NorthWestern Energy Group Inc (NWE) 2017 Q4 法說會逐字稿

Good day, and welcome to the NorthWestern Corporation Fourth Quarter 2017 Financial Results Conference Call. Today's conference is being recorded.

At this time, I'd like to turn the conference over to your Investor Relations officer, Mr. Travis Meyer. Please go ahead, sir.

Thank you, Evan. Good afternoon, and thank you for joining NorthWestern Corporation's Financial Results Conference Call and Webcast for the full year ending December 31, 2017. NorthWestern's results have been released and our release is available on our website at northwesternenergy.com. We also released our 10-K premarket this morning.

On the call with us today are Bob Rowe, President and Chief Executive Officer; Brian Bird, Vice President and Chief Financial Officer; along with several other members of the management team in the room with us today also 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 questions may contain forward-looking statements. 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 contains 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.

Following our presentation, we will open up the phone lines to allow those dialed into the teleconference to ask questions. The archived replay of today's webcast will be available beginning at 6:00 p.m. Eastern today and can be found on our website, again that's northwesternenergy.com, under the Our Company, Investor Relations, Presentations and Webcasts link. To access the audio replay of the call, please dial (888) 203-1112 then access code 5682232.

I'll now hand the presentation over to our CEO, Bob Rowe.

Thank you. Good afternoon, everyone, and thank you for joining us. And we just completed a successful board meeting and are enjoying a crisp, clear wintry day in South Dakota.

First, recent significant activities. 2017 operating income increased $15.5 million as compared to 2016, due primarily to improved gross margin driven by favorable weather as well as customer growth. 2017 net income was down $1.5 million as compared to 2016, and that is due primarily to a $17 million tax benefit that was included in our 2016 results. GAAP diluted earnings per share was $3.34 in 2017 and that's compared to $3.39 in 2016, a 1.5% decline. Non-GAAP adjusted EPS was $3.30 in 2017, which remained flat with 2016. And Brian will cover off more on GAAP to non-GAAP comparisons and disclosures. The board declared a quarterly dividend of $0.55 per share, a 4.8% increase payable on March 30 to shareholders of record as of March 15. And on February 5, Fitch, on the one hand, affirmed NorthWestern debt ratings, but revised its outlook from stable to negative, writing that a series of unfavorable rulings by the Montana Public Service Commission have weighed on NorthWestern Energy's credit quality.

And with that, I'll turn it over to Brian to begin with the summary of the financial reports.

Thanks, Bob.

Net income for 2017 was $162.7 million, which was approximately $1.5 million or just under 1% less than 2016. As you see on Page 4, the primary driver for that decline was in the income tax expense line. We had over $21 million of incremental income taxes on a year-over-year basis. As a result, as you look at the income before taxes, we had a nice improvement, approximately $19.5 million improvement or 12.5% improvement on a year-over-year basis on a pretax standpoint. What drove that was a $39 million improvement in gross margin. Also we had favorable interest expense and other income that helped in that regard. And also another positive development, even though the -- there was an increase in operating, general and administrative expenses in 2017, we kept it a very reasonable increase of just over $2 million or 0.7% increase. Primary negative impacts for -- on a year-over-year basis, was property taxes up $14.5 million, or nearly 10%, and depreciation was up $6.8 million and a reasonable 4.3% to round out the results.

If I move forward to gross margin on Page 5. The full year gross margin was $895 million versus $856 million from the previous year, an improvement of $39 million or almost a 5% increase year-over-year. That have -- that benefit came from both our electric business, which was up $24.3 million, 3.6% increase; and natural gas, up $14.8 million or up 8.3%.

Of that $39.1 million, $30.9 million of that is a change in gross margin that actually impacts net income. And the 2 primary drivers were, as Bob pointed out earlier, we had an improvement in our -- both our electric and gas retail volumes from weather and customer growth. Those 2 things adding to over $26 million. Below the $30.9 million, we also had increased our gross margin result of items that flow through trackers, equating to $8.2 million, to get to the total of $39.1 million increase in consolidated gross margin.

Moving in to weather on Page 6. This is discussing really weather. The maps here are indicating weather versus normal. In the bottom, in the red box, we do point out that we estimated favorable weather in 2017 contributing approximately a $3.4 million pretax benefit as compared to normal, and actually an $18.6 million pretax benefit as compared to 2016. As you see the charts just above on heating degree days of the 2017 as compared with 2016, you can see significantly colder in all jurisdictions. And as a result there and then on the cooling degree days, significantly warmer '17 versus '16. All of that contributed to the $18.6 million improvement on a year-over-year basis. And also you can see versus normal or historic average, we were not as cold in Montana versus normal, and we're actually warmer in South Dakota and Nebraska from a heating degree basis. So that offset, to a great extent, the benefit in Montana. And we were less warm, if you will, versus normal from a cooling degree basis in Montana, all of that again to help offset some of the benefits or the $3.4 million pretax benefit again as compared to normal. This does show when you have some diversity from a jurisdictional standpoint, very positive results from Montana from a weather perspective, not very good from South Dakota this year, that hasn't always been the case. They do provide some diversity from a gross margin perspective.

If we move on to operating expenses on Page 7. Our total operating expenses were $633.8 million, a $23.5 million or nearly 4% increase in a year-over-year basis. As I mentioned, the operating, general and administrative expenses were only up $2.2 million. And as you look at the list of items that -- or that increase, one could argue the bad debt expense of $1.9 million was the largest expense. And that's primarily driven from higher loads on a year-over-year basis. The other items there primarily offset one another.

Regarding property taxes. Property taxes were up $14.5 million increase, primarily due to the increase obviously on plant additions, but also higher property valuations and higher mill rates that were assessed to us during 2017. And lastly, depreciation and depletion were up $6.8 million or 4.3% primarily due to plant additions.

And our operating to net income. Operating income, $261.4 million, up $15.6 million or 6.3%. Below that item, I did mention that we had favorable interest expense that was an improvement of $2.7 million. That is primarily driven by the $2.9 million of interest included in our 2016 results associated increase in the interest expense associated with an MPSC disallowance in 2016. We also had a $1.4 million improvement in other income that was primarily due to higher capitalization of AFUDC. Netting all those items out, income before taxes, $176.1 million, a healthy $19.6 million improvement or 12.5%. And lastly, obviously, the $21 million increase in income tax expense was primarily driven from -- in 2016 our adoption of the tax accounting change related to cost to -- actually, just repair generation assets. It was a $17 million impact as a whole. And of that $17 million impact or benefit in 2016, $12.5 million of that related to prior periods. And also we did have higher pretax income in 2017 versus '16. So those are the primary drivers there.

Speaking of income taxes on Page 9 in terms of the income tax reconciliation. You can see the moving parts in -- over to the far right, as the primary drivers in terms of dollars. The 2 primary drivers, of course, as I mentioned, higher pretax income that drove $6.8 million of the change. But the flow-through repairs deductions and primarily the result of the establishment of the generation repairs in 2016 and the $12.5 million related to prior periods is the primary reason for the $10.6 million decrease in flow-through benefits, if you will, in 2017. And those are, again, the primary drivers for the income tax reconciliation.

Moving forward to the balance sheet on Page 10. Total assets actually came down to $5.4 billion. And again that's primarily driven due to tax reform. And you can see that, really, the 2 line items on the balance sheet. In the assets side, regulatory and other noncurrent assets came down as a result of tax reform. And the offsetting entry was in other noncurrent liabilities also coming down in that regard. And finally from a balance sheet perspective, from a shareholder's equity perspective, up 7% due to the improvement in earnings but also due to the ATM issuance that took place in 2017. At the bottom of the page, ratio of debt to total cap, we did come down into our range of 50% to 55%, actually driven by the ATM program in keeping debt flat during the year.

Moving on to cash flow on Page 11. Cash flow provided by operating activities was up. That's primarily driven by the $38 million in refunds we provided in 2016. Obviously, not having those refunds in 2017 is the primary driver of the change in noncash adjustments to net income. We did keep investing relatively flat on a year-over-year basis. Those are the primary drivers from a cash flow perspective.

Bob mentioned that I would speak to non-GAAP on Page 12. I do that. At the very bottom there, we show on a kind of diluted EPS perspective. On the far left, we show moving from $3.34 after we back out favorable weather of $0.04, we get to $3.30. You may recall in 2016, we had quite a few moving parts. We had a GAAP number of $3.39, backing out unfavorable weather of $0.19. Also backing out tracker disallowance, $0.16. We also removed the LRAM reserve release of $0.18, and we also removed the prior year's repairs income tax benefit. After removing all of those items, we went from $3.39 to also down to $3.30. So again, on a year-over-year basis, flat. Important to point out, though, is as you look kind of the middle as we kind of reconcile these things from a non-GAAP basis and actually walk down through the P&L, reasonable improvement in gross margin of about 2.9%. OG&A, we talked about the slight increase there. The one thing I did want to spend a little bit more time on is property and other taxes, up $14.5 million or 9.8%. If you'd look at that $14.5 million, you might have noted in our bridge, '16 to '17, we were expecting to be a -- from a property tax perspective, about $0.09 at the midpoint of that range. If you look at $14.5 million on an after-tax basis, that's actually $0.18. So it was the property tax were a huge miss from that perspective. So if you assume on an expense side a $0.09 miss, you assume that you get some of that, of course, recovered in the tracker. So assume that's $0.04, so you have a net increase in net property taxes of $0.05. Throw on top of that, the disallowance of the $1.7 million that we had on property taxes for 2017 as a result of the recent ruling on the property tax tracker, that's $0.02, so for a total of $0.07. And people are wondering why we're at the low end of our guidance at $3.30 versus the midpoint, $3.375. You can see it right there, it's property taxes.

So moving down from our overall operating expenses. Fortunately, we were able again to manage OG&A to keep that increase reasonable at 3.9%. But obviously, we'd like to see that number lower. And I think for those who think that we don't necessarily care about property tax, you can see how it certainly impacts our earnings in a particular year. Operating income was up 0.7% because of the benefit primarily in other income. Pretax income was up $3 million at 1.8% and net income, up $0.8 million or 0.5%. When you take into consideration the dilution of the ATM program, that brings us down to 0 increase on a year-over-year basis. So that's the adjusted earnings of GAAP to non-GAAP on a full year basis.

Next page shows the same thing in the fourth quarter. The reason -- primary reason to show this is in the fourth quarter is we did indicate we would need somewhere in the $0.95 to $1.10 in the fourth quarter to meet our guidance. We did come in at $0.96. But the main thing again to point out in the middle of the page, you can see from an OG&A perspective, we did a nice job managing expenses there even above that gross margin, a healthy improvement in gross margin on a year-over-year basis, up 4.4%. But here is where you can see property taxes, up nearly 20% in the fourth quarter. Again, higher valuations, higher mill rates and also -- and this was obviously impacting margin, but the impact from the property tax tracker.

As I move forward to Page 14 talking about earnings guidance. You do show, obviously, 6 years of history here. We've been able to certainly provide results within our guidance. And obviously, disappointed to be at the low end of our guidance range this year. Also to point out over this 6-year period, we had non-GAAP adjusted EPS growth of 6.8%. When you assume a dividend yield of kind of 3% to 4%, you're looking at a 10% to 11% total return. And again, historically, we've certainly beat our historic 7% to 10% return over that time period. We know as we faced certainly regulatory headwinds here as of late, we've talked about being in the low end of that range. We've actually changed that target now, and we're now talking about being in the 6% to 9% total -- long-term total return to our investors through a combination of earnings growth and dividend yield. However, I should point out the negative outcomes in the upcoming regulatory proceedings may result in near-term returns below our 6% to 9% targeted return. And generation investment to reduce or eliminate our capacity shortfall could allow us to achieve the higher end of our range over the long term.

Speaking to guidance as I move really to Page 15. 2017 to 2018 EPS guidance and bridge. At the top of the page in our year-end results, $3.30. We did provide this guidance in the past. These things were slightly adjusted here for tax reform and other year-end numbers as they came in. But please note that the guidance range itself has stayed the same at $3.35 to $3.50. When you take that into consideration, also trying to keep our dividend competitive. We're looking at now paying a -- with a targeted payout ratio of 64% and a range of $2.15 to $2.25 we've come out with our dividend. You're going to see total targeted dividend for '18 of $2.20 for the year. Again, from primarily at the midpoint of that range.

Speaking to just a little bit to the ETM -- or ATM dilution, excuse me. Prior to the ATM dilution, at the bottom red box there, the earnings here would've been a 7% increase, continuing to provide value, of course, to shareholders. As a result, in order to protect our credit ratings and our need to continue to issue equity, we issued $54 million in 2017, and we expect to do the remaining $46 million in the 2018. After that ATM dilution, the improvement is only at -- just under a 4% increase. So again, trying to continue to provide that growth but, obviously, more difficult with the equity issuance that were necessary to take. And obviously, going from $2.10 to $2.20 from a dividend perspective is just under a 5% increase. Again, trying to provide growth in our dividend as well to provide value to shareholders.

Moving forward to 6 -- Page 16. Fortunately, we only have to do this every 30 years or so. We did have tax reform in 2017. Obviously, this will be to the benefit of our customers going forward. The first thing I'd point out, the red box at the bottom of this page is, tax reform had no impact on our net income in 2017. As a result of the reduction in the federal corporate tax rate, we reduced our deferred tax liability by approximately $320 million. This reduction was offset in regulatory assets and liabilities. For 2018 and beyond, for that matter, we have dockets initiated in both Montana and South Dakota to provide the income tax benefit to customers effective January 1 of 2018. As a result, immediately this year, we began deferring the recognition of revenue estimated to be $15 million to $20 million in 2018 on a consolidated basis into a regulatory liability account. The reduction in revenue recognized is anticipated to be offset by an equal reduction in income tax expense with no impact to net income.

As a result of tax reform, we are updating our effective tax rate assumption, including the 2018 guidance to 0% to 5%, previously 8% to 12%. And NOLs are now anticipated to be available into 2020, previously 2021. Though I would argue we are -- from a net income perspective, we're neutral. I would argue that tax reform has been cash flow negative. And we point out here in the slide that, again, equal to the $15 million to $20 million that we talked about impacting -- not impacting net income but the range of the result of tax reform, it will impact negatively our cash flow from operations and primarily as if you think about, we're actually deferring revenue that ultimately will be returned to customers in the form of refunds or dollars spent on projects to the benefit of customers. And finally, we firmly believe our debt coverage ratios, even though adjusted due to this tax reform, will maintain -- or continue to adequately -- be adequate to maintain existing credit ratings. However, I should point out further negative regulatory actions would likely lead to credit downgrades.

Moving to Page 17. Financing activities. We didn't talk about this the last time we chatted with you. $100 million ATM program initiated in September of 2017. The main thing to point out here is during the third and fourth quarters of 2017, we sold shares with the equivalent of approximately $54 million of proceeds. And as I mentioned earlier, we anticipate issuing the remaining $46 million by the end of 2018. On the long-term refinancing, we did refinance debt that was at approximately 6 -- well, 6.34% with debt at approximately 4% 30-year money with the benefit of approximately $5 million net of make-whole amortization from that transaction alone.

And with that, I'll pass it back over to Bob.

Thank you very much, Brian.

I'll start with the regulatory and legal update. But before I do that, just a couple of points following up on Brian's remarks. First is that this company really has, at all levels, tremendous people. And our -- they're people who are skilled in executing in whatever environment they're called upon to execute and continuing to invest in and grow the company. As Brian described, we had a couple of curveballs thrown at us, essentially in the last 6 weeks to 2 months with the Montana property tax mill rates coming in high most recently, the Montana Commission's decision changing methodology in the tracker -- tax tracker docket and then also, obviously, the changes in federal tax law. And starting from the executive management level all through the company, people have just done a tremendous job doing what they're called on to do and continuing to execute for our shareholders and for our customers. Secondly and related to the regulatory areas, some of you know that our very Senior Vice President for Regulation and Government Affairs, Pat Corcoran, retired in January after quite a remarkable career. And we used that as an opportunity to make some changes at the executive level. We have consolidated our operations with the remaining executive team. And for these purposes, most particularly, the regulatory responsibilities have been taken over by our General Counsel, Heather Grahame. We've added some resources, some new people to support the great veterans we have in our regulatory area. And they are across legal and regulatory, really, working as an extraordinary team with the full support of the rest of senior management and of the entire company. So we really like where we stand right now and just a lot of appreciation for the people doing the work.

The 3 things to pay attention to over the next year as of this moment, first of all, the federal tax law change implementation proceedings, Brian did a good job describing in both South Dakota and Montana. Secondly, the Montana PCCAM docket, the electric supply tracker. And then third, preparing to file a general electric rate case in Montana this fall. On Page 18, we give you an update on a number of these. First, the Montana property tax tracker filing. The Montana statute recognizes that the tax burden on regulated utilities is substantial and allows us to recover far from all but a significant portion of the change in taxes year-to-year. And that is trued up when we file a general rate cases that was in the gas case last year and will eventually be on the electric side. So at the end of January, the Montana Commission issued the property tax tracker filing and reduced, as Brian described, our recovery of Montana property taxes by a total of $3.5 million, and that affected both 2017 and 2018. But approximately $1.75 million of that impact was in 2017. And this was a result of changing the allocation methodology between federal jurisdictional and state jurisdictional customers. The method we had applied was the one that the commission had instructed us to apply when the property tax tracker was first implemented over a decade ago.

On February 8, we filed a motion for reconsideration with the commission. If you're interested in this subject, I certainly encourage you to take a look at that filing. One of the things that we demonstrated was that, in fact, over time, the method that the commission had previously ordered produced a benefit to customers. And we requested certainly in the first instance that the method the commission had previously employed continued to be appropriate. However, most importantly, we explained that the method should not be changed retroactively and laid out the legal analysis to support that. The commission, when it issued its order at the end of January, did correctly anticipate that there could be request for reconsideration. So they have, as part of that order, set a schedule for briefs on any request to reconsideration that might be filed, so there will be the rounds of briefs and deliberations. And we expect to see a decision by the end of March.

Next, the Tax Cuts and Job Act implementation. South Dakota and Montana are taking somewhat different approaches, but we did file our initial proposal with the South Dakota commission in January and anticipate an additional filing in March. And in Montana, we expect to make a comprehensive filing with the Montana Commission by the end of March. And both states, we've had good preliminary discussions with the commission and the staffs.

Next to the power cost and credit adjustment mechanism, or PCCAM, the history for those of you who don't know is that in April of last year, the Montana legislature passed House Bill 193. And that amended a statute that had provided for mandatory recovery of our prudently incurred electric supply costs. The revised statute, which was advocated for by the commission, gives the commission additional discretion. And the commission then initiated a process to develop a replacement mechanism. In July, we filed a proposed electric PCCAM that was very much in line with the commission's advocacy to the legislature in support of HB 193. Intervenor testimony was filed in November. And in December, the commission issued a Notice of Additional Issues stating that the range of options proposed by the parties was not sufficient and directed the parties to consider alternatives incorporating risk-sharing features. On February 7, we filed rebuttal testimony and also addressed the commission's additional issues. Intervenor additional issue testimony is due at the end of March and a hearing is now scheduled for the end of May. And the commission may apply its eventual decision to variable costs on a retroactive basis to July of last year, which was the effective date of HB 193. Again, I -- in this case as well, I would encourage you to take a look at our filing -- our person responsible for the administration of the supply tracker expenses on a day-to-day basis filed some very practical testimony. Crystal Lail did a fantastic job with testimony describing the specific Montana context, the history and implications of trackers for the company. Then John Quackenbush, a former state regulator with great financial experience, provided good testimony, providing larger context, including debt and equity concerns and the appropriate use of supply tracker and other tracker mechanisms that really is pervasive around the country.

Nextly, the ongoing saga of Dave Gates Generating Station. As you know, we did feel parts of the FERC order, which resulted in a partial disallowance of federal jurisdictional costs that went to oral argument before the DC Court of Appeals in December. And we're hopeful to see a decision there by the end of the second quarter. Final legal matter to update you on is the disallowance of replacement power costs at Colstrip Unit 4. And that has now been briefed for the courts. And the argument was that the decision by the commission was inconsistent with commission precedent arbitrary and capricious. And we expect a decision on this appeal one way or the other within the next 12 months.

Turning to the ongoing discussion of Montana's -- what we would view as a critical capacity shortfall. The chart on Page 19 that you've seen before compares the positive planning reserve margins with the negative planning reserve margin that we have in Montana. Actually, this is relevant to some of the issues raised by the commission in the PCCAM docket as well, in that we are quite constrained in our ability to participate in the regional market. The resource initiatives, the action items developed in the Montana 2015 plan did focus on the needs of our portfolio, including solutions to resolve our current negative planning reserve margin over the months. First, we talked with you about the strategies to, first of all, optimize the hydro system, continue to take advantage of its great benefits. Secondly, co-optimize the hydro system with our traditional thermal resources. And then thirdly, begin in a very responsible way to reduce the exposure of our customers to the need for dispatchable capacity resources. We had, in implementing the plan, issued an RFP, retained a third party to administer the RFP. So it is, in a sense, blind to us. Reluctantly, on February 7, we terminated that solicitation process. And that was a result of the Montana commission's extension of provisions in a qualifying facility order to utilities, which is -- as applied to utilities would essentially require that utilities be able to show benefit over a 15-year period or rather than, for example, over the lifetime. And in the RFP, we had looked at a 20-year window. And obviously, the difference between the 20-year window and the 15-year window, the commission had ordered require that we terminate the RFP. At the same time though, in addition to the other implementation activities under the 2015 plan, our supply team is well underway working on 2018 plan for Montana to be completed by the end of the year as well as a South Dakota plan. The commission had issued through unusual several series of comments on the Montana plan a number of questions or concerns. And we have tried -- we have made modifications to the planning process to include, for example, public hearings, use of a third-party facilitator and the like. But we -- the plan -- planning process is well underway again in both Montana and South Dakota.

Moving to the capital spending forecast. This is, in the aggregate, quite similar to the 5-year forecast that we've shared with you previously. What's different is that about $123 million of previously included capacity generation investments have been removed. And that is pending updating the Montana and South Dakota plans over the rest of this year. So that's the outie. The innie is incremental investment related to grid modernization and automated metering infrastructure, or AMI, for now for Montana as well as South Dakota and Nebraska. The Montana amount is right around $116 million. As we've discussed this before, the communications platform to support AMI was intended to be -- will be deployed over the entire service territory for all of our gas and electric customers and as we move ahead with planning a bit more visibility. It was a good decision to include Montana deployment as part of that. So the current estimated cumulative 5-year capital spending is now $1.596 billion. You could probably round that up, if you wanted to. And we do continue to anticipate funding these expenditures with the combination of cash flows aided by NOLs through 2020 and the remainder out of our current equity distribution program as well as long-term debt. And as we always highlight, if other opportunities arise that are not in these projections, for example, natural gas reserves, asset acquisitions or the like, additional equity funding may be necessary.

And I will close with just a couple of our brag pages. First, we had, and this is the most important thing, when we will be holding an employee call soon as we're through visiting on this call, had another great safety here and that is where we start every employee meeting as, I think, probably many or most utilities do. We continue to be a top performer nationally on safety. And that, I think, is closely related to the execution and excellence of our folks as well. We have the best ever J.D. Power scores in terms of overall customer satisfaction. We're very proud of that. That's ultimately why we're in business. We were, yet again, recognized as a finalist for Best Proxy Statement for Small to Mid-Cap company by Corporate Secretary magazine. And we've been a finalist a number of years and won the award in 2014. What I would highlight here is this is homebrew. This is a project that is done in-house, which is notable in itself. But I think that it also makes it that much better a reflection of corporate culture and corporate governance. We were also recognized for gender diversity on our Board of Directors for 2020 by the 2020 Women on Boards project. And 3 of our company's 8 independent directors are female. If you pay attention to our board, we've had with -- sadly, 2 deaths and 1 retirement. We've had some significant change in our Board of Directors just over the last several years. It -- just like the executive team, it is a tremendous board and good corporate governance really does begin with them.

And then finally on this page, we have published our second annual environmental stewardship report. I certainly do encourage you to take a look at that. Given the part of the country we're privileged to serve, that's something we are very proud of. You see a photo of the cover page over to the right, that's the Mystic Dam, up high in the Beartooth Mountains. It's a -- outstanding facility. It's a beautiful hike. If you want to come out, we'll take you up there. Get to ride a little train car for part of the trip. One of the neat things about this, this is a very, very old facility, relatively small facility. But, among other things, we're able to use this to meet the new FERC reliability-based control transmission regime. So an old facility that's been lovingly cared for and modernized and provides really cutting-edge services for our system and for our customers.

Looking forward, we talked about key items already. Regulatory treatment of tax reform in both South Dakota and Montana and certainly eventually, Nebraska, too, for that matter; continuing to work on the PCCAM Docket; and then filing an electric rate case in September. Lots of work underway to get ready for that case right now and many moving parts. A whole series of studies both with a parallel FERC case and for the Montana case. We do manage our costs, I would say, extremely effectively. And to Brian's earlier comment, that includes our property taxes assessments to the degree that we are able to do so. We had successfully, in Montana, negotiated significant decreases from the initial valuation. Hats off to our tax department for their work there as well as on the federal side. Most importantly, we continue to invest in our transmission and distribution infrastructure. The DSIP/TSIP plan that got us off to a great start was clearly a success. Now we're building on that as we think about the overall health of all parts of our infrastructure. An important part of that for us and for other local distribution companies is the PHMSA integrity verification process in the good new work that our gas transmission department in particular is doing there. And the -- it's a good grid modernization, specifically. We've taken a very thoughtful approach to both the basic underlying investments, acquiring the communications access and then layering on technology projects as those technologies became stable and provided value to our customers. And then I did highlight these by planning work ongoing in both Montana and South Dakota. Standards are somewhat different. We -- essentially used the same rigorous process in both states to meet the requirements in those states. I encourage you to take a look at the 2 plans there just by -- [by a] factor, they tend to be a little bit different. But both are very important documents that deal with the issues of concern to our customers and to us in those states.

And lastly, as we note on an annual basis, this is a very good market in which to be acquiring natural gas for both price, security and delivery security to our Montana customers. And to the degree that we are able to identify transactable opportunities, that is something we're very interested in doing.

So with that, Brian, is available to answer your questions.

(Operator Instructions) Our first question comes from Michael Weinstein from Credit Suisse.

It's interesting that, I guess, with the lower-generation CapEx in the current forward plan, you were able to make up for that with more grid modernization CapEx and -- which I assume is a -- kind of an acceleration of previous plans into the current 5 years. Just looking forward, if you lower the total return target 1% to 6% to 9%, does that mean -- I'm just wondering, what's the push and pull in that? Is it -- there used to be about $1.3 billion of potential generation CapEx over like almost a 10-year period. Assuming that -- this lowering of the targeted range by 1% accounts for that being significantly reduced, I'm presuming. What's -- yes?

I'm sorry Mike, I didn't mean to interrupt you there. I pretty much thought you were finished.

Oh, yes. Because I'm just -- what's the -- how much of that is offset by grid CapEx going forward?

Yes. I think as you think about kind of the midpoint of our guidance even for 2018, it means that we -- if we're able to achieve our plan, we should be able to perform in -- within that return profile. And the thought process is, and I did demonstrate earlier on the slide when we were able to grow our business with investment and generation, we were able to perform at a high range at the high end of our 7% to 10%. And I think I look at the 6% to 9% as the same point. If, in fact, we are able to reinvest in supply on a going-forward basis, and particularly to deal with our capacity shortfall, I expect that we'd be at the high end of our range. Until that becomes a reality, in some form or fashion, I expect that we're going to be in the low to midpoint of that range. And I would add -- I'd just add -- as we point out here, if we see continued regulatory headwinds, it's going to be difficult to even achieve in the near term the 6% or 9% range. Sorry, Bob.

And I would just add a bit of a friendly amendment to your question. In both electric supply and transmission distribution, we're really thinking about orderly, sensible investment plans. So as to AMI, for example, the question is what's the thoughtful sequence to proceed with our deployment strategies. And I think that's what's reflected in the plan. Obviously, a lot of work has been done by our asset management and automation folks over the months to get more clarity there. And the same thing is really true on the supply side. And what we had is just as the Montana Electric supply, specifically in the 5-year capital of coming out of the 2015 plan, was relatively small bet in terms of the overall identified need. And as we've discussed in response to regulatory concern in Montana, we have pulled those investments out of the plan. There's some risks associated with that very clearly. And then we'll see where we are coming out of the plan that we will file this year. Obviously, there'd been policy market developments as well that we will factor in into that plan. But the world that we're looking at still has some of the basic characteristics. And whatever comes out of the Montana and South Dakota plans, to the degree that it requires capital, that's going to be reflected in our future capital forecasts.

Right. Understood. The -- this next long-term procurement plan. How is that going to differ from the last one in terms -- how -- what conditions would you want to see before you reinitiate another RFP? I mean, am I correct in inferring that you need at least 20-year contracts to be approved? Or at least full -- at least 20 years of security behind rate base?

It's really early to say what we would be looking for at this point. What we look -- as part of the plan in South Dakota, we're going to be building on our experience integrating into the Southwest Power Pool and changing operations there. We're also looking at, no offense to our supply folks, the antiquity of some of our fleet and evaluating the efficient operation of those units. So that's a study going on that will be included in South Dakota. In Montana, we are again looking at the same kinds of challenges that we did in the 2015 plan. But as regional developments move forward and as we look at how we're going to interact with the larger region, that will be a factor. But I think it's fair to say that in responding to the region, you've got to bring something to the table in order to participate.

One last question for Brian, then I'll cede the floor. Could you explain how much of the property tax hit is an ongoing figure? Is it just that $1.7 million a year? Is the ongoing hit into 2019, 2020 and beyond unless you are successful in getting FERC recovery for that portion of the allocation?

Yes. I think what you need to do from the portion that's going to Montana -- think of the $1.7 million in '18 that -- '17 that will continue on a prospective basis and going-forward basis. But we also have to get recovery on a going-forward basis in FERC. And by the way, when we go in to -- for a rate case in Montana, we'll reset the base for property taxes as a whole and start over again. One other thing to probably point out on property taxes is that from a recovery standpoint, the amount that we're able to recover on a going-forward basis is going to 1 minus the tax rate. And so since the tax rate has come down, the ability to recover through the tracker should go up as well. So there are some moving parts there.

Our next question comes from Nick Campanella from Bank of America Merrill Lynch.

Before tax reform, you talked about upward pressure on the tax rate. Sorry if I missed it in your remarks. But do you still -- is that still going to happen with this new guidance on your tax rate now? Should we expect it to slightly increase through your forecast period?

Actually Nick, thanks for pointing that out. I didn't share that on a long-term basis. And so we focused on 2018 with our 0% to 5% for 2018. And on our long-range plan, in fairness, we do expect some upward trajectory there. But as a result of tax reform, that increase will be much less. And the range that we'd show over the next 4 years would be in that 3% to 8% range, if that's helpful to everyone.

Very helpful. And then just your comments on cash flow, given tax reform, how should we think about FFO to debt? If you can maybe tell us what you're targeting in '18?

Well, what we're targeting is -- we want to be -- we'd like to be certainly even higher than this. But we'd certainly want to be in the 15% to 16% range on a going-forward basis. And obviously, over time, we'd like to be a little bit higher. But we certainly need to be in that range, I think, from a maintaining our ratings. And again, that's only a portion of the ratings. The regulatory environment is another portion of the ratings. So I want to be very, very clear. Even if we can maintain those ratings, we have a difficult regulatory environment -- excuse me, maintain those types of FFO to debt numbers, other things could impact our ratings. I know you're aware of that.

I would add to that, that the metrics, including FFO to debt, are a significant part, driven by regulatory outcomes.

Fair enough, Bob. Good point.

Our next question comes from Chris Ellinghaus from Williams Capital.

Bob, you were talking about -- it's a little too early to talk about what your thought process is on the terms required for new supply resources. Is part of your thought process going to be -- I know it's pretty traditional for utilities to you use 30-year financing. Is that going to be part of your sort of calculus in determining what you think those terms need to be?

Yes. It really is too early to say. The driver is going to be -- in the planning side -- of plan that identifies what our customer's needs are then you look at what the options are that best meet those needs. Usually, you do that through an RFP. What -- it's not so much a financing question as it is a cost effectiveness and a recovery question. Typically, including in Montana, regulators have wanted long asset lives for owned resources to feather the cost impact to customers and to provide some generational equity for resources that are going to have the greatest value in the out years. So as we look at the 15-year period for -- to essentially show a benefit that's contrary to what typically regulators expect. And it's hard to imagine how you would do if you were to make a commitment to a resource and then essentially do a relook in 15 years over -- that customers will have then receiving the benefit of depreciation of the first 15 years, would you -- then if it turned out there was even greater value in the resources than what the market was doing, would customers be expected to pay back some kind of a dividend to the company. That doesn't make sense. So the 15-year notion is just so at odds with other parts of the regulatory method that we need clarity to understand how it would apply. And we can't realistically make resource decisions until that is addressed. And the specification with the RFP is we asked for resources on a 20-year basis. So right out of the gate, we're 5 years past what the commission has required. But again, most importantly, we are now well into the next planning cycle. So we will just see where that goes. And with the commission, we'll work over the rest of the year to try to get more clarity.

And I'll -- I'd add to that. I mean, your point, Chris, early on is fair. I mean, obviously, long-lived assets, historically, had been able -- allow us to track 30-year financing. And it will be difficult to look to those tenors if, in fact, the 15 years is -- as a debt investor, I would be concerned, of course, to lending beyond the risk period, if you will. So it's something we all have to factor that in as we develop our plan this year.

The mismatches is what's troubling us. And the -- to the degree that regulatory actions create risk that doesn't otherwise exist, that risk needs to be compensated. And what we're seeing, unfortunately, now is a series of actions -- to triggering concern both in -- on the equity and debt side that from the view of investors is creating risk that's not compensated.

Right. Along the same lines, Brian, you've included the supply request in the guidance range. Is there some -- obviously, you've got some concern about credit ratings. But should the supply docket result in a less favorable outcome -- it seems like you have some risks to your guidance and to credit ratings. Is the commission aware of those risks to the equity side and the credit side as far as what the outcome of that docket will be?

I'd like to think that they are. I know various sell-side reports have been shared with commission staff and commissioners. I know the recent Fitch rating and negative outlook in their full report was shared with the commission, commission staff. And so I believe there's an awareness, but I can't speak for the commissioners.

I'd add to that, I did mention John Quackenbush's testimony in the docket. It is first rate. It's professional. And he does attend to his testimony most of the relevant reports.

Okay. A couple of quick questions on the ATM. Do you expect to fulfill the 2018 portion throughout the year, early in the year? What -- can you give us some clarity on that?

Yes. I can't at this point in time, Chris. I'm not sure myself when we'll do that. I'd just -- we are committed to get it done by the end of the year.

Okay. Can you give us a little color on the weather year-to-date, so far?

Yes. I would tell you that we would have wished it was a little colder in January.

(inaudible) With the hydro system, we pay a lot of attention to moisture content and snowpack. And we're having a very good year. Interestingly, last year was a little bit light, but with the diversity in drainages, we were still pretty close to the overall targeted capacity factor for the system. And this year, things look great.

Yes. And February is a bit colder. So that's been helping too, so...

And on the economic development front, if you're a skier, come to Montana.

Our next question comes from Paul Ridzon from KeyBanc.

Bob, did I hear you say that maybe the market was improving for potential gas reserves?

From a customer perspective, I'd say the market is -- continues to be positive. I certainly wouldn't say it's improving though.

Brian, you said that in the next several years, tax rate should increase. But is that uplift smaller than it was before tax reform?

Yes. I think it is. I -- if you heard my 3% to 8%, I think we were looking somewhere -- something closer, as approaching 20% as we spoke about in the past. And obviously, as tax reforms put downward pressure on, you could argue that on a percentage basis going from 0% to 5% to 3% to 8% might be similar to a percentage basis. But other thing to keep in mind, a lot of these investments that we're making continue to get repairs deductions, things like meters get those types of deductions, too. And as we continue to focus on, we need to keep our taxes down in addition to the benefits of tax reform. And so that will help keep a downward pressure on those rates. And so again, ultimately, all of those benefits capture, they benefit the customers in rate cases. And obviously, for 2018, as a result of the tax reform, through the process that we're going through our dockets now.

And that 3% to 8% uplift is over what time period?

Over the next 4 years beyond. So over the 5-year time horizon, you can argue 0% to 8%, correct? If I'm 0% to 5%, if you're -- I'm still talking about for '18, but as I was saying over the next 4 years, past '18. Is that helpful?

Yes. And then just to clarify on your '17 to '18 earnings bridge, some big moving pieces there. But that's really just the impact of tax reform hitting the revenue line?

Yes. That's the biggest impact on gross margin. There are couple of other things that we've learned obviously since we've provided this last guidance. But tax reform is the biggest drivers of moving things here.

And when would you expect the discussion in Nebraska to take place about what to do about tax reform?

That's a good question. I think, as you know, it's a very, very small part of our business. I think what we'll likely be seeing is we need to do the math even what that impact would be to Nebraska customers, and think about that from a rate case perspective. And we'll continue to have a dialogue there as well.

But in the interim, you'll just kind of reserve for all 3 jurisdictions?

Correct. And I think that the thing to point out here, I just want to be very, very clear, that $15 million to $20 million is a consolidated number.

Our next question comes from Jonathan Reeder from Wells Fargo.

If the revised Montana and South Dakota IRPs again determined that new generation capacity is needed, what's kind of the earliest possible time frame we could see some CapEx materialize?

I would be very careful getting too far ahead of that question. We'll have the plans done by the end of the year. And then any actions, capital or otherwise, will flow out of that.

Maybe asking another way. I mean, do you expect like some of the $123 million of CapEx that you pulled out could come back into the forecast over this 5-year period?

I think in fairness, Jonathan, certainly, over that 5-year period in -- as you roll out anything we do from a generation perspective, I believe there would be dollars within that 5-year plan. But we have to wait to see what those plans, ultimate plans will show. And keeping this skiing analogy going, we certainly don't want to get ahead of our skis at this point in time.

Okay. That's fair enough. And then remind us, what's driving expectations for the lower OG&A in '18 versus '17? I think like half of it relates to the end of deferred DSIP expensing amortization?

You hit the major one right out of the blocks right there. Just for everyone's knowledge there, we were -- amortized the upfront costs for DSIP and that -- last year was the final year of that. So that's going away is a significant portion. We have scheduled maintenance that's scheduled over, let's say, 3-year period. We do not have any significant maintenance associated with that as well. You know we're making a significant amount of investment in technology. And we -- obviously, our plans to continue to show that. And all of the work we've done on DSIP continues to help reduce reactive expenses. But I'd -- lastly, I want to say, as an overall company, we're trying to manage headcount. We are trying to manage costs because it's difficult in this particular environment to continue to provide earnings growth. Ultimately, we're trying to do what we -- the best we can in terms of returns for our shareholders. And we also do understand that reduction in these costs ultimately fall to the benefit of customers. And we think that's important in the long run as well.

Okay. So the major one is just a lot of other kind of ways that you're trying to run the business more efficiently and realizing some of the benefits of those investment maybe in DSIP there.

Right.

Okay. And then Brian, will you need to issue long-term debt this year to kind of permanently finance the outstanding result -- revolver balance?

We typically have -- each year, we typically have some debt issuance in our plans. They've been mitigated to an extent by the ATM issuance but I'm not prepared to speak to exactly what our issuance would be. But I'd argue it's going to be less than we've done in prior years. If you consider the fact that our CapEx is relatively the same on year-over-year basis, and we're doing again some finishing up the ATM programs, it's going to -- you'll see a lower debt amounts than our -- what our -- than have been in our plans in the past. And again, that's going to continue to help put downward pressure in our debt to capital so help our coverage ratios on a going-forward basis.

Okay. I just thought the revolver is kind of carrying a higher balance where you may have to kind of clear that out some. Is that -- that's not the case here. (inaudible)

Any time that we issue long-term debt, there's ability to reduce obviously, your short-term debt at that time.

Okay. And then last, can you kind of briefly walk us through how, I guess, you plan to utilize all of the $420 million of federal NOLs by 2020, given just the 3% and 8% effective tax rate expectations?

Yes. I think obviously, you've got a lower tax rate, of course, that helps. But you also have no bonus, which certainly hurts. And so even though we've kind of pulled in that NOL benefit as a net result of all that, really 1 year from 2021 into 2020, we won't actually be a full cash tax payer until 2022 because we still have some AMT and PTCs that we have -- a benefit of for those 2 years as well. So significantly continue to stay focused on taxes in terms of trying to maintain a noncash stance.

It appears to be no other questions at this time.

Very well. Thank you for the good questions and discussion. We look forward to seeing many of you over the coming months and visiting with, hopefully, all of you in April. Take care.

This does conclude our conference for today. Thank you for your participation. You may disconnect.