NorthWestern Energy Group Inc (NWE) 2015 Q2 法說會逐字稿

Good day, and welcome to the NorthWestern Corporation's Second Quarter 2015 Financial Results Conference Call. Today's conference is being recorded. At this time, I would like to turn the conference over to Mr. Travis Meyer. Please go ahead, sir.

Thank you, Janet. Good afternoon, and thank you for joining NorthWestern Corporation's financial results conference call and webcast for the quarter ended June 30, 2015. NorthWestern's results have been released, and this release is available on our website at northwesternenergy.com. We also released our 10-Q premarket this morning.

Presenting today are Bob Rowe, our president and chief executive officer; Brian Bird, our vice president and chief financial officer; as well as several other members of the executive team with us today. 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 will often contain words such as expects, anticipates, intends, plans, believes, speaks, or will. The information in this presentation is based upon our current expectations as 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 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 10-K and 10-Q, along with other public filings with the SEC.

Following this presentation, those who are joining us by teleconference will be able to ask questions. The archived replay of today's webcast will be available beginning at 6 PM Eastern today and can be found on our website under Our Company, Investor Relations, Presentations and Webcasts link. To access the audio replay of the call, please dial 888-203-1112, then access code 6653995. I will now turn it over to our president and CEO, Bob Rowe.

Thank you very much. Thank you all for joining us. We just completed our board meeting in Kearney, Nebraska, and Kearney is a thriving city in the heart of Nebraska and historically was a key point in the whole Western migration, where many of the western pathways crossed. As we always do, we had a great reception with community leaders and customers, and then a good breakfast meeting with our Kearney employees. I will give you the highlights reel on page 4 of the deck and then turn it over to Brian Bird for the play-by-play.

Our net income improved $23.3 million in the second quarter of this year as compared with the same period last year, and that's primary due to an insurance settlement and then the impact, of course, of the November 2014 hydro acquisition. Our diluted earnings per share of $0.65 compared to -- it was $0.65 compared to $0.20 for the same period last year, and our adjusted non-GAAP diluted EPS of $0.48 compares to $0.25 for the same period last year.

The insurance settlement agreement was with an insurance carrier for the former Montana Power Company and primarily related to previously incurred environmental remediation costs on electric generation assets. And these previously incurred remediation costs and the associated litigation expense to reach the settlement were not and have never been reflected in customer rates. As a result of the settlement, we recognized a net recovery pretax of $20.8 million. In addition, $20 million of 10- and 30-year Montana first mortgage bonds at a blended coupon of 3.74% to refinance $150 million of Montana first mortgage bonds with a 6.04% coupon due in 2016. We are reaffirming our full year 2015 adjusted guidance of $3.10 to $3.30 per diluted share. Our board of directors approved a $0.48 stick dividend payable on September 13, and we entered into an agreement to acquire for $143 million the 80 megawatt Beethoven wind project for the benefit of our South Dakota customers. With that, over to Brian.

Thanks, Bob. First of all, I'm happy to report we had a solid second quarter. In terms of our summary financial results, you'll see our net income for the three months ended June 30 was $31 million, or $23.3 million better than the prior year period, nearly a 300% increase. One thing I would point out regarding the results, if you look at the operating income line, there is an improvement of $36 million there on a year-over-year basis. Really, three items drive that generally. First and foremost, if you take all of the results from hydro operations including $38.3 million in gross margin plus the total operating expenses, you get a net benefit of $20.2 million associated with the hydro assets. So, on a year-over-year performance an improvement there. The addition of $20.8 million insurance recovery, that Bob mentioned, offset slightly by $4.3 million from a QF adjustment. Those three items add up to $36.7 million, or pretty much right in line with the improvement on a year-over-year basis in operating income.

I guess the fourth thing I would point out is we also experienced warmer weather during the quarter that impacted primarily our gas business, but the Company was well aware of expected weather and really did a nice job of managing expenses. So, it helped keep operating income at the levels I suggest.

Moving forward in terms of gross margin, I mentioned the $38.3 million associated with hydro operations. We also saw a slight benefit in retail volumes on the electric side, and then some transmission capacity added as well, again, offset by the QF adjustment. So, net-net, a nice improvement, $36.9 million on the electric side of our business, but our gas business did suffer. We had quite a bit of warmer weather on a year-over-year basis; that impacted our natural gas retail volumes and we did have a slight gas production deferral as well.

Speaking of the segments themselves, as you might guess, both on a quarter and a year-to-date basis, the electric segment is doing quite well on a year-over-year basis, the gas business segment is not. It's struggling versus the prior year, again primarily due to warmer weather. And then our other segment is certainly up on a year-over-year basis as a result of the insurance settlement.

Moving on to page 7, in terms of second quarter weather, you would expect some good news when you see cooling degree days with a touch increase, but we really don't see a lot of cooling benefit in our Montana business, particularly in the second quarter of the year. So, actually our retail and commercial loads relatively flat on a year-over-year basis, but you do see on the heating degree side certainly the warmer weather on a year-over-year basis and versus historic certainly hurt our results for the quarter.

Moving to operating expenses, our total operating expenses are $129.9 million, or $2.9 million less than the prior period last year. Really, I'd sum up that difference of $2.9 million really through two items. The hydro-related expenses, again, not just in operating, general and administrative, but that portion of property and other taxes and depreciation and depletion. Those total operating expenses are $18.1 million associated with hydro. Offset that with a $20.8 million insurance recovery, and that's $2.7 million, or pretty much right in line with the change in operating expenses. So, again, all other expenses were relatively flat on a year-over-year basis.

Moving forward to kind of going from operating income to net income, interest expense is up $3.8 million, incremental financing associated with the hydro transaction. Other income is down $2 million; that is associated with the reduction that we see in the value of deferred shares held in trust for a nonemployee director's deferred comp. I think you all know, though, any detriment you would see there is a positive we'd see in operating expenses. Those two offset one another. And lastly you see a $7 million increase in income taxes that is all a result of higher pretax income on a year-over-year basis.

Moving to page 10, talking about adjusted earnings, I hope you all find this helpful. What we try to do is take GAAP earnings on both the far left and the far right for the three months ended June 30, 2015 versus the three months ended June 30, 2014. To show what those numbers are, by the way, in a diluted EPS through the three months ended June 30, we had 65% diluted EPS versus $0.20 for the same period last year. But we did have some adjustments during the year. In 2015, we had unfavorable weather for the quarter by $1.5 million. We also removed the QF adjustment, the portion of that QF adjustment associated with our review of the liability itself, $6.1 million, and then we do remove the insurance settlement as well. When you take those things into consideration, our diluted EPS for the quarter is $0.48 compared to an adjusted $0.25 on a year-over-year basis, still a 92% increase on a year-over-year basis, so a very solid quarter.

Moving ahead to year-to-date earnings, on page 11, pretty much the same story. When you back our weather, really the difference, I guess, we recall that we had about $11 million on a year-to-date basis of unfavorable weather -- excuse me, margins, and we determined $8.6 million of that is associated with weather, so we show that as an adjustment. So, on an adjusted basis, a non-GAAP six-month ended June 30, 2015 versus 2014, we're seeing $1.66 versus $1.41, or an 18% improvement on a year-over-year basis. Obviously, you look at both of those two slides you see a vast improvement across operating income and net income, and so we feel very, very good about how the quarter and year-to-date things are going.

With that, just turning your attention quickly to the balance sheet. Not a lot of change since the end of the year. It's good to see from a total asset perspective the company over $5 billion in assets today and shareholders' liability now over $1.5 billion. On a ratio of debt to total capital we continue to move that downwards. We don't like to see that within the 50 to 55% range and hope that we'll see that during the coming months of the year.

Moving forward to the cash flow statement, on page 13, from cash flow provided by operating activities of nearly a $66 million improvement in the six months 2015 versus six months 2014. $190 million of cash flow provided by operations primarily driven by the higher net income and a reduction in under-collection of supply costs. So, we'd like to see that improvement and, again, the demonstrated benefit of the hydro transaction.

Moving forward, on page 14, based upon our results thus far through the first six months of the year, the Company is reaffirming its guidance of $3.10 to $3.30 per share, and utilizing the same assumptions that we had the previous quarter. With that, the last thing I would point out, I'd like to wish Bob a happy birthday tomorrow, and with that, back to you, Bob.

Thank you very much, and we did have quite a memorable birthday party in Kearney last night, embarrassing as could be. I'll start with a bit of an update on the South Dakota rate filing. You've seen part of this presentation before, and this has also been very helpful, I think, in communicating to customers what's going on. And the real success here from a customer bill perspective is our ability to manage costs to customers very, very effectively over a long period of time. The chart at the upper left shows that our fixed charges until making this filing essentially been flat now for decades. The only increase in costs our customers have experienced over the years has been in the various track-related portions of the bill -- fuel transmission, ad valorem taxes, things like that. You look to the lower left you see the comparison of the nominal customer bill, assuming average of 750 kWh per month. The nominal rate, again, quite flat. And then if those rates had been TPI adjusted, that's what a customer would be paying now, bringing forward the 1981 bill. Compare that to where our bills actually were, that's in real terms declining costs over that long period of time, and that doesn't happen for very many commodities, obviously.

Over on the right we give you a breakdown of what are in the docket and [notably] the overall rate of return that we're requesting is 7.76%, and that, I think, is very attractive. That is on a rate base of over $447 million. The lower right you see a depiction of our investment in South Dakota over that time even as customer bills have remained essentially flat in nominal terms. So, applying the rate of return and then bringing forward the expenses to the total revenue requirement, this request is driven overwhelmingly by the environmental compliance expenditures at Big Stone and Neal. Add to that our investment in the system, particularly the Aberdeen peaker from several years ago and the Yankton substation.

I would mention, we have been out holding community meetings on our own. The Public Utility Commission has held one public hearing as well. Over the next two months we'll be seeing -- we're still answering data requests at this point. We'll be seeing testimony from interveners and the commission staff and looking towards a hearing in the middle of this fall. The commission, I think, is doing a thorough and professional job of moving this case forward. I expect we'll be talking some more about that in the Q&A. So far no surprises in the case and we're moving ahead in answering discovery.

Page 16, a little bit more on the Beethoven wind acquisition, and this is something we're quite excited about. We have executed now an agreement with BayWa just over the last several days to purchase two recently completed qualifying facility wind projects in South Dakota for a total purchase price of $143 million. And the energy and the associated renewable energy credits, or RECs, for this 80 megawatt project are currently included in our supply portfolio under a QF power purchase agreement, and the existing PPA will terminate upon closing, and we are requesting the project be placed into rate base as part of our pending electric general rate filing. And we would file the information formally with the commission as part of the update to our filing, which typically occurs in a case that pends for as long as a general rate case does. We expect to close certainly before the end of the year. Financing will be through issuing up to $70 million in long-term debt, and up to $60 million in common stock, and then funding the remaining amounts with our available cash. From a customer perspective, this is an attractive transaction, because owning the asset will significantly lower the costs to customers. Over the long term it is expected to be accretive to earnings, but importantly we can't quantify that until the Public Utility Commission makes a final determination on the general rate case, and we anticipate that by the end of 2015.

The next couple of slides are new, and over the last several years, as we focused on our Montana portfolio and our focus in South Dakota has particularly been on environmental compliance expenditures, we haven't talked as much about our entire fleet. So, on slide 17 we give you a snapshot of assets that we have either built or purchased since 2007. On the far left you see that in terms of our own South Dakota resources, we are 18% renewable with the Beethoven acquisition. Our Montana portfolio was actually pretty remarkable [with] 69% of our Montana portfolio is either renewable or supports renewable. By that, of course, I'm referring to the Dave Gates generating station. And by way of contrast, states such as California have announced targets of getting to, for example, 50% renewable resources with prices much, much higher than the prices our customers face. And then to the right you see our total Company renewable portfolio including both South Dakota and Montana, and even there we are 49% renewable or, again, supporting renewable. These are owned resources built or purchased since 2007.

Page 18 gives you an all-in portrayal of our portfolio both owned and contracted resources, and there South Dakota with Beethoven plus other contracted renewables, we are 25% renewable at this point and very proud to be there. In Montana, owned and contracted 67% renewable, and that is really quite remarkable. From a total Company perspective, we are 54% renewable, and this is including Beethoven.

Page 19, I'll just give you a quick summary of some other activities. First, as a result of the hydro acquisition, we have in Montana a very diverse portfolio of assets. We have undertaken a series of studies now pointing towards the ability to optimize that diverse set of assets. So, we will be looking at best ways to integrate our generating fleet as an integrated portfolio and including determining the most economic means of providing ancillary services. When the study is finalized, we anticipate it making this a big implementing operational change to help us lower the overall cost and meeting our total portfolio requirements.

Second, as you are aware, Kerr Dam will be transferring to the Confederated Salish and Kootenai tribes in September. We expect that transfer to go forward on September 5. And as a result of that, then we expect to receive -- we will receive proceeds from the conveyance of $30 million. So, again, from our perspective, the hydro assets are operating well and we expect the transfer of Kerr, from our perspective, to go smoothly.

Next, as you know, one of our primary areas of focus has been several air quality projects, particularly at Big Stone, and that project is nearing completion, or 23.4% of the project cost will come in at about $95 million to $105 million, and including AFUDC being capitalized $91.8 million through June of this year. We expect the project to be operational later this year.

Our investments, our system investments, particularly in Montana, in the distribution system infrastructure project and the parallel activity on the transmission side are going extremely well, and these are intended to address aging infrastructure, maintain reliability, and to proactively manage safety and building capacity where we need it. And we expect our total expenditures there to be about $340 million over the next five years. Natural gas reserves, we currently own about 25% of our Montana natural gas needs. We do continue to look for attractive opportunities and continue to target owning about 50% of our overall need and estimate we would need to invest about $100 million to reach our ownership goal.

Dave Gates generating station, as you know, we have a request for reconsideration pending a -- rehearing, rather, pending at FERC. Yet again this quarter I have to tell you we have no news to report. We have deferred $27.3 million of revenue through June 30, 2015, and as we have noted before, we may appeal to the circuit court, if necessary, depending on what a FERC action might be.

The one slide I would highlight in the appendix is page 31, and this gives you our capital spending forecast. And as we've explained, we've shown this to you in previous quarters. This includes known specific capital expenditure projects and, as we've said, does not include projects that are not yet well defined. So, specifically, as we shared this with you before, did not include the Beethoven acquisition. As I said before, our ultimate debt and equity needs would be driven by our overall capital requirements, and we've described our financing approach for Beethoven. With that, I'll open it up to any questions.

Thank you. (Operator Instructions) Our first question comes from Jonathan Reeder with Wells Fargo.

We weren't sure whether to be concerned or relieved when the microphone was silent there. Good afternoon.

Well, in all fairness, I tried signaling in and it didn't go through the first couple of times, so it may be an issue on that end, but I was able to get through, so I appreciate you taking the question. Bob, I was just wondering, could you at all elaborate on the time frame for the South Dakota rate case in terms of various milestones along the way we should be looking for up until either potential timing of a settlement and/or commission final decision?

Yes. First of all, we did implement interim rates on July 1, and intervener testimony is the next key milestone, and certainly do pay attention to that. That would be September 14, rebuttal testimony October 5, parties' exhibit lists and witness lists October 12. A hearing is scheduled for October 27 through 30th.

Okay. So, the hearings are October 27?

That's correct.

I know you guys haven't been in a long time, but do you know typically in South Dakota if a settlement were to be reached, is this something that would occur prior to the hearings, after the hearings? Is there any specific requirement along those lines?

Based on experience of other companies that have been in recently, if a settlement is reached, that would be sometime before the hearing date.

Okay. And then is there a time frame after the hearing when the commission, I guess, has to act? Is there like a 60-day period or anything?

Well, we have a deadline in December associated with when we filed the case, but that's not a deadline triggered by when a settlement is reached.

Okay. And I saw on one of the slides you said you actually expect the wind acquisition to close in Q3, so I guess there would be perhaps a small period where you might have recovery of that asset. I'm assuming you would have to do the financing at that point. Is that kind of the right way to think about it, that there could be, I guess, a short period of drag between, I guess, the cost and recovery associated with it?

I think what we said was we would close in the last half of the year. Potentially there would be a limited period of drag, to use your word.

Okay. And then last question I have. Do you see any other opportunities either in South Dakota or in Montana in terms of whether it's acquiring the assets that are underlying some of your PPAs, putting them in the rate base and actually being able to earn on them as opposed to just passing through the costs, or is this just kind of a one-off type opportunity?

We try to avoid speculation. Certainly, we are interested in opportunities that make sense for us and for our customers. I am not prepared to discuss any now, though.

Okay. And then, I guess, last question on the national gas reserves, any update there, pricing, is it still economic on you end, just needing to find kind of the willing seller?

Yes, it certainly is economic and from a long-term customer perspective, this is a very good time to do it. We are -- I hate to repeat myself quarter-to-quarter, but we certainly are actively looking for those kinds of opportunities.

Okay, great. Thanks.

Thank you.

Our next question comes from Dan Eggers with Credit Suisse.

Hey, good afternoon, guys. If we can get into the Beethoven a little bit more. Can you just walk through the process as far as your comfort in needing commission approval, that this is going to go into rate base before you close on the transaction? And then if you look at the rate difference between what it would cost customers when it goes in under your ownership versus the QF agreement, which is probably a little more levelized of a price?

I don't want to in any way prejudge a final PUC decision. What I would say that in South Dakota we are very clear and comfortable with the commission's view that if there is a benefit shown to customers that they support company ownership, the Beethoven project has been discussed with commission staff, will be included then in the updated filing. And the customer benefit is a significant net present value savings under our ownership as opposed to under the QF formula. And, again, these are assets that are already essentially included in rates.

So, they're already included in rates, so would there be a step up or a step down, or is it you're just not going to say right now?

Brian?

Dan, what I would say is this. We obviously have to work with the commission in order to ultimately get this into rate based, and so it's premature to talk about exactly how it's going to play out.

Okay. From a funding perspective, like you said $60 million of equity, would that be an organized offering, or how would you guys think about financing that piece? And what point in time do you get comfortable again on procuring long-term financing for this?

Let's be clear, Dan, it would be up to $60 million, and I think we're still working through the arrangements of what that offering would look like.

Okay. When we look at Dave Gates at this point in time, and I understand we're kind of waiting for an awfully long period of time, is there anything you guys can do to try and go to court or something to move this along, or is this just a wait-and-see and then pursue litigation at that point?

At the FERC there is not a timeline on when the commission has to act on rehearing. We have been, as I mentioned, really focusing more on the operational side over the months since we acquired the hydro system. And our use of Dave Gates as part of an integrated system is one of the -- probably one of the data points, but at some point we would like to be able to share with the FERC as well as with the Montana Commission. What's frustrating is that the design of Dave Gates, the three units with two active and one spare has pretty much been vindicated. We have been able to meet our reliability requirements and handle scheduled outages and repairs so that the design makes good sense. We are providing a service, a valuable service to our FERC jurisdictional customers. On the other side of that is that our fleet looks very different in Montana now than it did when Dave Gates was built, so I think we have an opportunity to look at the entire fleet and ask how that fleet can be operated on an integrated basis as efficiently as possible for all of our customers.

Okay, on Beethoven, just one last question, is there the possibility or are there other assets similar to Beethoven where you guys can move them into rate base in the future or is this kind of the only one of size or substance?

Again, I really can't -- I'm not in a position to talk about any specific opportunities. Where there are assets that make sense for us to own, we are certainly open to an interest in that.

Okay, thank you, guys.

Our next question comes from Brian Chin with Merrill Lynch.

Hi. All my questions were asked and answered. Thank you.

Our next question is from Paul Ridzon with KeyBanc.

Good afternoon. How are you? You've got an option for 50 more megawatts. What are kind of the drivers of whether that option could be exercised and what's the need for more renewables? And would that be South Dakota jurisdiction as well?

Yes, that would be South Dakota jurisdictional. John Hines, our vice president for supply, is here, if he has any wisdom to impact. We'll turn it over to him.

It provides the utility the opportunity to build out that location. We do have a large generation interconnection agreement there. Bottom line is, it was part of the overall package with which we purchased it.

And is there an RPS in South Dakota?

There is not a mandatory one, there is a voluntary one.

Okay. And then can you quantify what the consumer net present value advantage is of you buying it?

No, I think in round numbers I would say it's approximately $13 million. The reason I was uncomfortable, Paul, is obviously, as we still continue to go through the costs and everything nailed down, that number could move. So, I would hate to throw out a moving number at this point in time, but approximately $13 million (inaudible).

Understood, but interesting your avoided costs are actually less than your avoided costs. I think those are all my questions. Thank you very much.

Regulation can be a funny thing.

(Operator Instructions) We will hear next from Brian Russo from Ladenburg Thalmann.

Hi. Good afternoon. In terms of the cash reserve acquisition opportunities, in the current forward gas curve, does it meet that criteria of the prior MCC settlement?

Yes, it very definitely meets it.

Okay, great. And the roughly 27% of your overall portfolio that's contracted, are there any larger PPAs within that that are rolling off in the next few years?

You're talking about the QFs?

Or any PPAs, meaning if a PPA rolls off, that might give you an opportunity to replace it with steel on the ground.

We have some QFs that are rolling off, but they're not rolling off in the near term, thinking in the 2020 time period and beyond.

The opportunities potentially are particularly to CELP and YELP, which are thermal byproducts and to the degree there is a desire to add more green or renewable resources, that would be a good opportunity.

I think it's also important to point out, Brian, that we've talked in the past about ultimately needing peaking potentially in both South Dakota and Montana.

Okay, and that's a good segue into my next question. Can you just discuss at a high level the upcoming IRP, and will David Gates be a generation source in that IRP?

We could turn it over to John for a little bit more color. The Montana resource plan is well under development. This will be the first plan in which we do have a complete portfolio of resources. As we've talked before, once Kerr is not part of that portfolio, we essentially will have our light load obligations met, and our load in Montana has some unique characteristics, since we for the most part are not the supply provider to the industrial customers, which often provide some real stability in the system. So, our focus will be certainly optimization of the fleet, and we talked about the study work that's been done in our supply area and that second planning to meet peak. Also during the period the plan is developed, we may see final EPA rules and we'll have to factor in how to deal with those. John?

We will probably not have the plan finished until mid-December. With that said, what Bob noted that we definitely will have peaking needs in the portfolio. Dave Gates will be a part of the portfolio. It is likely to provide multiple different purposes as opposed to just providing regulation at this point in time. But fine details still need to be determined.

So, to clarify, so we should expect an IRP filing in mid-December?

That's correct.

Okay. And then -- go ahead.

I was just going to say, and then in South Dakota, the Beethoven acquisition is merely a transfer of a PPA to an owned facility and thus it does not impact our need for additional peaking capability and can reserve margin capability, which we have previously identified.

Can you quantify the number of megawatts of peaking capacity you need in both jurisdictions?

In South Dakota we're looking at somewhere around 50 megawatts; in Montana it's probably premature.

Okay. Then, lastly, Brian, can you remind us what the NOL balance is currently and how long will those NOLs last?

Well, we talked, Brian, we continue to say into 2016 -- actually into 2017, pardon me. And I'm looking up the balance as we speak.

Okay. Well, that's all I had. Thank you very much.

Brian, do you have it?

Yes, the balance is about $350 million.

John, just to stay with Brian's previous question, why don't you say just a little bit more about the reserve requirements in South Dakota, particularly?

Certainly. There is a requirement, especially as we move into SBP, where we'll be having to have additional capacity available in excess of what our peak demand is. That is growing over the next three to five years, and we anticipate, like I said, around 50 megawatts of additional peaking capabilities to meet that reserve requirement over the next five years.

Why don't you say what the reserve requirement is in Montana and how we made that?

Well, there is no requirement in our state right now, but (inaudible) --

(Inaudible)

(Inaudible) and we do not think that sufficiently meets the reliability issue.

Okay, thank you very much.

(Operator Instructions) We'll hear next from Paul Ridzon with KeyBanc.

Just real quickly, how is Kerr performing against the hold harmless requirement for rate payers?

We are positive.

Okay, thank you very much.

There are no further questions in the queue at this time. Mr. Meyer, I'll turn the call back to you.

Before you do that, if I could add just a note about how the hydro system is performing this year. I think that is of interest. Brian described the weather in the West in terms of temperatures, but another key factor is we've had a fairly significant drought. Despite the drought, our hydro production at this point in the year we expect is going to meet our forecast at the start of the year. And actually factoring in production from Kerr, about half of our requirements in Montana were met with the hydro system. But we think that showed, among other things, was the diversity benefit within the Montana hydro system of owning generators, not just in one location, but in multiple drainages and other benefits as well. But we've been in a very tough hydro year. We've been extremely pleased with the performance, and going on from there in a typical year, an awful lot of water is spilled. In other words, it's not used to generate, so at some point, if it were cost effective, if there were reason to do so, there is additional generation to be produced out of that system. That is not something we're doing at this point, but I think most people would say that a hydro system like this is ultimately the very best renewable resource, and that has been our experience this year. With that, thank you very much for joining us. We look forward to seeing quite a few of you probably over the coming months and talk to all of you next quarter.

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