFO question. Absolutely. Sure. I think, Shar, you said two things. One, where would that put us from an earnings growth rate perspective? The thing that I would remind you, of course, would be the in-service date would be 1/1/24. That's the time you would see rates in place. That's a long-term growth rate on an average. The other thing I would say is certainly there'd be some AFUDC during construction there from that perspective. Of course, that's an important piece to achieving what we've said before is kind of pushing us to the higher, past the midpoint of that range is certainly our capacity piece and moving forward on those investments. I think I forgot the back half there for your question, Shar. It's just how to think about financing. Oh, financing. Yeah. Yeah. Certainly, as you've seen, we're spending $450 million in CapEx this year. We're launching an at-the-market equity program coming out of, or in Q2 this year. The thing I would think about are ongoing capital needs. We're certainly investing in our system at a high rate. From a Laurel perspective, subject to approval by the Montana Commission, we certainly would be looking to finance that probably in a normal 50/50 type structure. Okay. That's perfect. Congrats guys on the transitioning. Brian, best of luck. Thanks, Shar. Thanks, Shar. We'll take our next call. I do not have a name here, but it's from the line ending in 5990. Star six to unmute. Hi, guys. This is Sophie Carr with KeyBanc. Can you hear me? Sure can, Sophie. Yes. Great. Thank you for taking my question. A lot has been discussed already. Maybe if you could just talk a little bit about, following the results of this RFP in Montana, with the addition of these new resources, where does it leave you in terms of resource adequacy? How do you think about the cadence of additional IRPs and additional resources moving forward? Brian, let's get you back in the discussion. Yeah, Bob. Thanks. Sophie, I'd say this. We're not going to be explicit on exactly what the next RFP is going to be. We're continuing to evaluate as we move forward. I like to say from a rounding perspective, we're 50% there with this particular RFP. The timing is, as we stated in the 10-Q, late this year, early next year to release that second RFP with the hopes to have something in, as I said earlier in the call, in the 2025, potentially 2026 timetable. Then obviously even beyond that, Sophie, as certain contracts roll off over time and other things get addressed, our quest to capture capacity just doesn't end in 2025, 2026. We believe going certainly beyond that, in the 2028 and in the 2030 time period, we'll be looking for more capacity at that time as well. You're assuming that Colstrip will remain available to you throughout this decade. Would that be accurate to say, or is it still out of consideration in future IRPs? We certainly are assuming in the next RFP that we release that Colstrip's going to be considered during that time period. Got it. Thank you so much. That is all I had. Thanks, Sophie. Our next question comes from the line ending in 4404. Press star six, it'll unmute your line. Good afternoon, everyone. It's Brian Greenwald. Oh, hey, Brian. How are you? Appreciate it. Sorry, it didn't register my name there. That's okay. Not a problem. No problem. So in terms of the three- I would let you in anyway, Brian. I appreciate that. Congratulations to you and Crystal again on completing your Q1 here in the new roles. Thanks, Brian. In terms of the three to six and the new generation kind of getting you above the midpoint, is 2020 the right way to think about the base into the outer years here? Yes. 2020 is the base. Awesome. In terms of the decoupling and the efforts there to delay another year potentially further, just curious how you guys are framing the reason for that in terms of, seemingly relative to most of your peers, you guys are one of the more sensitive to load impacts. Just curious if you can elaborate on the efforts there. Sure, Brian. Go ahead, Crystal. Go ahead, Bob. No, after you. The thing, Brian, I would say is just from a decoupling perspective, this is something we agreed upon our last rate case, I think as you think about what happened in 2020, we saw certainly a fundamentally different load pattern as we were moving into that initial period. We had the pilot with the shadow accounting. What we've seen from that initial period is something quite different from how that was designed. Think about test period loads when the design was agreed to. As a reminder, that FCRM handles our residential class and a small slice of our commercial, but not all of our commercial and industrial. With that and what we've seen out of that first period, and where we're still seeing fundamentally a different load pattern than we would've seen, think pre-pandemic, we've suggested to the commission that they either continue it in pilot form or extend a pilot purely being with just shadow accounting or extend the implementation another year. Again, I would say it's because we're seeing different load patterns than what we saw in the test loads that is based on. Of course, as you think of any decoupling mechanism, those are typically comparing back to a load period. With that, what we've seen in the initial period of shadow accounting, we've requested the commission delay impact. Bob, would you add to that? That was perfect. Got you. In terms of legislative items, so with SB 379 getting tabled, and I know there was HB 99 looking to remove pre-approval earlier in the year, but anything else that's on your radar at this point? Yeah. We would say, again, other than 379, which had not been part of our original agenda, it was a busy but a good legislative session in Montana despite all the challenges with COVID. One other item that was certainly important was to eliminate the CREP program, the Community Renewable Energy Program. That was very problematic for us because it was almost impossible for a resource to thread the needle of being low cost and community-based. There are substantial penalties potentially associated with that as well. We worked very hard on compliance. It ultimately was unworkable, so we're pleased to see that requirement go away with retroactivity. That's a big positive. We will, quite separately from anything the legislature is doing, be moving ahead on a subscription green program, which we think is a much better approach to achieving a similar set of goals in terms of giving customers the opportunity to subscribe to a resource that they choose. Again, an overall good and busy session in Montana, Nebraska, and South Dakota. Very quiet, as is typically the case, and also positive. Great. I'll leave it there. Thank you all for the time. Thanks, Brian. Thanks, Brian. It looks like Brian Russo has raised his hand one more time. I don't know if Brian has another question or not. Brian? No, I'm all set. Thank you. Okay. Thanks, Brian. Let me add one other legislative outcome, which was eliminating what are essentially speculative carbon adders. The concern we have there is effectively our customers could have been put in a position where they have to pay a QF developer for a value that is not received. Just in terms of computing and avoided cost, non-quantifiable costs may not be added to the avoided cost. We think that's a good outcome for our customers and for us as well. Thank you, Bob. With that, we've exhausted our question queue. I'll hand it back to Bob for any closing remarks you might have. Just as always, we appreciate you being with us this quarter in this new format, and we are very eager to get to spend some time with you in person in the coming months. All right. Thanks again for joining us. This brings the webcast to a close. You may now disconnect.