NorthWestern Energy Group Inc (NWE) 2015 Q3 法說會逐字稿

Good day, and welcome to the NorthWestern Corporation third-quarter 2015 financial results conference call. Today's conference is being recorded. At this time I'd like to turn the conference over to Mr. Travis Meyer. Please go ahead, sir.

Thank you, Jennifer. Good afternoon and thank you for joining NorthWestern Corporation's financial results conference call and webcast for the quarter ended September 30, 2015. Northwestern's results have been released and the release is available on our website at www.NorthWesternEnergy.com. We also released our 10-Q pre-market this morning.

Presenting today are Bob Rowe, President and Chief Executive Officer and Brian Bird, our Vice President and Chief Financial Officer. We also have several other members of the Management team with us in the room today 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'll 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 may contain words such as expects, anticipates, intends, plans, believes, seeks or will. The information in this presentation is based upon our current expectations of the date hereof unless otherwise noted.

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 on 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 10-K and 10-Q, along with other public filings with the SEC.

Following the presentation today, those who are joining us by teleconference will be allowed to ask questions. The archived replay of today's webcast will be available beginning at 6:00 PM Eastern and can be found on our website at www.NorthWesternEnergy.com under the Our Company, Investor Relations, Presentations and Webcasts link.

To access the audio replay of the call, dial 888-389-5988 and access code 428-3628. Again, that's 888-389-5988, access code 428-3628. I'll now turn it over to President and CEO, Bob Rowe.

Good afternoon and thanks for joining us. Today we're at our division operations in Missoula, Montana. Missoula's the home of the University of Montana and is a thriving and really a very dynamic community.

I'll start with some of the highlights. We have net income of $23.8 million reported in the third quarter of this year, and that's compared with $30.2 million for the same quarter last year, and the decrease was primarily the result of a $16.9 million tax benefit recognized in the third quarter last year and that was partially offset by the income from the November 2014 hydro acquisition. We have diluted EPS of $0.51 as compared to $0.77 in the third quarter of last year.

Adjusted non-GAAP diluted EPS of $0.51 as compared to $0.38 in the third quarter of last year. We reached a settlement agreement in our South Dakota general electric rates filing with both the South Dakota PUC staff and with intervenors. If approved by the Commission, the settlement will provide an increase in base rates of $22.2 million (sic - see press release, "$20.2 million"); in addition to that, $9 million related to the acquisition of the 80-megawatt Beethoven wind project.

On September 25 we completed the Beethoven acquisition for approximately $143 million. As compared to the 20-year qualifying facility contracts that were previously in place for Beethoven, the acquisition and ownership by NorthWestern is projected to benefit our South Dakota customers by in excess of $44 million over the same period of time. The acquisition was financed with the issuance of $70 million of 25-year first mortgage bonds with a coupon of 4.26% that occurred in September of this year, and by $57 million of equity or 1.1 million shares in October of this year, and with the remainder funded with available cash and short-term borrowing.

We've narrowed our full-year 2015 adjusted guidance to a range of $3.10 to $3.25 per diluted share. Our previously announced guidance was $3.10 to $3.30 per share, and the Board of Directors approved a $0.48 per share dividend payable on December 31 of this year, and with that I'll turn it over to Brian Bird.

All right, thanks, Bob. Summary of financial results on page 5 for the third quarter. I'll focus on income before taxes; I'll get into individual components of the P&L shortly.

But income before taxes, as you see for the quarter we had $30.2 million which is an $18.4 million or 156% increase over the prior quarter. That was offset with, however, on the tax line, we had a significant tax benefit as Bob just discussed last year which resulted in a $24.8 million negative variance on the income tax line for the quarter, netting us to net income of $23.8 million or a $6.4 million reduction versus the prior year.

As you move forward to gross margin on page 6, the increase in gross margin, primarily on the electric side and primarily driven by two items. First and foremost the hydro operations, $40.4 million, and the South Dakota electric interim rate increase of $1.8 million.

There's several items, certainly below that, that effectively net out. I would point out that the electric retail volumes were up $1.1 million. We did see some benefit, slight benefit, from weather there but which was offset by some slight negative weather that impacted the gas, the natural gas retail volumes. Taking all things into consideration, we deemed that weather was immaterial for the quarter.

Moving forward to page 7 regarding weather to demonstrate that, as you take a look at the 2015 weather compared with 2014, we were slightly cooler in Montana regarding cooling degree days, but quite a bit warmer in South Dakota. Again, those two things primarily offset one another and certainly on a cooling degree day versus our historic average is how we look at and as we forecast our earnings on a going-forward basis we look at versus historic averages, you can see there's very little difference in the quarter versus the historic average from the cooling degree day.

Regarding heating degree days, the third quarter is quite a bit a shoulder quarter for us. It was quite a bit warmer but again, since there's not a lot of heating load there, it was a very little impact in the quarter associated with heating degree days.

Moving forward to operating expenses on page 8. Operating expenses, let's start with OG&A. It was up 16.4% or $11.2 million. $10.8 million of that increase is associated with our hydro operations.

Each of the items below that $3.5 million increase was associated with a non-employee directors deferred compensation. For those of you who cover us closely, you know that that's offset in the other income line. Below that, both hydro transaction costs was a favorable variance this year since we didn't incur any of those costs this year, and bad debt expense, certainly we've had an improvement in terms of our CIS system this year and thus an improvement in our bad debt expense as well.

The last title there of $2 million other, which is a favorable variance in this case, is really associated with the cost control that we've put in place during the quarter so actually on a netted basis we're actually down all other costs if you [look in the quarter], and again, trying to manage some impacts on our margin by managing our costs closely for the quarter and we were successful there. Regarding property taxes and depreciation, those are up 28.4% from 17% respectively. The increases there are primarily driven from the hydro transaction in each of those categories.

Moving forward to operating net income on page 9. The top of the page, you can see operating income is up $17.5 million or 56.5%. Below that, interest expense is up $3.2 million, again, primarily driven by the hydro transaction and the debt associated with that transaction.

Other income is actually up $4.2 million, primarily driven by the $3.5 million increase in the deferred comp that I discussed earlier, and netting to us again the income before taxes of the $18.4 million improvement. And again, below that on the income tax line, the $24.8 million detriment, if you will, on an unfavorable variance on a year-over-year basis netting a $6.4 million unfavorable variance for the quarter.

If we move forward to page 10, thinking about EPS GAAP to non-GAAP numbers, as Bob pointed out earlier on the call, for the third quarter, you can see that we started with a $0.51 GAAP number. There were no adjustments for weather or any other adjustments for the quarter so our adjusted diluted EPS was $0.51. That compared on a comparable basis to $0.38 on a quarter-over-quarter basis, and on a year-to-date standpoint we're at $2.17 year to date this year versus $1.78 through three quarters last year.

So regarding the fourth quarter of this year, in order to hit our new guidance of $3.10 to $3.25, we will need between $0.93 and $1.08 for the fourth quarter of 2015. That compares to $0.89 in the fourth quarter of 2014.

Moving forward to slide 11, adjusted earnings for the third quarter. We did discuss at the very bottom of that page the diluted EPS of $0.51 versus $0.38, a 34% improvement. The beauty of this slide, though it does show how that compares to this throughout the P&L, from a gross margin perspective a 27% improvement, operating income nearly a 70% improvement, pre-tax income on an adjusted basis 111%, and net income 60% so good year-over-year performance for the third quarter.

Moving to slide 12, we're looking at this now, a year-to-date basis similar [a]comparison of $2.17 to $1.78, 22% increase. You'll see similar improvements across the board from a gross margin, operating income, pre-tax and net income up 48% on a year-over-year basis year to date, so again, very good performance.

On page 13, talking about diluted earnings per share guidance, as folks again who cover us closely, we typically do tighten our guidance after our third-quarter results. In this case we did slightly tighten down to $3.10 to $3.25. The three primary areas where we made that adjustment were issues associated with property taxes; in the third quarter we typically get a good idea where property taxes are going to land, those came in higher than we expected, income taxes as a result of the return to accrual adjustment in the third quarter, and slightly lower repairs tax deductions than anticipated for the year, income taxes are going to come in slightly higher.

And you might note that we did tighten up our consolidated effective income tax rate of 17% to 19% versus the previous 15% to 19%, and the last reason we tightened is there's been some outcomes from the LRAM decision and the gas tracker in front of the Montana Public Service Commission. As a result, our expectations from earnings have been impacted somewhat. Those three items have been offset to a degree by cost control and thus we netted at the $3.10 to $3.25, and from our perspective we just felt it would be difficult to get at the high end of our original $0.20 guidance.

Another thing I'd point out, the only other thing we did adjust here is we are using a new diluted average shares outstanding of 47.6 million versus the previous 47.3 million. Again, even with this adjusted guidance, we will continue to demonstrate a 7% to 10% total return to our investors in 2015.

On page 14, in terms of the balance sheet, total assets through 2015 today are now over $5 billion. The big increase for the last nine months was over $300 million -- approximately a $300 million increase in PP&E. That is driven to a great part in terms of our investment in Beethoven, but obviously other investments we're making throughout the business. Also a nice improvement in shareholder's equity up approximately $40 million through the first nine months of the year.

Lastly ratio of debt-to-capital 56.5%. We like to be around 55%. We expect to be closer to 55% at the end of 2015.

On slide 15 is cash flow. Our cash flow from operations are up approximately $100 million, really driven by two things, obviously the improvement in net income but also improvement in working capital, that's primarily driven by improvements in collections on a year-over-year basis.

Another significant difference, if you will, on a year-over-year basis is in the PP&E additions I just discussed. Again, the primary difference between the two years is the investment we made in Beethoven in the third quarter of 2015. And with that I'll turn it back over to Bob.

Thank you, Brian. I'll start with a bit more detail update on the South Dakota general rate case. As you know, we filed our first electric rate case in South Dakota in 34 years and our initial request was $26.5 million increase driven really overwhelmingly by our investments, particularly at Big Stone and Neal as well as the Aberdeen peaker and the Yankton substation.

Went through, overall, a very constructive process of negotiating with the South Dakota Commission staff and ultimately with other intervenors and we did reach a broad settlement allowing an increase in base rates of about $20.2 million at an overall rate of return of 7.24%, and in addition to that, we would bring the Beethoven project into rate base for an additional $9 million annually. The PUC has scheduled a hearing, it's actually next week, October 29, and we hope that they will be able to make the final decision in the case by the end of the year. We have been collecting interim rates since July 1; that was based on our original filing, and we're recognizing revenue consistent with the settlement and will refund any amounts determined to be overcollected by March 31 of next year.

A little more detail on the Beethoven wind acquisition. In September we did complete the purchase of the 80-megawatt Beethoven wind project near Tripp in South Dakota for about $143 million subject to the usual post-closing adjustments.

Prior to the acquisition, the energy and the renewable energy credits, or RECs, associated with this 80-megawatt project were included in our electric supply portfolio under a Qualifying Facility, or QF, power purchase agreement. And the QF PPA terminated upon closing and we have requested the project be placed into a rate base as part of our pending general electric case, and again stipulation does speak to that. Financing, once again, included $70 million in South Dakota first mortgage bonds issued in September of this year at a fixed rate of 4.26% maturing in 2040, and about $57 million of equity that was completed in October of 2015 with 1.1 million shares at $51.81 per share, and the remaining amount again was funded with available cash and short-term borrowing, and we do look forward to a decision from the Commission before the end of the year.

A bit of an update on the Montana hydroelectric system, and this was obviously a very dry year throughout the West as drought conditions persisted in a relatively warm year, but despite that, the generation output from the hydro systems came in really right at capacity for the five-year average. I mentioned before in previous quarters that our supply division has been quite busy working on several projects that will feed into the Montana asset optimization study and that involves looking at various scenarios in an attempt to integrate and operate this great diverse set of assets, the dams and other Montana facilities to operate them as efficiently as possible to meet the needs of our customers.

And probably many of you saw the recent news that Talen Energy, of course formerly part of PPL, announced the sale of 292 megawatts of hydro generation for $860 million, and that was purchased by Brookfield Renewables. And that's comparing to the 439 megawatts of hydro generation net of Kerr to be purchased for $870 million, so you could look at it either as we got 147 million megawatts for $10 million, or you could look at it with Brookfield paying a price of just a little bit under $3,000 per kilowatt and we paid a little bit under $2,000 per kilowatt so again we think the market experience in that case really affirms that this was an outstanding transaction for our customers.

Turning then to what our supply portfolio looks like now, it's really a kind of a remarkable and certainly a transformational place. With the Beethoven acquisition by name plate capacity in South Dakota, we are now 25% renewable and that's including Beethoven plus contracted renewables. In Montana by name plate, we are 67% renewable, and by actual delivered power, we are almost 60% either water or wind in Montana cause it's basically a hydro-based system in Montana and Company-wide, we are 54% renewable so that's again really a transformation in the power delivery to our customers, particularly our Montana customers.

A couple of other brief highlights, Dave Gates Generating Station, as you know, FERC issued its December in April of 2014, in May of 2014 we requested a rehearing consistent with the FERC decision. We've deferred $27.3 million of revenue, that's through September 30 of this year.

We have not heard on a rehearing; I know everyone is wondering the status of that and we do have the option of appealing to the Circuit Court of Appeals depending on what we ultimately do hear on rehearing. We don't believe an impairment loss is probable at this time, but obviously, we continue to evaluate as facts and circumstances change.

Big Stone Air Quality project, the coal plant at Big Stone is subject to BART requirements for regional haze, that's a best available retrofit technology. We've been required to install and operate new systems to reduce SO2 and NOx, our 23.4% portion of the project cost is between $95 million and $105 million capitalized $95.1 million through the end of September, and that project is expected to go into service in December of this year or into January.

Our distribution and transmission system investments are ongoing and certainly see the benefits of those in the system. Total DSIP and TSIP investments are expected to be about $340 million over the next five years.

Natural gas reserves, we do currently own 25% of our natural gas requirements for both retail customers and generation and invested about $100 million through September. We would like to own 50% of our requirements and that would require an additional investment of probably around $100 million.

Last slide I'll speak to, this is our capital spending forecast. You've seen this before and you'll see that over the next 2015 through 2019, we expect to invest about $1.45 billion and this is in maintenance, CapEx, our DSIP expenditures, we do have the Big Stone investments reflected for 2015, transmission investments, and then a layer of hydro-related investments on top of that. As we explain every quarter, this does not include additional projects such as the Beethoven acquisition and a future natural gas acquisition's peaking generation investments or the like. These are the investments that are clearly in front of us right now and we do expect we would be able to fund these through a combination of cash flows and that would be assisted by the NOLs, along with long-term debt.

So with that, we will open it up for your questions.

Thank you.

(Operator Instructions)

We'll go first to Dan Eggers with Credit Suisse.

Hi, good afternoon, guys. First question I guess is just on the tax rate, moving into the higher end of the range this year. How should we be thinking about the tax rate for next year, and then, how much of a reduction in tax expense are we going to see because of the PTCs generated out of Beethoven?

That's a great question, Dan. We, historically, had stated that we expected our tax rate to get up to around 20% by 2017. As a result of the Beethoven transaction and -- the big benefit, if you will, is the PTCs associated with that transaction. That will drive our tax rate down considerably and our expectation is that we wouldn't see that tax rate certainly that high. We expect now that it would get up into maybe the low to mid-teens by 2017.

What utilization rate should we be -- because obviously it's very volumetric to affect utility earnings, but what utilization rate should be assume on Beethoven's trying to worm our way into a tax benefit?

I'd say we would probably be in the -- I don't know that number off the top of my head. I'd have to get back to you with that, Dan.

Okay, got it. And then, just on the gas reserves and rate base, is there anything new of substance to add, either advancing on getting the next $100 million spent or you having gotten any interested people willing to sell reserves as gas prices continue to languish?

No, again, we've looked at various opportunities but have not found the combination of the right set of assets at the right price with a willing seller. But we are certainly actively looking.

(Multiple speakers).

I'm sorry, Dan. Just to answer your earlier question, it would be around 45%. For utilization --

45% utilization. Okay, very good, thank you. Bob, just on the not found the right set of assets, is the opportunity set getting larger or smaller at this point?

Well, I'm not sure it's either expanding or contracting.

Okay, very good. Thank you, guys.

Thank you. We'll go next to Paul Ridzon from KeyBanc.

Just a follow-on on Beethoven. The benefits of the PTCs accrue to rate payers, I assume?

Well, actually, we're allowed to capture what we would expect to get from earnings in an asset like that, but ultimately the benefit of PTCs also accrue to customers.

And if there's variability in wind, does that flow through the fuel clause or is there an assumed wind resource and there could be some earnings variability around that?

It does flow through.

Okay, great. And then, any sense what FERC's thinking is with regards to Dave Gates? Where is it in their stack of work?

We don't know and I'm not sure that there is any real FERC thinking on that issue. That's not intended to be critical. I don't have the sense it's a very visible matter.

And then, do you have any recourse on the LRAM? Can you appeal that? Or -- and, if not, how much of that do you think you can offset?

I would say we're looking at the decision and we will make an appropriate decision about what recourse we have. Beyond that, the reality is that regulatory decisions, federal or state, affect our ability to invest in serving our customers, and that's just a function of being a regulated utility. So we have to ultimately deal with decisions such as eliminating the LRAM by managing our budget, and it does have an effect on our ability to invest in operations. Now, that said, again, at some point, when a rate case is filed, that essentially resets the base. But regulatory decisions of any kind are very powerful in driving our ability to invest in serving our customers.

What's your latest thought about when the next Montana case could be filed?

Well, again, as we say, we will be looking at all of our jurisdictions in the spring -- typically in April -- and then we'll make decisions after that.

Okay, thank you very much.

Thank you.

We'll go next to Jonathan Reeder from Wells Fargo Securities.

Hi, actually most of my questions have been answered already. But I did want to follow-up on the LRAM. So what's in guidance right now? It's the loss of the $7.1 million, but just pro rata, for essentially Q4 for 2015, is that right?

Yes, that's right. The order doesn't go in effect until December 1. We've taken that all into consideration.

The order doesn't go in effect until December 1. Okay. And then, as we look to 2016, we would expect I guess the full-year impact until essentially your next rate case where then you can hopefully get that encompassed into your base rates? Is that the way to think about it?

That's right. That's correct.

Okay. And then, if you could, Brian, could you also expand a little bit on that gas-tracker decision you alluded to?

Yes, what effectively has happened there is we have been putting our gas assets -- the gas production assets, into the tracker, as you -- with the intent ultimately of those assets going into a rate base with either a stand-alone filing or through a full natural gas rate case. Costs in those particular items do change and, as a result of that, some of those costs were not allowed in the tracker.

Okay. And what was the extent -- was it a material portion?

$1.6 million.

$1.6 million. Okay. All right, thank you very much.

Thanks, Jonathan.

(Operator Instructions)

We'll go next to Doug Christopher with Crowell Weedon.

Hi, thank you very much. I wanted to go back to the comment that you made on taxes and that was that, in the press release, you currently expect the tax rate to range between 17% and 19% for 2015, but then indicating that, by 2017, actually you would be at a low to mid-teens rate.

Yes, I think to think about what Beethoven is going to do, ultimately -- Beethoven on a stand-alone basis is going to have a detriment from a pretax perspective, but the benefits from the PTC is ultimately going to improve net income. And so, think about that improvement to the tax rate is ultimately reducing our tax rate. So that will put us down. And we haven't talked about our range for 2016 yet from a tax rate perspective but, as I pointed out, we do expect to be in that low to mid-teens by 2017.

Okay. Thank you. And then, on the natural gas -- the goal of increasing the natural gas assets. Since company's been discussing this and it's been an objective, natural gas prices have deteriorated further. Does that mean for the $100 million potential you'll be able to get more reserves than you could a year ago?

Certainly, yes. And, again, it's a great time, from a customer perspective, to be doing these kinds of transactions. The challenge we have is just identifying projects where we can transact. But it's a -- if we can get that done, it's just a huge win for customers.

Thank you.

We'll go next to Paul Peterson from Glenrock Associates.

Good afternoon. It's Paul Patterson.

Hi, Paul.

Just a couple quick ones. On the LRAM, it was a unanimous decision, I think, right? And I mean, it seemed like it was quite a reversal. Any thoughts as to what sort of philosophically is now occurring at the Commission with respect to this issue and their visceral reaction to it?

I'm going to let the Commission speak for itself. You're right, this was a unanimous decision and takes the Montana Commission in a bit of a different direction from many states around the country which have adopted more true decoupling mechanisms. As a Company, we're committed to providing our customers the best diversified cost effective portfolio of resources possible, including energy efficiency. But as a result of the back fit (technical difficulty) prices for electricity and natural gas, as opposed to, for example, phone service, are volumetric, you have to have a strategy to be able to cover your costs and earn a return.

And I am concerned that, in a world where energy efficiency and in a country where energy efficiency is an increasing priority, we just haven't got that figured out. But, again, I acknowledge the Commissioners' sincere concern to ensure that customers are treated fairly and hope we can work with them on an alternate mechanism. It was notable that there was some interest in revisiting the subject of a decoupling mechanism -- and actually Montana did have decoupling in the 1990s prior to supply deregulation -- so there may be an opportunity to take another look at that.

Okay. And then you mentioned that it would be reset --, and I apologize if I missed this, but you mentioned that you would have reset it within the next rate case and I'm just wondering if you'd give us a little bit more of a feeling as to -- and I might have missed it so I apologize because I got distracted, but if there's any timing that you guys could give us in terms of when you guys plan on having the next rate case?

No, I think my comment to that question was, we look at each jurisdiction and each sector in spring, typically in April, so we would make a decision for Montana gas and electric, for example, at that time.

Okay. But can you tell us what the earned ROE for the last 12 months is, and the last surveillance reporting date was for your jurisdiction?

No, I don't have that information with me, Paul, at this time. We do file in Montana what's called an Annual Report that shows what that return is, and the last one we filed would have been for 2014. My recollection is, for 2014, our electric was approximately 11% and our gas was approximately 9%.

Has that changed a lot since then?

Difficult to say. Obviously we've got to run our numbers here through the end of the year to be able to update those numbers in the February timetable.

Okay. In terms of Big Stone station, what happens when it actually gets into -- when it actually is completed, just accounting-wise? Do you start to depreciate it? Is there any sort of regulatory treatment for it? Just if you could remind us how -- when that facility is in rate base -- or, excuse me, when it's completed, what happens then? Accounting-wise. Do you follow me?

Yes, up until it's actually put into rate base, we've been able to earn AFUDC on the investment. And their expectation is, near the end of the year, when ultimately that asset is going to go into a rate base, AFUDC, of course, will stop. But we will also then start getting a revenue requirement associated with that investment as it is a rate base -- is an asset in rate base at that time.

So you guys will get revenue for it. Does that happen automatically or does that have to be a rate case I guess is what I'm (multiple speakers)?

No, that is part of the settlement that we have with the staff at this point in time that will be ultimately ruled on, on October 29. (Multiple speakers) Thank you. Presented. Thank you, Bob.

And then, the Dave Gates, just on terms of rehearing, I've noticed with some FERC cases that it can be several years for these guys to actually address rehearing. I just noticed that, in the last couple meetings, that they were sort of cleaning (multiple speakers). Right, so is there any time frame here where, if there is no action on rehearing that you have to -- you can't go to court I think until there is a final ruling on rehearing, if I'm correct. Would there be any potential impairment that could happen if, in fact, this drags on and we don't have anything coming out of FERC?

We are evaluating, on a regular basis, whether or not there is any potential for an impairment, and at this point we don't think so. Your other comment is correct. But the decision on rehearing is necessary before judicial appeal.

Okay. And then, just finally, with the repairs tax impact that you guys are benefiting from, does that have any impact in a future rate case in terms of impacting rate base and what have you? How should we think about that, if you were to go into a rate case, how the benefit associated with repairs deduction might -- may or may not impact a rate case in the future?

Ultimately, those benefits will accrue to customers in the next rate case. Because what happens is, it ultimately reduces your effective tax rate and that new lower effective tax rate would be the tax rate that you'd be able to earn on in the next rate case.

Okay. But what you've taken so far, that wouldn't impact rate base or anything like that, correct?

No.

Okay. And I think that is all of my questions. Thanks so much.

Thank you.

We'll go next to Paul Ridzon with KeyBanc.

Just a quick follow-up. When do you expect to burn through your tax shield?

Thanks, Paul, for that question. The answer, again, we -- assuming there's not another bonus extension -- but obviously we don't know the answer on that right now, but we're still holding true to the fact that we believe that, into 2017, we will still be utilizing NOLs.

And do you have any read on prospects of bonus fee being extended?

Well, we certainly are having people look into that but they don't have the answers yet themselves.

Okay. Thanks again.

We'll go next to Joe Zhou from Avon Capital Advisors.

Hi, it's Andy Levi, how you doing?

Hi, Andy.

Just two questions. Just a follow-up on Paul's question on the repair tax. Why would that not be an adjustment to rate base?

Ultimately, like anything that adjusts an effective tax rate, these are passed through to customers in the next rate case.

That's the dollar amount, so I'm just trying to -- because in other states I believe, if I'm not mistaken, that there generally is an adjustment to rate base, so I'm just curious.

Andy, it's a function that we are a flow-through state in Montana.

Got it. Flow-through state. Okay. And then the second question I had was, just in natural gas acquisitions, I understand that you quote a dollar amount always, but is there a way to determine or have you talked about -- maybe I just don't have it -- the amount of actual gas you're looking to buy for the customer that would -- so because $100 million but then because, as you said, the assets have -- the price of the assets have changed. It's kind of hard to determine how much gas you're looking to. I think in the past you've put a percent of your total load or something like that?

Yes, the rule of thumb --and it really is just a rule of thumb -- is that we would like to have about 50% of our requirements both for retail gas for our electric generation needs and we could get that done at current market prices for about $100 million.

Okay. And how much do you have currently of that 50%?

We have 6 Bcf of gas and we would like to get another 6 Bcf. So, obviously, if prices continue to stay low, we could do something less than $100 million as well.

Okay, 6 Bcf, that's what I was looking for. Great. Thank you very much. See you soon.

See you, Andy.

Thank you. We'll go next to Doug Christopher from Crowell Weedon.

Hi, thank you for taking my follow-up call -- Crowell Weedon and D.A. Davidson. It sounds like you've been great stewards -- you've been adding renewables and, not only that, you've been buying at attractive prices, as you indicated, with the hydro comparison, been enhancing the reliability of the assets as well. Is there any sense in the discussions I guess with the Commissioners, the regulators, that this has been at least positive in your relationship or getting your requests through?

Well, I think, generally -- well more than generally, the acquisition of the hydro system has been recognized as a true long-term positive for our customers and the Commission, obviously, did strongly support that.

And have you looked at this -- I can't recall, does this make you the most renewable utility or at least one of them, right?

We're definitely one of the most renewable utilities and certainly there are companies that might have more hydro capacity than we do in some regions, and there are utilities, obviously, that have lots of nuclear as well. So we're very proud of having, in Montana, a hydro-based system, with each of the resources contributing a tremendous amount of value to the diversity. What's frustrating to us -- one of the things that's a concern is that, if you look at pounds of carbon per megawatt hour of generation, our Montana fleet is actually already, right now, lower than the EPA's target for Montana in 2030 -- and that's, to me, kind of amazing.

But, under the EPA formula, we don't get credit for any of that, so there's something fundamentally flawed. We and our customers have already made investments that were transformational, from an environmental perspective, in how we generate power -- and what we get for it is bupkus.

Well, you're being good stewards. Keep up the good work. Thank you.

Thank you very much. And the stewardship role that we play is one that we're also extremely proud of.

Thanks, Doug.

(Operator Instructions)

There are no further questions in the queue at this time.

Great. Well, thank you all very much for your interest in the good discussion. I know we'll see you --, many of you, at the financial conference coming up. Otherwise we'll talk to you next quarter. Take care.

That does conclude today's conference. Thank you for your participation.