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NorthWestern Corp
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Good day, and welcome to the NorthWestern Corporation's Year-End 2019 Financial Results Conference Call and Webcast.
At this time, I would like to turn the conference over to NorthWestern's Investor Relation Officer, Travis Meyer. Please go ahead, sir.
Thank you, Shelby. Good afternoon, and thank you for joining NorthWestern Corporation's financial results conference call and webcast for the year ending December 31, 2019. NorthWestern's results have been released, and the release is available on our website at northwesternenergy.com. We have also released our 10-K pre-market this morning.
Joining us on the call today are Bob Rowe, President and Chief Executive Officer; Brian Bird, Chief Financial Officer; and additionally we have other members of the management team in the room with us to address your questions.
Before I turn the call over for us to begin, please note that the Company's press release, this presentation, comments by presenters and responses to your question may contain forward-looking statements and non-GAAP financial information. As such, I will remind you of our safe harbor language. During the course of this presentation, there will be forward-looking statements within the meaning of the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995.
Forward-looking statements often address our expected future business and financial performance and often contain words such as expects, anticipates, intends, plans, believes, seeks or will. The information in this presentation is based upon our current expectations. Our actual future business and financial performance may differ materially and adversely from our expectations expressed in any forward-looking statements. We undertake no obligation to revise or publicly update our forward-looking statements or this presentation for any reason. Although our expectations and beliefs are based upon reasonable assumptions, actual results may differ materially. The factors that may affect our results are listed in certain of our press releases and disclosed in the Company's Form 10-K and 10-Q, along with other public filings with the SEC.
Today's presentation also contains non-GAAP financial measures. Please refer to the definitions and reconciliation of these measures that are included in our webcast materials.
Following our presentation, we'll open the phone lines to allow those dialed into the teleconference to ask questions. The archived replay of today's webcast will be available for one-year beginning at 6:00 p.m. Eastern Time today and can be found on our website under Our Company, Investor Relations, Presentations and Webcast link.
With that, I'll hand it over to our President and CEO, Bob Rowe.
Good afternoon, thank you for joining us and we are calling in from our Sioux Falls Office, where the temperatures have rocketed up over the last couple of hours, and it's now a positive two degrees Fahrenheit.
I'll start as always with some recent highlights. Net income for 2019 was $202.1 million, that's a $5.1 million or 2.6% increase, compared to last year. Diluted EPS was $3.98, a $0.06 or 1.5% increase, compared to last year. Non-GAAP adjusted EPS was $3.42 and that's a $0.03 or a 9% increase, compared to 2018. The Board declared a quarterly dividend of $0.60 per share, that's a 4.3% increase and that's payable March 31 to shareholders of record as of March 13.
Late last year, we issued a carbon reduction vision for our electric portfolio in Montana. We are targeting a 90% reduction in carbon intensity by 2045 starting from a 2010 baseline. In December, we also announced our transaction to acquire an incremental 25% or 185 megawatts of Colstrip Unit 4 from Puget Sound Energy for $1.
In February just this month, we filed a request for approval of the Colstrip acquisition with the Montana Commission. In December, the Montana Commission issued a final order approving our electric rate case settlement, and this month we've also issued an all-source competitive solicitation or request for proposals for up to 220 megawatts of peaking and flexible capacity to be available for commercial operation early in 2023.
And with that, I'll turn it over to our CFO, Brian Bird to walk through our financial results.
Thanks, Bob. Slide 4 shows our summary of financial results. The takeaway there as Bob talked about net income $202.1 million, a $5.1 million or 2.6% improvement on a year-over-year basis. I’ll get into details, but generally the 2.3% improvement in gross margin that increase was a higher increase than our operating expenses of about 1% resulting in operating income improvement about 4% that ultimately drove our good results on a year-over-year basis.
Turning to Slide 5. In terms of gross margin, gross margin of $939.9 million, a $20.8 million improvement or 2.3%. If you look into the major drivers there I would talk about two things that really from 2018, the Tax Cuts and Jobs Act impact benefit this year $22.1 million versus the 2018 amount. That's offset also with a better electric qualified facilities liability adjustment in 2018.
So kind of taking those two offsetting one another, what really drove the results to a great extent. We had good retail volumes on the gas side and electric retail volumes. We also saw some benefit from our rate increase, $4.4 million this year for a nine-month period, an improvement in our electric supply cost recovery.
Offsetting that to a degree, we did see some reduction in our electric transmission revenues during the year and also stepped out our natural gas production rates. That total change in gross margin on those items that impact net income was $20.2 million. In addition things that flow through trackers like property tax and production tax credits netted to a $0.6 million increase in gross margin again netting to a total of $20.8 million increase in gross margin.
Moving forward to weather on Page 6. Upper right, just to summarize, we did estimate overall favorable weather in 2019 resulted in a $7.3 million pre-tax benefit as compared to normal, and a $6 million benefit compared to 2018. The calendar months and the weather maps reach month were very, very telling. All of the favorable weather benefit for the year really came in the first quarter, really cold February and March helped drive the favorable results that really impacted the gas side of our business.
When you look at the second and third quarter, we didn't have much cooling load at all. A matter of fact, it's net unfavorable weather, if you will during that time period. And then the fourth quarter though October was cold, it certainly didn't do enough to offset a pretty mild December. And so, again, net-net, the first quarter drove our favorable weather results for the year.
Moving on to Page 7, in terms of operating expenses. Operating expenses as a total $663 million, up $10.1 million or 1.5%. So keeping operating expenses low. The two primary benefits there is property taxes appeared to level off, certainly level off in 2019. We hope to see that as a trend going forward, certainly no certainty of that, but certainly a good step in the right direction to see those leveling off, up $0.6 million or 0.4%.
Also, the depreciation and depletion, actually down $1.6 million or down approximately 1%. The reason there being obviously we've had increased depreciation as we continue to invest in our assets, but the $9 million improvement in depreciation rates as a result of the rate case settlement as the primary driver for the reduction on a net basis.
In terms of operating, general and administrative expenses, we've shared in the past that we did and opened the first strings a bit, if you will on our expenses. We did note throughout the year, we are going to be spending more on hazard trees and made really good progress on that during the year. We did through both our generation and our T&D business, increased maintenance expenses across the Board. Labor was up a bit during the year. And then additional legal technology and benefits are other primary increases in OG&A.
You may note that last quarter on a year-to-date basis, we did have a quite a big large other there were questions associated with that. We did in the fourth quarter break that out a bit more, so people could see that. That change there in those items impacting net income from an OG&A perspective, $17.3 million.
When you take a look at items that certainly are in the OG&A category, but are offset elsewhere in the P&L $7.8 million pension, some operating expenses recovered in trackers and then $2.3 million in non-employee directors deferred comp. Both the pension and deferred comp item you'll see in a moment offset in other income. Those changes were a decreased OG&A of $6.2 million for a net increase in OG&A of $11.1 million.
On the next Page 8. Operating income, $276.9 million, up $10.6 million or 4%. Below that interest expense, up primarily due to higher borrowings $3.1 million. Other income as I just spoke the main decrease is really netting the pension item and the deferred comp item I just spoke to in OG&A. But also that was also partly offset by $1.6 million, a higher capitalization of AFUDC.
The net there that from an income before tax of $182.2 million, $3.9 million increase or 2.2%, and then following that we did have a slightly higher income tax benefit on a year-over-year basis, I'll speak to that in a moment. To explain that difference giving to the net income I spoke earlier of $5.1 million improvement.
On Page 9, income tax itself, the two biggest drivers we had a release of an unrecognized tax benefit in 2019 of $22.8 million. That was offset by the impact of the Tax Cuts and Jobs Act excess deferred taxes in 2018 of $19.8 million, that $3 million difference is the primary difference, other things like the slight improvement in pre-tax income also drove the net result of an income tax benefit – incremental benefit of $1.2 million for the year.
Moving onto the balance sheet that much to really say here on Page 10, obviously, continue to see improvement in shareholders' equity, but ratio of debt to total capitalization continued to see a downward trend as we continue to shore up our credit metrics and always keyed in on our FFO to debt try and make sure we maintain our BBB flat unsecured credit ratings.
Moving onto the cash flow statement on Page 11. We did see a falloff in cash provided by operating activities of approximately $85 million on a year-over-year basis in the red box to the right. We really identify five things that drove that. We did have an under collection of supply cost during the year, not only to be a higher supply costs, but our method now to collecting those are on an annual basis versus a monthly basis, and as a result of the PCAM settlement that add some aspects to do with it as well, but that under supply we are now collecting in 2020. So we do expect to see a bit better cash flow, certainly on a year-over-year basis.
The Tax Cuts and Jobs Act, we had that settlement that we had in 2018. Actual refunds to customers didn't start occurring until into 2019, there is the $20.5 million there. And then the change year-over-year in terms of people providing deposits for generation interconnections was actually net refund $22.1 million for the year, those are the three biggest drivers of the $85.3 million.
Moving forward on to Page 12 from an adjusted non-GAAP earnings perspective, I think people who follow the company come to understand this page on the far – to the far left to the far right really is the GAAP numbers for 2019, and far right GAAP for 2018. And then we work toward a non-GAAP numbers for both 2019 and 2018, the middle and the rest you can compare those.
Starting from the far left, diluted EPS of $3.98 on a GAAP basis, we had two adjustments this year, we took out $0.11 of favorable weather and we backed out $0.45 associated with the unrecognized tax benefit getting us to $3.42.
On a comparison basis, last year's GAAP number in 2018 $392, we have three items that we backed out of that number $0.02 of favorable weather, $0.26 associated with QF liability adjustment, $0.25 associated with TCJA netting to a 339 – $3.39 non-GAAP EPS in the 2018, a $0.03 improvement or just under 1%.
Comparing the middle columns through the P&L, gross margin up about 3%, also operating expense is up about 3%. Even though property taxes and depreciation – actually depreciate slightly down, we did have a higher amount in OG&A and we planned to spend more, we talked about hazard trees. We talked about some other categories of incremental spend, we wanted to have in 2019 that – though considering that improvement in gross margin increase in operating expenses at 2.8% improvement in operating income and net ultimately in a 2.2% increase in net income on a non-GAAP basis.
Moving forward to Page 13. Diluted earnings per share over this time period, you see it from both a GAAP perspective and a non-GAAP perspective. On a non-GAAP basis, our EPS has grown on an average over 5% from 2013 to 2019. We will tell you that we do also show in 2020 column. Our guidance range of $3.45 to $3.60 per diluted share, we do note here really the three assumptions normal weather, we give you a consolidated income tax rate of 2% benefit to 3% tax increase based upon pre-tax income and then diluted shares outstanding of $50.9 million.
Lastly, regarding our 6% to 9% total return long-term. Look one thing I would mention here is we do see our capital spend now getting up in 2020. In 2021 to $400 million should be able to sustain that level on a going forward basis. I'd expect this to move toward the middle of that 6% to 9% total return – total shareholder return range again assuming reasonable recovery.
Moving forward, 2019 non-GAAP to 2020 EPS bridge to the right, I mentioned the $3.45 to $3.60 range. How do we get there? Starting at $3.40 to $3.42 share we show kind of some low and high points to get to that range.
What are some of the drivers on gross margin? Certainly, we expect the 1% plus of organic growth. We expect higher industrial and commercial loads. We expect some improvement in transmission revenues, and we expect to get a full-year benefit from the rate case. And then lastly, we had a wet year from an irrigation perspective in 2019. We expect to see some improvement in irrigation revenues in 2020. That should help on the gross margin side.
And OG&A expense decreases really across the Board. We're looking at the business trying to maintain cost control in 2020 after kind of – as I said, releasing some of the first strings in 2019, certainly tightening up here again in 2020, we've made great progress on hazard trees in 2019 expect to spend a little lees in that category in 2020. And that range of $0.11 to $0.14, those are the two big drivers for improvement between gross margin increase and OG&A decrease.
Thinking property tax, depreciation and interest expense for a growing company, we expect to see those, each increasing year-over-year. Other income with the South Dakota generation and increased capital spend, we'll speak to in a moment. We're expecting a bit more AFUDC on a year-over-year basis.
And lastly, we continue to focus on repairs tax deductions and expected incremental tax benefit associated with that. That nets us to $3.45 to $3.63 with – up to a range from zero to $0.03 of potential dilution from equity needs likely late 2020 to possibly early 2021. We see a net range of $3.45 to $3.60.
When you take in consideration, our mid-point of that at $3.53, when you look at the dividend we announced today and annualize that that's $2.40, if you compare that to $2.40 to the midpoint of the range or just provide a $3.53, that's about a 68% dividend payout.
Lastly on this page, I'll speak to taxes. Some good news and regarding that, we did expect to be going through our NOLs in 2020. Now that's 2021. And as a result of pushing that back a year with AMI [indiscernible] credits and PTC credits being available now into 2023 that used to be 2022 to reduce cash taxes. And lastly, we anticipate our effective tax rate to reach approximately 10% by 2023.
And with that I'll pass back to Bob.
Thanks, Brian. I'll start with a couple of words about our carbon statement in Montana. And as you know that's targeted 90% reduction in carbon intensity by 2045, as compared to a 2010 baseline – in the baseline is the result of effectively that's been Colstrip Unit 4 was able to be fully dedicated to serve our customers, the first resource that we had in Montana after going through deregulation and divestiture of the Montana power days.
As you know, we are already over 60% carbon-free on a delivered basis in Montana and that compares to 28% average nationwide. This is a Montana specific statement, although it's notable that in South Dakota, we are – I think about 32% carbon-free right now.
We’ve referred to this as really a no BS, kind of a carbon statements are not a lot of qualifications to it. It's driven by continued renewables coming on an actually very soon, we'll have more wind on our Montana system. Then we have hydro and we'll have more wind or hydro and then we have Colstrip even after we close on the additional acquisition at Colstrip.
Energy efficiency continues to be important. Thermal resources will be very important in meeting our customers’ demands in Montana dispatchable resources. But the frequency, the range of dispatch at this point to diminish as other resources come online toward the end of the decade. We expect there are thermal resources that will be retired.
So this is a glide path, it's also worth noting that this really is linked to the same modeling assumptions as in our resource plan and just like the resource plan, this will be updated on a regular basis and that will allow us to capture changes in economics, changes in technology, changes in public policy.
One of the things I'm particularly excited about that will help us achieve this vision is working with a group of communities that have their own sustainability goals, sustainability programs in Montana to help them craft and implement solutions that makes sense for them, while also recognizing our legal obligations to all of our customers that will be a great opportunity to work directly with our customers.
Turning then to the announced acquisition of 25% of Colstrip Unit 4. On December 9, we executed a purchase and sale agreement to acquire Puget Sound Energy's 25% ownership in Unit 4. It's 185 megawatts that would bring our total ownership at Colstrip to 407 megawatts or 55% of Unit 4.
And as I mentioned, even without additional acquisition, we will have both more hydro and more wind on our system. A brand that deep into his pockets and find a $1 to pay for the resource, very importantly Puget Sound will retain responsibility for its current pro rata ownership share for environmental of pension liabilities, as well as for ultimate closing costs.
In tandem, we will enter into a purchase power agreement, under which we will sell 90 megawatts back to Puget for five years indexed to the Mid Sea index, but with a floor of costs. And our proposal is to essentially put the profits from that PPA into a trust to pre-fund pretty meaningful down payment on an eventual closing costs for Unit 4.
We think that's far sighted and responsible recognizing that all assets do have useful lives. We filed for approval of the transaction in its various parts with the Montana Commission. They are being responsible in setting a schedule interventions are due in the first few days of March and we certainly don't see any reason why the transaction couldn't be reviewed and approved by the end of the year, which we think is an important and being able to implement the elements of the proposal and start achieving those benefits for our customers.
And as you know, we are uniquely exposed to prices in the Western power market, 46% reserve margin deficit at peak concerns about that, meaning deep requirements are now a primary focus in Western United States and even sharper focus in the Pacific Northwest and an acute focus in our Montana operation, again because in part of the legacy of supply new regulation. So I mean, this is very important in addressing about a quarter of our customers exposure to peak.
Turning on to the South Dakota and the Montana electric plants. First, South Dakota, it's been a straightforward and efficient process, we published our plan in the fall of 2018, really focused on modernizing our fleet to address reliability, flexibility and particularly to maintain our compliance with Southwest Power Pool requirements to be able to participate on behalf of our customers as effectively as possible in SPP. So we identified 90 megawatts of existing generation that should be retired and replaced over the next 10 years. I think we're running over a decade.
Then on April 15 2019, we issued a request for proposals for 60 megawatts of flexible capacity resources to begin serving our South Dakota customers by the end of 2021 is a very robust process, again administered by a third-party, lots of interest in the process, a good variety of submissions. As a result of the competitive process, we do expect to construct and own natural gas-fired reciprocating internal combustion engines or RICE units at a Brownfield site in Huron.
And then dependent on manufacturer selection, we anticipate between 55 megawatts and 60 megawatts of new capacity should be online by late 2021 at a total investment of about $80 million. And this election proposal is subject to execution of construction contracts and then obtaining the applicable environmental and construction permits. So that South Dakota, we're very excited to see that move forward.
Turning to the Montana plan. There the focus was on developing resources that will address the – really dramatically changing energy landscape in Montana and in the West to meet our customers' needs in a reliable and in affordable fashion.
As I referenced just a moment ago, we are severely exposed at peak, right now we're about 630 megawatts short of our peak needs, and that's in a market in which traditional resources are shuttering and original market that isn't where providers and planners are increasingly concerned about loss of loan probability in the not terribly distant future.
Right now we are at market on behalf of our customers and being at market at peak with a skinny set of resources is not a very good place to be for our customers. We forecast that our portfolio will be about 725 megawatts short in just five years, considering expiring contracts and then just very modest increase in customer demand. So this month, we've issued a competitive all-source RFP for up to 280 megawatts of flexible peaking capacity to be available for commercial operation in early 2023.
As the node indicates, the RFP is opened to all types of resources provided that they can meet our needs for peak and flexible capacity. There will be an independent evaluator to administer and then to evaluate proposals and the successful project or projects should be selected by the first quarter of next year, and then we expect to kind of wash, rinse and repeat and run a subsequent process in a future year.
Turning to some other matters, on the regulatory front, as you know, in December, the commission issued a final order, most importantly approving the electric rate case settlement in our Montana case effective April 1, 2019. And that would result in an annual increase to electric revenue of about $6.5 million based on a 9.65% ROE and the capital structure as we had proposed.
And then a $9.3 million decrease in depreciation expenses, several parties have filed petitions for reconsideration of various parts of the order, particularly a request for reconsideration by the Montana Consumer Council concerning the decoupling or infrastructure funding mechanism that had been proposed by Natural Resources Defense Council and that we're very strongly supported. We expect that the request for reconsideration will be acted on – in the first quarter.
Parallel, in May of last year, we submitted a filing to FERC for our Montana transmission assets. In June, FERC issued an order accepting the filing, granting interim rates effective July 1, of course subject to refund, and then establishing settlement procedures and terminating our related Tax Cuts and Jobs Act filing, settlement judge has been appointed and then settlement negotiations and conferences are active. We expect to submit a compliance filing with the Montana commission based upon eventual resolution of the FERC case with an adjustment and proposed credit back to our Montana retail rates.
We're continuing to invest in our transmission and distribution infrastructure, and this has been sometimes this work is not as visible, but is incredibly important fulfilling our responsibilities to our customers. That includes continuing work on a comprehensive staged approach to infrastructure addressing safety, capacity, reliability, really modernizing the system. We've been talking about that, our progress along those lines actually since I've been at NorthWestern.
On the natural gas side pipeline, investments or integrity verification, pipeline and hazardous materials on a lot of good work there. And then grid modernization continues to be our focus. We'd like to talk about deployment have the speed to value, learning what works and then making decisions that are sensible for our system and for our customers.
One of the neat things actually just over the last couple of weeks, we've been on a multi-year process to create a distribution operation control center and that started with geo coding elements in the field, acquiring spectrum, attaching communications to devices in the field that went live just in the last couple of weeks in the days after go-live, we had wins in Montana actually had top of loan peak at Big Sky that hit 155 miles now, we had several hundred outages, it was truly the most challenging shake down crews that the distribution operations center could have had, they are folks in customer care and then particularly our people in the field all this did an extraordinary job.
The functionality of the DOC is going to continue to improve – increase over the next several years as we continue to turn on more technology and make investments there, but a couple of minutes on that just because it's an example of how investments that we consider to be very important, but that can be invisible to our customers, ultimately really make a huge, huge difference.
As you know, we're planning to enter the Western Energy imbalance market in April of 2021 based on our experience in the Southwest Power Pool, out of South Dakota that will produce some real benefits for our Montana customers. We'll allow more efficient use of intermittent resources, greater power grid reliability, but then circling back to the Montana RFP, we have to have resources to be able to participate in that market.
As we've talked about before, we continue to monitor costs including labor benefits, property tax valuations. We consider ourselves, I think objectively to be one of the most efficient companies in our peer group and really and post up well on most measures against companies larger than us.
Last thing, I'll draw your attention to is our capital investment forecast and what you see here over a five-year period is $1.8 billion of total capital. We anticipate financing this with a combination of cash flows from operations aided by NOLs through 2021, first mortgage bonds, equity issuances, based on what we know now, any equity issuance would be late 2020, early 2021 and would be size to maintain and predict and protect our current credit ratings. The significant – potential significant capital investments that are not in these projections or negative regulatory actions could necessitate additional equity.
Just a couple of things to highlight based on the results of the South Dakota RFP. This does include $80 million of incremental investment for our South Dakota generation in 2020 and 2021, but does not include any investment identified it for generation capacity in Montana, and those depending on the results of an RFP could be in excess of $200 million over the next five years.
One thing, I would highlight as you've heard us say before, as we work through any five-year period, we identify more projects that are important to serve our customers. And indeed, if you just look at the period 2020 through 2023 in this bar graph they're about – actually $222 million of investment more than you would have seen last year, and that's a result of the additional $80 million in generation in South Dakota.
Also an important Montana electric transmission initiative, some additional funding in Montana AMI, gas transmission work in Montana, work at a billings substation, ongoing upgrades to the hydro system and then like so many other utilities, the investment in the SAP S4 HANA project. So the point being that as you work through the five years, again you identify the work that's most valuable and important to continuing to be able to serve our customers.
With that, we are open for questions.
[Operator Instructions] We'll take our first question from Mike Weinstein with Credit Suisse.
Hi Bob, Brian.
Hey, Mike.
Hey. Could you talk a little bit more about why the RFP, I guess final decision would be in the first quarter of 2021, what are the – what's the extra, I guess time required for that?
It's going to be a very thorough process or through the pre-qualification process there will probably be several stages of evaluation. So we believe in our supply folks, most importantly, believe that's a realistic and prudent schedule.
Yes. Our expectation is that by this call next year we'd be giving you an outcome.
Got you. And have there been any other changes to the process there? Or is it the same process, just seeing more time with it?
We are following the process outlined in legislation passed last year in Montana. So that does include several steps that otherwise we wouldn't have – and the legislation actually isn't in place. But for example there we filed the RFP with the commission before releasing it for submission. So that's one extra step that does come in mind under the statute that we'll be taking effect this year.
Right. And I mean is the delay coming from you guys you initiate – you're saying that you need more time, it's not that somebody else is saying they need more time like the legislature or the commission itself or?
No, I would not. I did use the word delay at all. This as a reasonable schedule to work through.
We might have been aggressive on the front-end in terms of fully understanding the time period, but working with the independent party revised our time period.
Okay, got it. Hey, I was wondering if you could maybe talk a little bit more about the energy imbalance market. I think, Bob, you mentioned that the additional assets are required to join that. And you're planning on joining in next year, is there any timeline that you have for additional assets that might need to be built? I mean what are we talking about here? Is it any significant investments that are required?
Those would be the assets that come out of the RFP.
Okay, so you need to see that before you can join?
No, we're actively going through the steps to join right now. It's a very significant undertaking to get in place all the systems, hardware, software, people to be able to participate in the market and that's a joint undertaking of our transmission department and our supply department.
Mike, I just add…
Yes.
Mike I just add, the capacity that we plan to build through 2025, certainly meets our needs from an EIM perspective. We or others, obviously through PPA, depending on the outcome of RFPs. But anything we don't have during the time that we're in EMI up until the end of 2025, we'll have to enter into contracts in order to achieve that.
Got it. Are there any transmission assets required that need to be built or any additional upgrades there?
Not specifically for this. I mentioned, we do have a couple of transmission project under way.
Right. All right. Thank you.
Thank you.
Thanks Mike.
We'll take our next question from Julien Dumoulin-Smith with Bank of America.
Hey, Team. How are you, Brian and Bob?
Julien, how are you?
Can you hear me?
Yes.
Good, pleasure. Absolutely, good to hear from you. So just following up on where Mike was taking a second ago. Timing of equity here, you specifically talked about this upside $200 million. You also put in the slides here 2020, 2021. Are you waiting to get some clarity about that process before kind of the deciding definitively on equity needs? And also when you talk about equity here, is that a definitive block equity or you think about like an ATM process or something like that?
I put two answers to your first question, Bob walk through the $222 million of incremental capital from the last time we talk from the slide. And when I talked about it on the last call, I was specifically talking to the $80 million, not the full $222 million and talked about having a need, the latter half of 2020 or into 2021 that's still the case. But again, we just need to size that debt according to needs from a rating agency perspective, again FFO to debt perspective. So that's really answering your first question.
Your second question, we've used ATMs in the past, like them, that's certainly a possibility, but we'll evaluate other options as well.
Right. So basically whatever comes out of this current process in Montana that would be incremental later on, as you say in the slides, so that's not going to dictate the timing whether 2020 or to early 2021, right, et cetera?
That's a fair point, Julien. I think, we'll need some equity prior to it outcome. I think in terms of certainly building out anything, if we're fortunate enough to be successful in Montana. That would be certainly beyond the end of 2020 early 2021 time period. So that might be – hopefully that's an incremental amount of equity we're raising at sometime in the future beyond it.
Got it, excellent. And then, Brian, did you say – you expect to move to the middle of the 6% to 9% TSR range? And then to the extent which I heard that right, can you clarify how you think about like a base year or anything like that? Sorry, I don't mean to read more into it than is necessary. But I also heard it, so I just want to make sure I heard it right here?
I appreciate you gave me an opportunity to clarify it again. The main thing here is in 2020 and 2021 we're now at about $400 million of capital investment. If we're able to sustain that type of increase if you will to $400 million every year, I think you'd see our EPS growth rate improve. Again assuming reasonable recovery and thus you'd see EPS plus a dividend yield moving us more to the center of that 6% to 9% range. Is that make sense?
Excellent. Absolutely. No, thank you. I appreciate it, that's important. Sorry quick last little detail here, maybe this is a Bob question. When you think about Colstrip and the various owners, how do you think about consolidating up further your ownership in that plants beyond what's contemplated today, broad-based?
Yes, through the RFP we are looking for flexible dispatchable capacity that would complement our other resources, including the PSC portion of Colstrip. So I think what we're looking for again is something that would – in terms of serving our retail customers, something that would be complementary with a big emphasis on flexibility, dispatchability, particularly on an intra-hour basis. And then beyond that we'll just see what's proposed in the RFP.
Okay. Is that differently, you don't have a need for base-load coal like Colstrip?
I'm comfortable with what we've acquired and beyond that we'll just see what comes in the RFP. But our focus is flexibility, dispatchability and risk management, I would add.
Absolutely. Thank you very much for the clarification.
Thank you.
We'll take our next question from Shar Pourreza with Guggenheim Partners.
Hey guys.
Shar, how are you doing?
Not good, not too bad. Can I just follow up on Julien's question, I guess, putting in a different way, if you are presented with a similar structure as you received with Puget. Would you take on additional interest in Colstrip especially as the partners kind of decarbonize?
What I would…
Can you hear me?
As we're focused on resources that are complementary to the resources we have now in terms of ability to be flexible, operate on an intra-hour basis and then manage to diversify our risk as well. And then if you can read into that, if you like.
Okay, got it. And then obviously you did – you've got the Colstrip deal, you issued the RFP for additional generation. Any sense on sort of the timing and the composition of the next RFP as you think about the duration of your peaking needs?
No. I think we'll work through this RFP, see what comes out the other end focus on implementing that, and based on conditions at that time, which will be obviously different in terms of size of the need, the economics, the technology, that's available. But given the exposure that our customers have right now, I don't think we can wait terribly long. The first thing is we get through this process, whenever the results are – get those resources engaged to serve our customers.
Got it. And then lastly, it's helpful is – you sort of highlighted the complaint around the FCRM pilot program. Is there any – just remind us if there is a statutory deadline, I know you expect a decision, but is there a statutory deadline for Montana, PSC to issue a decision on the petitions?
And then Brian, this is maybe a little bit for you. Even if you sort of get a scenario where there is a 25 basis point reduction in the earnings and the ROE. Is there sort of an earnings impact given the fact that you do under earn in Montana?
Yes. First of all, I think, just to clarify that we spoke about earlier. I think just the MCC is the only party that as far reconsideration associated with the FCRM and the 25 basis point everyone else – I shouldn't say everywhere else, but most parties it's certainly comment on that certainly support moving forward that without any impact on the ROE, and we hope that's where the commission will come down again in that regard. So I'm pretty confident we'll get there, but we'll see.
I think the other thing I'd say is, it would be an impact of course to our earnings and regardless if we're earning or under earning, I think it's going to have an impact, if in fact we're deemed in anyway, not an ROE perspective, and so I just leave it at that.
Got it.
The proposal, I thought was maybe the best decoupling our fixed cost proposal I've seen anywhere and was an extremely forward-looking step by the Montana commission. I think that testimony really eviscerated any kind of an argument for an ROE adjustment, but then beyond that said, if you really think this is something to look at that's something that can be evaluated as part of the subsequent study. So I certainly hope the commission sticks to its guns. And there were a number of very good responsive fleeting from other interveners opposing the request for reconsideration.
Got it. Thanks guys. That was helpful.
I think one thing too, in terms of the timing. I think we're going to need to get an outcome pretty soon on that, because we're supposed to implement that program by July 1, and so we hope to hear something relatively soon on that.
Just one more little footnote following on to implementation of the order. There was also good action by the commission approving, what we're referring to is our green pricing stipulation. So Bobbi Schroeppel, our Vice President for Customer Care and quite a good group of stakeholders are actively working on approaches to develop green products that our customers actually want to buy and we think that's very responsive to what we're hearing from both large and small customers and from some of our cities.
We'll take our next question from Jonathan Reeder with Wells Fargo.
Hey, good afternoon gentlemen. Just kind of following up on that comment there, Bob, in your prepared remarks, it kind of sounded like in the RFP based on some of the desire for kind of green products that we might expect some renewables to maybe clear this first RFP? I mean, is that kind of fair?
Very honestly, we don't know what will come out the other end, and what will ultimately be expected given the number of parties, who are bidding in. I expect we will see some real diversity in proposals. And as we think about our resource needs, we think about it really as a pyramid, and that's the base long duration, dispatchable resources, and then building up the pyramid dispatchable resource at a shorter duration. So that potentially creates an opportunity to acquire some diverse resources through the process, but the foundational need is going to really be long duration dispatchable resources.
Okay that's helpful. And then Brian, just to confirm the FFO to debt ratio that you guys still target that's 15%?
We target 15%, I think the clearing is really 14%. We'd like to have some cushion in our FFO to debt.
Okay. And then lastly, the higher T&D CapEx spend that's now in your budget. How does that impact the potential cadence of rate case filings, as well as any rate affordability concerns for your customers?
Great question, Jonathan. I think twofold, we will obviously as that spend and that was a $223 million that Bob talked about. That's spread across those four years. I would say this. It could move things accelerate things a little quicker. As said in the past that we expect to file bit more frequently certainly than we have in the past and we'll let you know that in April in terms of our timeline, if you will, at least for 2020, if there's any filings. I think the other thing too is we expect during this time period, particularly when we get into EIM, that's going to help reduce any bill headwind. In any time we think about our long-range plans. We're trying to increase the customers at less than inflation.
The one thing I'd add to that is, of the $222 million part of it is South Dakota, part of its Montana, part of its electric, part of its gas. So on any one business segment, the increased capital is just that much more modest.
Yes. No, I would like you guys to kind of spread it across the field pretty well so. Okay, thanks so much. That's all for me.
Thanks Jon.
We'll take our next question from Vedula Murti with Avon Capital.
Good afternoon.
Good afternoon.
Hi, Vedula.
In terms of the pending RFP here in Montana, do you have – is there a rate – in the past that it's been difficult for you to be able to come up with self-owned proposals that managed to be able to effectively compete or be able to cross to finish line with the Montana PSC and the independent evaluator. Yet in South Dakota, you were able with the Brownfield site to have a unique situation where it actually did work that way. In this current RFP, do you have any particular new opportunities or advantages that could produce perhaps a better outcome or the likelihood of a self-owned option more so than maybe it's been – then has been in the past?
Could you point me to the RFP you're referring to? I'm kind of a blank.
The ones in the past where you wanted to have your self-owned options and you haven't been able to get the PSC or whoever to validate having your self-owned options in Montana?
I truly can't think of an example. What I wonder, if you're referring to coming out of the 2015 plan, we undertook an RFP and we would drew it, because of noise at the commission really unrelated. If you recall, that was when commissioner at the time, came up with a reasonable idea that QF contracts ought to be limited to 15 years, but that under a notion of symmetry resources coming out of the RFP, whether owned by us or anybody else also ought to be limited to a 15-year period. So as a result of that separate action by the commission, we ultimately ended up withdrawing the RFP because we requested 20-year proposals. I wonder – could that be what you're thinking of?
Yes. Perhaps in this case, I guess maybe – just maybe ask a little differently then. Given your success in South Dakota, do you feel like in this new process or things that you have advantages in terms of what you will be able to propose, that may perhaps increase the probability of being successful at least in terms of part of solicitation. In addition, does the Colstrip acquisition per dollar actually perhaps influence at all the self-owned viewpoint, given you're not going to be able to fine-tune too much more capacity for dollar?
Certainly, I agree with that statement. I think we will participate in the RFP. Obviously, we think we are good at building and operating resources, and we think there are real customer benefits to having us do that. So we're going to participate, but the proposals from all parties will be evaluated on a neutral basis by a third-party, really through a blind process.
In terms of relationship to Colstrip either the relationship, I would see is that we did at least defer about a quarter of our customers exposure through that very cost effective transaction. We think that was the right thing to do for our customers. And also we think that was a pretty progressive move in terms of thinking about eventual closing costs and creating a situation where the ultimate decision about disposition of Unit 4 is going to be based either on the economics at that unit or on a public policy decision in Montana, and not somewhere on the coast. Beyond that I really don't see a relationship between Colstrip and the RFP. Brian, do you say anything else?
No, I think, we obviously, know the service territory that we operate in and have built resources and ask for pre-approval and received approval on resources we put into our portfolio in the past and we plan to compete. That's all I guess I'd add, Bob.
Okay. And I want to make sure I clarify one thing as Julien asked the question in terms of, when you're running and make sure I understand this probably the $400 million – if you were to sustain a $400 million capital expenditure level, when we're talking about the midpoint of the 6% to 9%, given that you're at a 3% yield, the inference is that the $400 million – at a $400 million CapEx run rate, but that would imply about a 4.5% earnings CAGR as part of that as your 6% to 9%. Is that fair?
That is the approximate math, if you use that 3% flat dividend yield, correct. And I think the reason for sharing that is historically we have said in the past, in light of the lower growth and investment in some of the outcomes we had been receiving, we expect it to be in the lower end of that 6% to 9% range that we're certainly pleased in terms of being able to invest capital, including the $80 million that we're investing in South Dakota, and Bob pointed out, projects that we – throughout our service territories, both electric and gas certainly to our customers benefit, but that higher level of investment allow us to move up within that range.
And also to clarify also the equity question, given the timing you laid out toward early 2021, which also lines up with the outcome of the RFP process in Montana. Is there any reason not to simply wait to find out what that outcome is in terms of figuring out whether it'd be an ATM program or maybe whatever the sizing is and that type of thing and with the agencies, do you feel like you have time to perpetuate that if you have an idea of what the outcome is?
Yes. I think – it's a fair question. I think, obviously, one of the benefits of an ATM program you could size that if in fact you – let's say, you weighted into the first quarter and you knew an outcome from that you could certainly size that and utilize that over time, it's certainly something to think about. We just wanted to make sure we gave people the impression of the timing that around an equity raise, and so something certain to think about, Vedula.
Okay. And just in terms, if we're running at a $400 million CapEx program. Given your cash flow profile in order to keep – maintain a balanced capital structure. Should we be thinking at that point in time that something in the $100 million to $200 million kind of area is what would be required to maintain the capital structure?
Vedula, I think people all run their various models and I think they probably have in their miles on FFO to debt calculation for us. That's what we're really trying to get you to do is from your perspective in a modeling perspective for you to size that equity. We're not going to provide you what we believe that is at this point in time.
All right. Thank you.
[Operator Instructions] We'll take our next question from Brian Russo with Sidoti.
Hi, good afternoon.
Hey, Brian.
Hey. Just on Slide 38, the rate base and authorized returns, just remind us your thought process here. You're currently earning on $3.4 billion of rate base, but your actual estimated rate base, if you kind of true it up outside the historical test years is $3.8 billion. Is that the way to look at? So that delta will – that was roughly $400 million will be need to – be recovered in future rate cases?
That's correct. The $3.8 million is a future rate case perspective. If it all happened on a particular date today, we would be earning on the $3.8 million, $7.3 million, currently earning on the $3.4 million today.
Okay, so – and the timing of these upcoming rate cases is to be determined and like you said, maybe after your first quarter call in April?
That's when we give you an indication, what we plan to do in 2020.
And in South Dakota for recovery of the peaker plant, are you going to pursue the general rate case route? Or file for a tracking mechanism?
Yes. We're going to pursue that the rate case, Brian, I think the timing of that will determine whether we can get a known and measurable adjustments. So the timing of that will also require us to have some conversation with the commission and regardless, while we're making an investment in that and we – I said, we don't have a rate case, we certainly would have AFUDC during that time period.
Okay. So would this be like a one-off rate case or would you seek recovery of the difference between $606.6 million and $557.3 million, which was authorized back in December of $15 million plus, the $80 million for the peaker? Is that...
I think, it would be all in. It would be all in. And potentially if it was primarily, as you can see from the schedule, you're looking at it's primarily on the electric side, where we have that need and obviously the generation units on the electric side. So if we have a rate case from a South Dakota electric perspective, we're not just going to do the $80 million of investment in the plants. It's going to be for all of our South Dakota electric business.
Got it. And then just to clarify, remind us the peaker plant in South Dakota being built in Huron, South Dakota. Is that at an existing generation facility? Or is it just that some sort of industrial site that has easier access to transmission?
That is our site.
It's your site. Okay. Got it.
Correct.
Thank you very much.
Thank you, Brian.
We have no more questions in the queue at this time.
Okay, great. Thank you all very much for your interest and support. We'll see quite a few of you over the next two months, and hopefully be visiting with all of you in April. Take care.
This concludes today's call. Thank you for your participation. You may now disconnect.