NorthWestern Energy Group Inc (NWE) 2014 Q2 法說會逐字稿

Good day and welcome to the NorthWestern Corporation second-quarter 2014 financial results. 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, Anna. Good afternoon and thank you for joining us for NorthWestern Corporation's financial results conference call and webcast for the quarter ended June 30, 2014. NorthWestern's results have been released and the release is available on our website at www.northwesternenergy.com. We also released our 10-Q premarket this morning.

Joining us on the call today are Bob Rowe, President and CEO; Brian Bird, Vice President and Chief Financial Officer; Heather Grahame, Vice President & General Counsel; Kendall Kliewer, Vice President and Controller; John Hines, Vice President of Energy Supply; and Mike Cashell, Vice President of Transmission.

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 need to 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 contain words such as expects, anticipates, intends, plans, believes, seeks, or will.

This information in this presentation is based upon our current expectations as of this 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-Q, which we filed with the SEC this morning, and other public filings with the SEC.

Following our 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 Time today and can be found on our website at www.northwesternenergy.com under Our Company/Investor Relations/Presentations and Webcasts link. To access the audio replay of the call, dial 888-203-1112, then access code 8886085. Again, that's 888-203-1112, access code 8886085.

I will now turn it over to our President and CEO, Bob Rowe.

Thank you very much.

Just to start off and give you some flavor for our service territory, we're joining you today from our Bozeman, Montana, division office. The Bozeman division is very, very dynamic. It serves, obviously, the Bozeman area, also down into Yellowstone Park, across the border into Wyoming, Big Sky, where we're experiencing a lot of growth and demand and great employees doing the job.

Our Board Meeting was primarily about 40 minutes west of here in Three Forks, Montana at the historic Sacajawea Inn. And that's an important place to the Company. It's the headwaters of the Missouri River that flows north through much of our Montana service territory, then of course heads east into the Dakotas, down through South Dakota and ultimately goes by our Yankton, South Dakota operation as well. So it really does tie our whole company together.

As we typically do, we had a good employee meeting this morning. Great community reception in Three Forks two nights ago and we really appreciated the support that a very large community from that part of Montana showed for what our employees are doing in all kinds of ways and, as you'd expect, a lot of enthusiasm for our proposed hydro acquisition, too.

Another thing we did during the Board Meeting was take the Board down to see the Madison Dam in the Bear Trap Canyon. The Madison is the oldest and one of the smallest facilities that we hope to be acquiring. But the power house was absolutely spotless. The employees that hopefully coming over from PPL are just incredibly proud of their operation and they refer to that as the flagship of the entire hydro system. So, again, it's been a great couple of days.

Some highlights here -- 3% improvement in gross margin. That's despite slightly milder weather as compared to the same quarter last year.

Concerning our Dave Gates Generating Station, as many of you know, in April of this year the FERC finally issued an order affirming a previous FERC Administrative Law Judge's initial decision in September of 2012. And that regarded cost allocation at DDGS between retail and wholesale customers. On May 19 of this year we filed a request for rehearing, which is pending before the FERC. We'll come back and talk about that some more.

On July 18, just a few days ago, we completed a robust and nearly two-week regulatory hearing in front of the Montana Public Service Commission requesting approval of the purchase of the hydro generating assets from PPL. As an aside, we now have all of the license transfers approved from FERC. And we'll come back and talk about all of that in more detail.

And our Board of Directors declared a quarterly stock dividend of $0.40 per share payable on September 30.

And with that, I'll turn it over to Mr. Bird.

Thanks, Bob.

In terms of the summary financial results on page 5 for the three months ended June 30, 2014, we showed $7.7 million of net income compared to $14.3 million for the three months ended June 30, 2013. On a six month ended June 30, or year-to-date numbers, we were at $53.3 million net income this year versus $52.2 million from the prior year.

One thing I'd say about the second quarter, the second quarter typically contributes the least amount to our annual net income. Matter of fact, from 2011 to 2013 the second quarter has contributed about 12% to our total. This particular quarter, if you take the contribution here against the midpoint of our guidance, particularly on an adjusted basis, it would contribute about 10%. When you add that with our strong first quarter, we expect to be around 53% of our midpoint on our year-to-date results.

And typically over the last three years through the first and second quarter we're at about 50%. So little bit ahead of where plans are typically through the first half of the year. And though we had a mild weather quarter, as Bob pointed out, and results we'd like to have been stronger, we're still on track with where we need to be on a full-year basis.

Another thing I'd point out here on this particular slide, you can see at the top of the page, when you look at gross margin you can see the three months compared to the year-to-date numbers, it's significantly less than half. But, when you look at operating expenses, they're very, very close to half, the three months versus the six months. So in other words, our volumetric business we have very strong first and fourth quarters, but our operating expenses are pretty constant throughout the year and, thus, another reason why our operating income is certainly lower for the three months than you would have seen in the first quarter.

The last thing I'd like to point out, just to reiterate, we are on track. From our perspective the second quarter came in relatively close to our plans. And, again, we are on target to hit our year-end guidance.

Moving on to the next page just to focus directly on the second quarter itself, pretax basis we were off about $7.5 million. And I'd really summarize that under five different things. If you take a look at the gas production business, the margin from that business less the production costs, we're up about $2.2 million on a quarter-over-quarter basis.

Offsetting that favorable impact were really four negatives. First and foremost, from a hydro expense standpoint, $2.8 million negative variance on year-over-year. $900,000 of that shows up in operating expenses and $1.9 million shows up in interest expense. That, added to bed debt expense of $2.2 million. And then, lastly, the fourth and fifth expense items that you'd expect to see with a growing company -- depreciation expense up $3 million on a year-over-year basis and property taxes up $2.2 million.

So in the grand scheme of things, that pretty much breaks up the quarter on the pretax basis. On an after-tax basis we did have a $900,000 favorable variance on income taxes for the quarter.

Moving forward, speaking directly to gross margin, we do see, as we utilize more of our gas business from a volumetric perspective, we do see an improvement in natural gas production. We did see a $5.1 million improvement on a year-over-year basis. Obviously, the addition of South Bear Paw in the fourth quarter of last year certainly on a year-over-year basis is a big driver for that improvement in the second quarter year over year.

Next, we point out from a demand-side management perspective of lost revenue recovery, that's primarily a timing issue, again, year over year. Regarding natural gas retail volumes, $900,000 unfavorable. We did have a milder second quarter than we did have the prior year.

One thing I would point out there, just a little more color there -- our use per customer dropped by over 6% during the quarter. Our customer growth rate, it's up slightly under 1%, which results in a net volumetric change, if you will, with slightly less than a 6% decrease on a year-over-basis.

So gas business was down, thus, almost $1 million negative variance there.

And on the electric side of our business, because of the mild weather we were flat there instead of being slightly up as we would have expected for the quarter.

Moving forward on operating expenses, total operating expenses were up $12.2 million. Regarding the OG&A, or operating, general and administrative, expenses were up $7 million with 10% of those. And the first and foremost is natural gas production of course again offsetting that against the $5.1 million in margin I talked about, was kind of that $2.2 million of improvement year over year.

The second increase was in bad debt expense. And primarily that bad debt expense is from two items. First, we did have certainly a colder fourth quarter of 2013 and first quarter of 2014 and collections as you will -- as, excuse me, revenues as a result are high and thus you expect some additional bad debt expense.

But secondly, we've had implementation of a new CIS system. As a result of that we had some delays in terms of collections and some implementation items we needed to work through. And that has also resulted in us having higher bad debt reserves than we typically would.

And, by the way, some additional color there, what we do is we put anything over 90 days past due goes into a bad debt reserve. So as we continue to make enhancements to the system and we continue to do that here in the third quarter, our expectation is we may see bad debt expense go up for a period of time. But we do expect to get a recovery of some of those bad debt reserves before the end of the year.

The third item here is nonemployee directors' deferred compensation. Certainly those folks who have covered the Company a long time and for some time understand an increase here from an operating expense perspective is offset in total in the other income. And I'll talk about that in a minute. So that has no impact, if you will, on the P&L as a whole.

Another item is hydro transaction costs. Again, these are the -- think of the legal and other advisor costs which you incur from your operating expense perspective. We also have, and I'll point out in a minute, $1.9 million of additional interest expense associated with the hydro transaction.

The other areas of increase from operating expenses are in property taxes and depreciation. And included in depreciation, by the way, is depletion, another incremental cost, if you will, from having our natural gas business. And, as I pointed out earlier, both the production costs and the depletion will stay relatively constant quarter over quarter in a particular year, if you will, or quarter to quarter in a particular year and throughout the year. It's the actual volumetrics of that business are going to be better in the first and fourth quarter in those quarters when we typically have higher volumes for our business.

Moving forward in terms of items below operating income and operating income we were down about $7.6 million on a year-over-year basis. Interest expense is up about $2 million. But that's primarily related to the $1.9 million of expense associated with our credit facility, or bridge, for the hydro transaction. That's in place.

Below that is the favorable income associated with other income of about $2.1 million. And that's primarily driven by the $1.5 million gain on deferred compensation we talked about up in operations, operating expenses. The other part of that variance is in improvements in AFUDC.

And that's getting back to kind of on that $7.5 million unfavorable pretax variance. And as I pointed out on -- we did have lower pretax. That did benefit in a $900,000 favorable income tax benefit. But we did see a slightly lower -- but, we did see lower flow-through items in the second quarter that had -- we expected to see that favorable variance to be slightly higher. We do expect for a full-year basis our flow-through benefits to be in line to continue to provide our guidance of 14% to 16% from an income tax rate.

All in all, net income, again, $7.7 million compared to $14.3 million from the prior-year quarter, a variance $6.6 million negative.

Regarding the balance sheet, on page 10, not a lot to point out here since -- over the last six months. I do want you to pay attention, though, the ratio to debt to total capitalization. We typically see that that -- over six months we see that number come down from a 55% to something lower than that.

One thing we do want to point out, we did issue some debt associated with new market tax credits associated with our new general office in Butte, of approximately $28 million. That ultimately closed on July 1, but from an accounting perspective we did book that $28 million to long-term debt during the end of the second quarter. And the cash that will show up in restricted cash will not show up until the third quarter. So if you remove that $28 million from our long-term borrowings, our total debt to cap as of the end of June 30, 2014 would be 54.3%.

Moving forward to the cash flow statement, cash provided by operating activities is approximately $5 million less than it was for the six months ended June 30, 2013. The primary variance there is working capital changes. And the biggest difference really from a working capital was more a function of under-collection on our supply costs than it was from our receivables. We had been doing a better job in the second quarter in collecting receivables, but we still have a bit of work to do by the end of the year in that regard.

In terms of investing activities, we are investing certainly more from PP&E additions, year-over-year basis $112 million versus approximately $89 million. But on the financing side, proceeds from the issuance of common stock through the first six months of this year are down versus the prior six months of 2013. The reason being is we finished up our dribble program in 2014, the last issuance in the first half of this year. So that facility is now done.

As a result of all of that activity, at the end of the day we actually borrowed approximately $5 million versus paying down $58 million of debt last year.

Moving forward to adjusted EPS schedule, would point out on a diluted basis 2014 GAAP EPS of $0.20 versus $0.37 from the second quarter of 2013. We did make, from an adjusted standpoint, two items for non-GAAP adjustments, the first being we added back $0.01 from weather perspective and we added back $0.04 associated with hydro transaction costs. And as you can see from looking at slide 12, we added $0.04 in the second quarter, very similar to the $0.04 we added in the first quarter.

That got us to an adjusted $0.25 for the quarter versus $0.35 of adjusted 2013. And there was weather impacts. We actually had favorable weather in the second quarter of 2013 that was adjusted. So net/net a decline, if you will, of $0.10 from an EPS perspective year over year.

When you look at the charts just below that from a GAAP year to date, we had about $1.38 down to $1.37, just under a 1% decrease. But with the adjustments I just spoke about and adjustments that we also had in the first quarter of 2014, you see an adjusted EPS from $1.36 in 2013 to $1.41 in 2014 and just under a 4% increase.

Lastly on this page, just to point as we point out in the red box at the bottom -- as I also mentioned earlier on the call, we're typically about 50% of our earnings, if you will, through the first half of the year. And right now we sit at about 53% of our midpoint of our guidance. So we're right in line with what our expectations are for the year.

In terms of -- as a result of that, moving to slide 13, we are reaffirming our 2014 guidance of $2.60 to $2.75. We do have listed below some assumptions associated with that. The one that's highlighted in bold here was related to the hydro transaction. We are incurring fees of course during the year. But even if we are to receive approval on the transaction and we're able to close on that before year end, we are excluding any fees or any potential income in our guidance for the year.

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

Thank you, Brian. And I'll give you an update on several of the items that we do talk about quarter to quarter.

First of all, Dave Gates Generating Station -- as most of you know, some of you may not, this is essentially a transmission reliability resource. The great thing about using the PowerPoints, as we've been doing now for a number of quarters, is the ability to actually show you what we're talking about.

And you see the plant in the photo off to the right. It's three units which provide just one operating reserve to swing in and out as needed, for example, when a unit is taken down for repairs or maintenance, and simply to manage the operation. We have responsibilities to both our retail and wholesale customers. We operate a very large balancing authority out of our Montana system and DGGS was designed to allow us to meet this important obligation.

Montana Public Service Commission has consistently done a great job around working with us, approving the plant in advance, giving us clarity to what policy would be there. Brought the plant in $20 million under budget in December of 2010 and it's been operating very well now.

Separately then, we'd filed in 2010 -- or 2011 -- an application for recovery on the federal side as well. As many of you know, then we went through a contested case proceeding at the Federal Energy Regulatory Commission. Notably prudency and costs were not at issue there; it was really a question of allocating cost recovery jurisdictionally. And unfortunately the FERC ALJ took a very different view of allocation than what occurred in Montana or, in our view, different from what FERC precedence would have suggested. So we received what we considered to be a very unfavorable decision from the Administrative Law Judge in September of 2012.

We requested reconsideration in front of the full Commission. During that time we'd been recognizing revenue consistent with the Administrative Law Judge's initial decision and so, as a result, have reserved $27.3 million subject to refund through the end of June of this year.

In late April of this year, about 3.5 years after the plant completion, 20 months after the ALJ decision, FERC did issue really a summary order affirming the initial decision. Subsequently in May we filed a request for rehearing which remains pending.

Under the FERC decision we were required to refund within 30 days. Included in our rehearing request we requested that refunds not be ordered until after a final -- until after the substance of the rehearing request had been addressed. And the FERC did reverse or revise its initial decision, again, just as to refunds. So we will owe refunds, if at all, 30 days after a FERC order on rehearing.

If the rehearing is unsuccessful, we may appeal to the United States Court of Appeals. The timeline would depend most particularly on when the FERC issues a rehearing request, but ultimately could extend to 2016 or beyond.

Parallel to that we're looking at actively developing, I should say, a number of options on the FERC side in terms of other filings. Really can't say more about that right now, but you will have more clarity about that by the time we're together at the end of the next quarter.

Turning to the environmental compliance projects at Big Stone and Neal, we're going to be talking about these for a long time. Both of these important and successful projects. The Neal plant, in which we own a much smaller interest, a coal plant in Northwest Iowa, was substantially completed last year ahead of schedule and it is in service. The Big Stone project is expected to be completed by the April 2016 compliance deadline. And, again, as to both projects, we are pleased with the status.

We've talked a lot about our natural gas reserve opportunities. And this is something -- particularly in the way we are doing it, is really quite unique. In our Montana operation we have an extensive natural gas transmission, storage and gathering system. Adjacent to that system in North Central Montana are extensive traditional gas production assets. So our approach, as many of you know, has been to acquire natural gas production and dedicate that exclusively to serve our customers, manage those assets, and provide gas based on the cost of production.

Our customers saw great value of that, I think, over this last winter when multiple cold weather excursions, to use (inaudible) we've heard a lot over the last couple of weeks, really drove price quite high. And we were able to help buffer that for our customers.

We've made three purchases so far. Certainly we're out examining opportunities now, taking a conservative, but we think appropriate, approach. A goal could be to own up to 50% of our retail supply, plus perhaps another 50% of what we would need to provide fuel at the Dave Gates Generating Station and then at our leased Basin Creek facility. As you know, natural gas production depletes, so we do have to factor in depletion as well. And this is something we're very happy to be able to do and we think provides our customers an awful lot of long-term benefit.

Lots and lots going on in our transmission and distribution systems as we pay attention to the essential infrastructure that serves all of our customers. The Montana Distribution System Infrastructure Project we discussed, every quarter focused on reversing the trend in aging infrastructure, maintaining reliability, managing safety, building in capacity where it's needed, and making our network ready for the deployment of new technology.

It's both a gas and electric project, complicated project in terms of the number of elements, geographically disbursed, disbursed over a period of time. The Bozeman employees I mentioned at the start of the call are very much in the thick of this and they're working very, very hard. We're pleased with the progress we've made so far. Our employees certainly report that they are seeing the results in the field. So we're, again, quite happy with that.

It's a good time to point out during the Board Meeting, Board members made the comment that with the intense focus we've had on the hydro project really for several years, but certainly for the last several months, it was a real reflection on the breadth and the depth of this company, that we were able to move ahead on so many other fronts as well. And I think that was a very wise observation on their part.

Turning to hydro, we are obviously very focused on projects that are consistent with our vision (inaudible) that successfully work through our project screen. The hydro project is one that we think provides great long-term value for our customers, our communities, certainly for our employees and for you, our investors, as well.

One of the really striking things within the Company is -- although we've been in Montana for a number of years, a T&D company primarily, and haven't operated hydros in a number of years, we've got quite a few folks who refer to themselves as the river rats. If you work in a hydro operation you are a river rat. And the experience that they have brought to the project, to due diligence, and will provide to operating these facilities is just extraordinary.

Turning to page 19, a little bit more detail on the process. The overall effort, again, two years really nine months is the clock that the Montana Public Service Commission is working on, culminating in almost two full weeks of hearings. We put on ultimately 18 witnesses, including addressing some issues we hadn't anticipated initially, particularly including transmission access for our Choice customers.

If you have a chance to listen to parts of the hearing, it is available online and I think you will, particularly if you have the opportunity to listen to some of our operational folks -- everyone was outstanding, from whatever perspective -- that you would find yourselves very impressed by John Hines and the operational people who led the due diligence team and will manage this great set of assets.

So post-hearing briefs due August 1 for us, August 15 for the intervenors, and then our final brief on August 25. September 16 would be the final day for the Commission to issue an order. The Commission could extend that deadline if it determines there are extraordinary circumstances.

With a case as large and consequential as this, the Commission really has done an extraordinary job in keeping the schedule really right to the day.

We believe there's obviously a clearly correct answer, but also completely recognize just how fundamentally important this case is to us at NorthWestern, but to our customers and really to the State of Montana. If you listen to the -- or watch the Friday morning hearing, this last Friday morning, I think you'll see the Montana Commission at its very finest and particularly Chairman Bill Gallagher, who did an outstanding job running the hearing and has just been very, very thoughtful about this entire matter.

So if we receive the satisfactory approval from the Montana Commission, we will be seeking authority from the Federal Energy Regulatory Commission to issue securities in connection with the transaction. We anticipate a FERC approval to take 30 to 60 days after the Montana Commission approval.

It's important to note that because of the size of this transaction a key aspect of our request of the Montana Commission is to approve financing. And then the FERC ultimately decided that it needed to see a Montana Commission decision before it would approve financing as well.

There were a series of FERC approvals that we needed. They have now, other than the Section 204 approval for financing, they have now all been received. And that specifically includes the license transfers. Just a half an hour before this call started we received word that we had received the final license transfer approval. Yes, so we're very, very excited about that.

If we receive both MPSC and FERC approvals we plan to close into permanent financing of up to $450 million of debt and up to $400 million of equity, and up to $50 million of free cash flow. If capital market access is limited, we do have the option of closing into the $900 million committed bridge facility with Credit Suisse and Bank of America Merrill Lynch.

Lots of additional information is available on our web page.

And with that, I will stop talking and we look forward to a discussion of your questions.

(Operator Instructions) Paul Ridzon; KeyBanc.

Can you just give an update where the -- not the DSIP, but the TSIP, kind of you have a parallel program for the natural gas system, kind of where the thoughts are on that?

Actually, TSIP refers to transmission. DSIP does include gas and electric elements. What we are doing is really trying to take a comprehensive view of all of our infrastructure assets -- transmission, distribution, substations. And we'll be developing -- we've done a lot of work developing options in terms of priorities, scope of investment, and timing. And we're looking forward to discussing those plans with our commissions probably over the coming six months or so.

Mike Cashell, our Vice President for Transmission, is here. Mike, do you want to add anything to that?

I think that you covered it fully, Bob. The plans are pretty well developed as far as what we intend to do on both the electric and gas sides, including substations. And they do need some more stakeholder involvement and that sort of thing and then also the kind of molding those into our five-year plan as we go through the budget season.

Couple of comments I'd make in addition to that. Between Curt Pohl, Vice President for Distribution, and Mike, the level of coordination between T&D in terms of long-range planning and various key initiatives is great. So I think we are, as a company, more able than ever before to really look at the entire system. And I think that's just obviously in our customers' best interests.

And we do have the ability, again, to stage investments as it makes sense. And we're taking, obviously, hydro with a long-term commitment that we're making to our customers and our focus on transmission and distribution is exactly the same as the long-term commitment on the supply side.

And just on the bad debt, is this a function of people not getting their bills or just not paying them?

No, it's not a function of that. It's a number of things, Paul. One on the things is from a budget/billing perspective we had to do some adjustments to our system for that particular issue, which resulted in our inability to change people's bills in a more timely fashion in terms of adjusting those accordingly to the higher amount of sales, if you will, in the first quarter. That's a portion of it.

But it's a function of corrections we've made to that system here in the third quarter. But we continue to see as people are going past their 90-day arrears, if you will, we're seeing that bad debt even in July. But we did make a correction to the system. We believe that's going to correct that on a going-forward basis and thus we expect to see an improvement in the second half of the year.

One more word on the system itself -- we've talked about this a little bit previously. A number of utilities have been going through these CIS conversions over the last year or so. We like the results we're getting from our system. We like the fact that we've used as much in-house work as we did so the (inaudible) gives us a lot more hands-on experience. And so we're I think further ahead than are many companies that have gone through these conversions. They are always tough. But we like where we are. We like where we're getting.

And to your initial question, so customers affected actually include quite a few, you could say, very high quality customers. So I think we'll manage through it. We're putting the resources on it. But it's going to get probably a little bit [worser] before it gets better.

Another thing I think I'd add, Paul, is two things. One, when we implemented the system it was Labor Day of last year. And as a result of cutting over to that new system we did stop collections for a one-month period. And that does, if you will, push everyone out pretty much from a 30-day perspective. That certainly continues to be an impact, particularly as we went into a very cold season where we had difficulties with disconnects and the like. So that had an impact on this as well.

And I think from, as Bob pointed out, we continue to be focused on this. We continue to -- we'll see some issue potentially in the third quarter, but again, expectation of somewhat of a reversal in -- by the end of the year.

Thank you very much.

(Operator Instructions) Brian Russo; Ladenburg Thalmann.

The David Gates -- if the FERC declines your request for rehearing, would that be the trigger to cause an impairment and a write-off?

We'll be evaluating the need for an impairment on a quarterly basis certainly at that point, but that would not necessarily be a trigger.

Okay. And you just talk a little bit more on other options for the under-collected capacity at David Gates, kind of integrating it into your system or portfolio and did the hydros give you another opportunity to find alternative use for that if, indeed, you'll be under-recovering on the FERC side?

Two points and then Mike or John may want to speak to this as well. First, we are providing a service that we are required, really, as a matter of federal law and policy, to provide. It's an essential service on the system. We face penalties if we don't provide it and if we don't meet the performance standards. So we have no choice but to provide the service. This is the right asset, the best asset with which to provide that service. And that's why I know many of you have been puzzled and frustrated along with us by these, we think, strange FERC outcomes. So we think it's the right asset to provide this necessary service.

Secondly, though, we are -- if we receive a favorable decision from the Montana Commission concerning the hydro project, we are eager to look at ways to optimize an entire system to operate it as efficiently as we can for both our retail and wholesale customers. I think that the Montana Commission had a lot of interest in those opportunities for, again, overall system optimization.

But Mike or John?

I'd just add -- this is John. Just add that with the addition of the hydros we'll have control of over 60% of our power supply in Montana as opposed to relying primarily on power purchase arrangements, which will give us a lot more tools, if you will, to optimize this, including the use of Dave Gates, in alternative ways. It's premature for us to identify those at this point in time, but I can say that we're looking at a variety of different alternatives.

This is Mike Cashell. I would simply say, to Bob's point of the potential for additional filings with the FERC, that -- and emphasize that we are providing a service and our intention is to show FERC in a different way that the customers are providing very important service, whether you call it regulation or something else. And that's kind of the theme around potential future filings.

Okay. And the year-over-year EPS drag on the depletion of the gas reserves this quarter, what was it exactly, embedded in the depreciation in depletion?

Oh, the depreciation depletion total was $3 million. $1.2 million was depletion, for the quarter.

Okay. And we should expect that to recur in the second -- in the third and the fourth quarter as an earnings headwind?

Yes. I would look at it this way, Brian. Think of the gas production itself and the depletion itself to be relatively constant quarter to quarter. But the margin will obviously be higher in the first and fourth quarter. That's when we're selling more throughput, during those quarters than we certainly are during the second and third quarters.

Okay. And is bad debt recoverable in a general rate case?

Yes. I think that I -- from our perspective -- I want to make sure people understand that these are not write-offs. These are increases in reserves. And so at the end of the day it will be -- what is your bad debt expense in a particular test year that you would ultimately ask for from a recovery. As a company we have extremely low bad debt as a percentage of revenues. And our expectation as we continue to make adjustments to the implementation of our new CIS program, we're going to continue to keep that very low level of bad debt expense. And so, again, there's an expectation we're going to get a recovery of these reserves at some point in the future.

And just to reinforce that again, we have in both Montana, South Dakota, Nebraska gas and electric among the lowest bad debt ratios of any utility in the country.

Okay. And the last question -- Brian, based on your comments earlier on the guidance and the percentage of earnings that you've achieved year to date, you're comfortable with the midpoint of your guidance?

Brian, we don't speak to where we sit in the guidance but the percentages I gave you were of the midpoint. The guidance is the range of a total of $2.60 to $2.75.

Okay. Thanks.

David Arcaro; Sidoti & Company.

Could you talk a little bit about what the main drivers are of gross margin growth in the second half of the year this year?

I think, as you'd expect -- when you say gross margin and growth, I mean, I continue to see customer growth and volumetric growth as a result of that. I don't see in terms of any projects coming on line that we'd see incremental margin growth from that. Obviously, you're going to continue to have gas production in the second half of the year that's going to be higher than 2013, because remember we didn't put Bear Paw South into our earnings until December of 2013. Other than that we have seen some improvement in OASIS revenues for the year. Those are the things, David, that are jumping out at me at this point in time.

Got it. Thanks. Also had a question about timing of financing for the hydro acquisition -- wondering if you could help me understand the timeline. So, if you were to get approval from the Montana Commission mid-September, that would start the countdown for FERC approval. But would you then tap into the bridge, basically bridge loans, mid-September? Or would you wait for FERC approval before doing any kind of financing?

That's a good question, David. I think once we receive MPSC approval, there's expectation of 30 to 60 days from FERC. And the way that the way the PSC has written is we're required to close within 20 business days after we get all of our approvals. So we don't have to draw on the bridge financing. Our expectation is we hope to receive MPSC approval and then within 30, 60 days when we would hope to receive the FERC approval we would quickly upon receiving those get to the capital markets. And we're allotted some time to do that, as I pointed out.

And so, to your point of mid-September the hope is we could do something after 30 days, maybe late October, if you will. But potentially could go into November as well, in terms of coming to the capital markets.

We are very eager to get out just in a New York minute as quickly as we can. Right now we could deliver long-term, very low-cost debt. Brian has a little votive candle and picture of Janet Yellen on his desk. We want to get out and do that. And we'd be able to provide an overall ROR probably lower than anything the Montana Commission has seen. So the quality of the assets, the attractiveness of financing right now, locking in long-term debt while these plants depreciate out, it's just a wonderful time to be doing what we think is a great deal.

Thanks.

I should have said a Montana minute.

Bob, question for you actually regarding the hydro hearings. You had mentioned during the hearing, or you described it as a little bit acrimonious. Or that might have been a quote from someone else. But I was wondering what your thoughts are about how you might be able to improve the communications or improve the process between NorthWestern and the other parties when it comes to hearings like this and processes like this.

Actually -- well if I could go back to the previous question first, another reason we're eager to get out and wrap up the financing is because our operational folks that I mentioned earlier are basically ready to go as of August 1. So, as soon as we get the deal put together, if we do, we'll be ready to start operating these plants, dedicated to serve our customers.

In terms of process, it was, in this case, extraordinarily thorough, reams and reams of information. I think every stone was looked under. And that's totally appropriate. We had so many working very, very hard to provide all the information to get the job done.

Quite a concern I had and I tried to raise in a respectful way on the second to the last day of the hearing just has to do with what I think is the key, the important role in Montana and the Montana regulatory process, of the Montana Consumer Council. It's a constitutional body, plays an important role representing the public interest, representing customers. As you hear us talk about constantly, we really do put customers and the public interest first and talk about that alignment of interests.

We've tried to reach out to -- and actually often are able to work very well with the Consumer Council on a range of things, including off and on, for example, our gas production acquisition. We need to have a good relationship there and there needs to be respect among ourselves and them, but also the witnesses.

And, honestly, we had some -- I'll be very direct -- we had some real concerns about positions that one of the Consumer Council witnesses took and about statements that were made during the hearing. And, honestly, there's almost an expectation that the Consumer Council next witnesses will be speaking factually and a real respect for the Consumer Council positions in Montana. So it's important that they be factual, be constructive, and that we be able to work with one another.

So I did point that out during the hearing. I actually pointed it out in my rebuttal testimony as well. We respect the Consumer Council as an institution, certainly respect the individual who heads the Consumer Council. But it's just so important for us to be able to work together.

And in this case, again, because of the size of the transaction, it's important for Montana. And the risk that was associated with timing I think was another real concern for us. We, as a matter of law, needed the Montana Commission's approval before financing and then found out that after we needed the Montana Commission's approval as a prerequisite for FERC approval, too. Well, during that time the market did not move, debt prices did not go up. But they certainly could have and it would have been a tragedy if we had lost our ability to finance on those attractive terms.

So it's something -- there's supposed to be some institutional tension, but it's something we sure as a company are committed to addressing. And sometimes it's best to address that outside of a contested case.

Great. Thanks for that. That's all I had.

Jonathan Reeder; Wells Fargo.

Just a couple follow-ups. Were there any issues raised during the hearings that you hadn't anticipated? Or was everything pretty much in line with your expectations?

I'd say two points. We knew that cost of capital would be an issue. Brian, in particular, did a nice job addressing that in our initial testimony. We did bring in an independent cost-of-capital witness in rebuttal.

And then, secondly, the transmission-related issues. Obviously, there is concern for a customer who's mainly industrial/institutional that takes service now from PPL as to whether over our transmission system they would continue to have access. And Mike Cashell ended up providing live testimony and we think we did a good job addressing those questions.

I think we were all surprised by some of the proposals that Consumer Council's independent expert, Dr. Wilson, offered in their round of testimony. And that, again, led to some of the discussion back and forth.

A third issue, some of the concerns around Kerr, which is, as those of you who are following it know, is a facility that under condition and it's sort of license has the potential to revert to the Confederated Tribes next year. And there was a lot more clarity provided around that process after we had entered into our purchase and sale agreement. And we had to -- we actually really stepped up and worked through that issue. We got pretty well -- John, anything else to --

I guess one issue that I thought was a little bit surprising when you're acquiring an asset that's going to be around for probably another century was the extreme focus on very short-term comparison between these assets and the market.

And that really is foundational. We take seriously -- we have an obligation under Montana law, one, to look long term and, two, to assess risk. And we think we did that very well.

Okay. And so now that you have the hearings and kind of the public comment opportunities in the rear-view, do you feel like the court of public opinion has been swayed at all? Or, you've talked about a lot of support within Montana from not just customers but also legislatures and everyone else up and down the line. Is that still consistent?

I think so. I think -- and, again, credit to the Commission for going out and holding almost 20 public hearings. And that was a great educational opportunity in a lot of different ways. The Commission, the Consumer Council, and we had the opportunity to educate customers and citizens. But it was an opportunity, then, for the Commission to -- and for the Commissioners to educate themselves about what the public was thinking.

As a company, we really do emphasize talking, and we think pretty substantively, with our customers and community leaders. So we're always doing that. And certainly on something as important as this that was our goal.

Okay. And then last question -- is reaching a settlement on the hydro deal, is that even a possibility or anything you're working towards, or now that we've kind of seen the opinions and everything we should expect fully litigated?

The Chairman, Chairman Gallagher, made a statement. It's a matter of public record. Friday afternoon, after the hearing closed, he testified to the legislative interim committee, a legislative interim committee on telecommunications and energy. And reported on the hearing generally and made the statement that NorthWestern Energy had started at around $128 million and through a number of adjustments came down to $117 million. And the Consumer Council was at $114 million so he thought it was reasonable to expect a settlement, and that that would then allow the Commission to issue an order in early September.

So from our side -- and government negotiations are confidential, but we have been actually working, trying to reach out, since March and April and we think it's a sensible thing to do. The way to think about it, and we've talked about this in some detail at the hearing -- $900 million purchase price, we will write a check. We hope we have the opportunity to write that check for $900 million.

After announcing this transaction then we got clarity on the terms of the arbitration results between PPL and the Confederated Salish and Kootenai Tribes. As a result of that, then we know that essentially the price for Kerr to us is $30 million. So that will get sorted out after about a year at the time of the transfer.

So we were able to then move from $900 million, $870 million rate base amount by basically forgoing either return on or return of Kerr during the time that we operated it. There was some discussion about various other specific adjustments. Kind of to walk through those at a very high level, we agreed to take for the first year PPL's tax obligation, which is lower, we expect, than ours will be as a retail utility.

We spoke -- we also then agreed to move from 40-year to 50-year depreciation, which actually -- so there's a pretty significant net present value. I want to say -- about $16 million?

[$4.4 million] (multiple speakers) --

-- in the first year to our customers and, again, over the life of very significant net present value.

There were concerns about capital forecasts. We're very comfortable with the first six years of capital forecasts. And although Montana has an historical test year we were willing to commit to live within those capital forecasts, again, based on the experience of our due diligence and the quality of their work.

And then fundamentally focusing on capital structure, cost of debt, cost of equity. As you know, we are willing to take on just a little bit more leverage in the capital structure than a lot of companies are.

And, again, the amazing thing is that, depending on if the Commission does print out a positive order and if we are able to go out and finance debt long term, the stability we could provide customers for this set of assets really is remarkable.

Brian, John -- add?

No. I think, Bob, you've pointed out the, again, the $11 million in revenue requirements that the Company offered up during the case and sort of our ability to reduce costs. For instance, the reduction of debt costs would be one of those.

But, again, I think to your point, we're trying to do what we can to ultimately move this to the right outcome.

Just a follow-up on that. So, Bob, you mentioned the MCC. I guess their revenue requirement was at $114 million. Was that in their pre-trial testimony on the assumption that the deal, I guess, kind of gets approved? Or where is that kind of coming from?

There are three pieces and it gets complicated for -- at least for a simple guy like me. They had two witnesses, Dr. Wilson and then Mr. Al Clark. Mr. Clark was the accounting witness, you could say. He proposed a couple of adjustments -- depreciation life and then the return on and of that we accepted -- Kendall Kliewer accepted in his rebuttal testimony. And then that moves to the $114 million. In addition, he proposed a generational inequity, not iniquity, but inequity, of adjustment that had some discussion at the hearing.

And then what was very troubling for us were a series of rate-based adjustments, if you will, that Dr. Wilson proposed. And those are things that we just had a hard time understanding, on one level and, again, I think from an accounting perspective would have caused huge, huge concerns.

So what we asked for ultimately, again, after we got the clarity around Kerr, was $870 million in rate base, and that's based on, obviously, our best effort to reach an appropriate price with a seller who was under no obligation to sell at all and certainly didn't need to sell to us for a set of assets that we think provides a whole range of long-term values.

Okay. So the $114 million is based on an $870 million rate base and excludes kind of those more extreme adjustments that the witnesses threw out?

That's fair.

Okay. All right. Well, we'll be watching this closely and good luck getting it across the finish line.

Maury May; Wellington Shields.

Just another quick question on Kerr. I think I understand the issue. But if all goes right, you're going to own this asset for about a year and it produces about 1 million megawatt hours per year. And so, if there is any profit on it, does that just get returned to rate payers as credits?

We would, we hope, have Kerr for about nine months. And, yes, that would flow back as credits.

Okay. Okay. And my second question really is on dividend policy. Can you review your dividend policy and payout ratio?

Sure. Our payout ratio is 60% to 70%, Maury. But we're at the low end of that ratio and we've publicly noted that for several years now, that we plan to be at the low end of that percentage as long as we've got large capital commitments in front of us. If there's some point for whatever reason rate base growth percentages -- that that rate of growth would slow, our expectation is we'd have more cash to be able to pay a larger dividend, we'd probably move up within that range. But we're very comfortable being at the low end of our stated 60% to 70% range at this time.

Okay. Now, in recent years you have increased the dividend in the first quarter of each year. And did you do that -- do you apply the payout ratio to the prospective year or the previous year?

We look at what our plans would be -- we come out with our dividend usually in the line of time we come out with our guidance for the upcoming year. So it is on a perspective basis.

Okay. Great. Thank you very much.

(Operator Instructions) Paul Ridzon; KeyBanc.

Along the lines that Brian has a pinup poster of Janet Yellen in his office, have you put any Treasury locks [in]?

That's a great question, Paul. And what we've done in discussions with Commission staff about this issue some time ago -- the concern is when you put in place a Treasury lock or even consider doing a forward, if you will, on your stock, it certainly gives the perception that you're going to get this thing approved. And we certainly didn't want to get ahead of our skis in that regard.

I have to tell you, in hindsight it certainly was a wise decision. If we would have locked in interest rates at the time that we had filed for this particular case, we would have locked in too high a cost, if you will, from both a debt perspective and of course our stock price is up since that time as well.

I think I'd put it in this context. If, in fact, we were to have a settlement with the MCC and comfort in terms that this transaction could close, and comfort based on feedback we received from the Commission about liking us to lock in, we would certainly want to do a Treasury lock at that point in time. But until there's clarity around that, we just feel uncomfortable doing it.

And in the meantime, I'll continue to monitor what Ms. Yellen's doing.

We're lighting a lot of candles. And I'm going to be in so much trouble for sharing that secret of Brian's as soon as we're off this call.

And when we think about the permanent financing I assume we should be thinking about $870 million, not $900 million. And I don't know if you'll just carry the $30 million on a revolver of some sort. Or is that the right way to think about it?

Paul, you've nailed it. Think of it this way -- up to $400 million of equity associated with the $870 million. Think of $450 million of debt on the $870 million, and then $20 million of free cash flows for the total, if you will, to get to $870 million.

On the $30 million associated with Kerr, as Bob pointed out, it's an asset we're going to own for nine months or so. Our thought process is that's a short-term asset that we'll own. Well finance that, if you will, with a draw on our revolving credit facility.

Is there any thought about, in light of the fact that there's more gas users out there, just coming to the capital markets once and maybe clean [out]some potential equity you might need?

That's a fair question, Paul. I think we'd like to keep our financing [rates] here, particularly since the hydro transaction is such a significant transaction, we'd like to kind of keep that totally tied to that transaction. Obviously there are other tools if in fact -- just we understand there's opportunities on the gas reserves of a transaction that size. We've used a dribble program in the past for small equity needs. That may be a tool we would consider again in the future.

And that makes sense. Thanks again.

We'll now move back to Brian Russo with Ladenburg Thalmann

I just want to clarify, in the 10-Q it says that average first-year rate base is $839 million, down from $866 million, which you are discussing an $870 million.

I think one of the issues there you have to take into consideration the impact of Kerr and then deferred taxes have an impact on that amount as well.

Okay. So the $839 million is the number we should use.

Yes.

Okay, great. Thank you.

And it appears there are no further questions.

Great. Well, again, thank you all for your interest and support over the quarter. I would hope we'll be seeing some of you over the next several months. And I think our next quarterly call will be from Mitchell, South Dakota in October. And that concludes the call.

And once again, that does conclude today's conference. And we thank you all for your participation.