Good day, ladies and gentlemen, and welcome to the NorthWestern Energy Corporation Third Quarter 2012 Financial Results Conference Call. [Operator Instructions] At this time for opening remarks, I'd like to turn the conference over to Mr. Dan Rausch.

Good afternoon, and welcome to NorthWestern Corporation's financial results conference call and webcast for the quarter ended September 30, 2012. NorthWestern's results have been released and that release is available on our website at www.northwesternenergy.com. We also filed our 10-Q after the market closed yesterday. Joining us today on the call are Bob Rowe, President and CEO; Brian Bird, Chief Financial Officer; Kendall Kliewer, Controller; Mike Cashell, Vice President of Transmission; Heather Grahame, General Counsel. This presentation contains forward-looking statements within the meaning of the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995. These statements are based upon our current expectations and speak only as of this date. Our actual results may differ materially and adversely, from those expressed in our forward-looking statements, as a result of various factors and uncertainties, including those in our Annual Report on Form 10-K, recent and forthcoming 10-Qs, recent Form 8-Ks and other filings with the SEC. We undertake no obligation to revise or publicly update our forward-looking statements for any reason. Following this presentation, those who are joining us by teleconference will be able to ask questions. A replay of today's call will be available beginning 6:00 p.m. Eastern time today, through November 23, 2012. To access the replay, dial 888-203-1112 and then access code 3754155. That number again is 888-203-1112 and then the code 3754155. A replay of today's webcast is also available on our website. With that, I'll turn it over to President and CEO, Bob Rowe.

Good afternoon, everybody. Thank you for joining us. Today we're joining you from our service center in Aberdeen, South Dakota. We just completed a board meeting this morning. As we always do, we had a community meeting last night and a good employee meeting this morning. The board meeting was over and we got to go out and visit our new gas peaker plant, and I'll come back and talk about that. Those of you who follow the company I think are aware that our entire Board of Directors are certified fellows by NACD, the National Association of Corporate Directors, and they and the entire executive team will be staying together tomorrow to renew their certifications through a day of training. I'll summarize the quarter's ending activities. First, we are obviously very disappointed with the quarterly results of a loss of $3.8 million or $0.10 a share. As most of you know, we recorded a quarterly loss as a result of 2 previously disclosed items. First, our decision to shelve the Mountain States Transmission Intertie project, MSTI; and second, the unfavorable, although non-binding decision of a Federal Energy Regulatory Commission administrative law judge regarding the allocation of cost at our Dave Gates Generation Station. I'll come back and talk about that of course as well. However, very importantly, our core business does continue to perform to expectations and we will discuss that in more detail. On several more positive notes, in August we completed the purchase of a natural gas production interest in northern Montana's Bear Paw Basin for approximately $19.5 million. The construction of the Spion Kop Wind Project in Montana is now nearly complete and we plan to close on that project in the near future, and place it into commercial operation in the fourth quarter this year. Also related to electric supply, as I mentioned we continued construction on the 60 megawatt peaking facility located here in Aberdeen, South Dakota, and we expect to achieve commercial operation before the 2013 summer season. On September 30, we filed with the Montana Public Service Commission a request to adjust natural gas rates by $15.7 million to account for investments in our natural gas transmission, distribution and storage systems, and to implement pipeline integrity and infrastructure improvements as well as cover increased expenses. Last, the Board of Directors declared a common stock dividend of $0.37 per share, payable on December 30, 2012, to common shareholders of record as of December 14. Now, Brian Bird will discuss our third quarter '12 financial results in more detail.

Thanks, Bob. As Bob said, we reported a net loss of $3.8 million or $0.10 per fully diluted share for the quarter ended September 30, 2012, compared with consolidated net income of $14.9 million or $0.41 per fully diluted share for the quarter ended September 30, 2011. Summing up the quarter, there were 3 primary drivers: first, we deferred approximately $11.4 million in revenue as a result of a non-binding initial decision by a FERC administrative law judge related to DGGS, which Bob will talk about more in a few moments; and secondly, we took a charge of approximately $24 million for the impairment of substantially all of the capitalized preliminary survey investigative cost associated with MSTI; and third, those unfavorable variances were partially offset by warmer summer weather, adding to our electric volumes in all our service territories. Our fully diluted EPS in the third quarter of 2012 again was a loss of $0.10 per share, and after deducting what we calculate to be about $0.06 per share benefit for the warmer than normal summer weather, and then adding back $0.12 a share for the effect of the 2011 portion of the FERC ALJ initial decision and adding back another $0.40 per share for the $24 million negative effect on income from impairing the MSTI costs that were capitalized. From that we calculate a more normalized earnings on a non-GAAP fully diluted EPS basis for the third quarter of 2012 to be about $0.36 per share. That is lower than the same period of 2011, due primarily to the effect of the FERC ALJ initial decision that related to 2012, estimated to be about $0.08 per share. Now I will talk about our earnings outlook for the remainder of 2012. For the full year 2012, we are estimating our…

Thank you, Brian. I'll start by providing an update on the Dave Gates Generating Station or DGGS cost allocation issue which as you know, caused the reserve of $11.4 million. A hearing was held in June of this year before a FERC administrative law judge or ALJ to consider our proposed our allocation methodology which was challenged by several other engineers. Our methodology proposed to allocate about 20% of the DGGS revenue requirement to our FERC jurisdictional customers, and it is consistent with past practice of allocating contracted cost for similar service. The ALJ’s initial decision issued in late September included that NorthWestern should recover only about 4.4% of the revenue requirement from our FERC jurisdictional customers, and this result, although non-binding, really was shocking and in our view is entirely inconsistent with FERC’s past treatment with similar cost to service. The initial decision would have the effect, if it's allowed to stand, of either shifting cost to other customers or allowing costs simply to fall between the cracks. That obviously is not acceptable to us. The FERC is not obliged to follow any of the findings from the initial decision and can accept or reject the initial decision, either in whole or in part. With respect to the FERC ALJ decision, we have now filed our appeal to the full FERC and again, were the decision allowed to stand, we would be earning actually a negative return on the portion of the plant that was built, and that is still needed to provide reliability service to FERC jurisdictional customers, also to meet FERC policy goals for network reliability and also to integrate variable energy resources, so called VERs like wind. And again, this is an important policy priority of the FERC. So we filed our opposing briefs on October…

[Operator Instructions] We'll take our first question come from Paul Ridzon with KeyBanc.

I didn't hear you talk about the Collector system, just wondering if you can give an update on that. And then, I guess, my second question would be whether, just kind of precedents there are with regards to the FERC's decision around the Dave Gates Station?

With regard to Collector, first of all, there are no, we've been expensing Collector. We think about that as really being complementary to MSTI. So the viability of Collector in the larger sense really is associated with the MSTI project. But at this point, we're not actively developing the entire Collector system. If it some point in the future there is demand for a MSTI type project, that would affect Collector as well. Important, in making that statement, though, is to, as I mentioned, keep in mind that our transmission department is responding to service requests for transmission service from project developers, and these incremental projects are in a sense building portions of Collector by kind of piece-by-piece. But in terms of a grand Collector Project, that's very much associated with MSTI. In terms of precedent for DGGS, and you know us well, and you know our persistent needs, we are unique in being a utility that’s not part of an organized market and that, oh by the way, went through supply divesture. So it does not have a fleet of resources to provide these particular services. So the facts on the ground are in that sense unprecedented. On the other hand, in looking to prior FERC decisions, we believed we were on good ground, first of all in that they consistently approved the contracts that we used to obtain this service. And as part of that process, they've noted favorably our plans to build a resource like this. But one of the challenges of a hearing before the FERC in Washington DC, I think, to be very direct, one of the obligations of the FERC, making decisions about our utility, in this case in Montana, is to understand those facts on the ground in this particular part of the country. And very clearly, the ALJ decision failed that test.

I saw in the release that you had committed $0.06 of it to volumes and you also stripped out $0.06 on the weather. Was weather flat with last year? I noticed degree days were up quite a bit.

Yes. I think what -- We looked at it both versus prior year and versus normal, in this case, would be $0.06 for the quarter. And even though there is, seems to be quite a few cooling degree days during the third quarter, it really had very little impact on the Montana business.

And lastly on, there’s a rumor that PPA is potentially looking to divest Colstrip. Just wondering if you could look at that and how you would gauge the relative attractiveness of those assets.

Good try, Paul. But as always we don't comment on rumors.

We'll take our next question from Michael Klein with Sidoti & Company.

You said that the cost allocation was consistent with some previous projects. Can you just provide a little more color on maybe when, what some of the projects were and the most recent example of that? Was that last year or was it 10 years ago?

What I'm referring to specifically are the contracts that we had enter into on the market to provide this identical service. And as you heard, our Vice President for Transmission, Mike Cashell, is here and he can provide some more detail about the specific contracts.

What I'd add to Bob's comments is that the contracts that, we believe, had this precedent firmly within them, were entered in the 2008 and 2009 timeframe, so very much recent precedents specific to our situation. The contracts were approved with an allocation methodology that we carried forward to the allocation that was suggested as part of our rate case for DGGS.

Now throughout the process of building the Dave Gates Station and communicating with the FERC, did the allocation of cost ever come up or was it just assumed and the discussions or were just mainly focused on the prudency and absolute cost?

There are 2 different processes. I could, I asked Mike to provide some color, because he was in these meetings. On the state side, as you know, there is formal pre-approval process and that really is one strength of the state regulatory process. And that included informational meetings, obviously discussion before the pre-approval request was filed. On the federal side, there is not a pre-approval process for the project, as in advance of undertaking the project, and obviously, before a filing was made at the FERC, which then brought down the ex parte curtain, we did have extensive meetings with policy staff, with each of the FERC Commissioner's offices, Commissioners and their staffs, talked about the need for the project, the design of the project. And the fact that it was intended to meet both our state jurisdictional and our FERC jurisdictional obligations.

The only thing I would add to that is that we, in the pre-filing conferences with the FERC and their policy staff, we fully disclosed the methodology by which we intended to allocate the costs.

And lastly, just switching gears to DSIP a little bit. Strategically, how are you thinking about DSIP in terms of when the spend is going to be the heaviest, and when we can start to see the incremental benefit in rates and earnings?

You can think of it is as a 7-year project. And again, this is Montana specific in both gas and electric. A 2 year ramp up with primarily expenses associated. Those expenses then are covered under the accounting order that I mentioned, and then 5 years of full production. So we are including the 2 year ramp up period right now and then converting to full production starting at the first of the year. I mentioned we filed a gas case just in the last few weeks, and that gas case includes significant capital. A lot of that capital is associated with compliance with Federal requirements, but we do start to see some DSIP-related capital there as well. And then going forward, as we file our rate cases on the electric side in Montana, we will be folding in the capital there. We evaluate every year whether or not it's appropriate to file a case in each of our jurisdictions. So as we do that, then you'll start to see the effect. Parenthetically, from my perspective, it's exciting to see just what a great job the DSIP management team is doing and what a great job our employees are doing with implementation. People are very focused, very busy, and fundamentally committed to this project and to do doing the right thing. Brian, anything to add there?

Yes, I think to specifically in terms of timing, I think because of the large lift and capital spend in '13, it be likely that 2013 would be a test year, to start capturing the larger spend. But as Bob pointed out, we'll be looking at it each and every year to determine how soon we’d come in. And if 2013 is a test year, Mike, I think you know in terms of the timetable, by the time you file the, the 4 year effective, receiving the benefit of any rate cases associated with that would be in 2015. We’d see a partial year in 2014 if 2013 was a test year; that makes sense.

We'll go next to Brian Russo with Ladenburg Thalmann.

I had the opportunity to read through the briefs on the ALJ decision. And I was just hoping in your own words, could you just discuss why you believe the ALJ understated the capacity required to service the wholesale customer? I think you proposed 21 megawatts, ALJ proposed 7? And then also why you believe the ALJ overstated the capability, and I think you proposed 105 megawatt but the ALJ findings were 150 megawatts?

Mike did a very nice job discussing this just earlier today, so I'm going to turn it to him.

Well, 2 reasons for the capacity needed to serve the wholesale customers. First of all, the ALJ found that NorthWestern was not entitled to receive compensation for a type of service called regulation down. It's a portion of the service that's necessary to provide the full regulation requirement for our customers. We provide regulation down and regulation up. Of course, we believe that that's not accurate and we have strong FERC policy, namely in most recent third quarters, regarding the integration of variable energy resources into balancing authorities to support our position, is our view. By the way, our briefs explaining this was filed Monday, the 22nd, and is available publicly as well. It explains that point pretty well. Secondly, the numerator was also reduced by diversity. By diversity I mean, the diversity between wind generation and load. And a recent order from the FERC also suggests that, because wind generation and traditional load sometimes offsets the need for at least some regulation between the 2 of them, that those diversity benefits should be shared among all customers. We believe that's inaccurate as well in our particular case, because all of the regulation that's necessary for integration of wind on NorthWestern’s system is being paid for by retail customers. So we believe that that should not be a shared benefit, rather it should be allocated to retail customers. That takes care of the reason for the ALJ's reduction to our numerator and our belief why the numerator should remain at 60 megawatts. On the idea of the capacity or the denominator being increased from 105 megawatt to 150 megawatts, we believe that the judge has created a mismatch now between the amount of capacity that's necessary to serve these customers, 105 megawatts, and the nameplate capacity of the generators that we use to serve that need of 150 megawatts. Dave Gates Generation Station has 3 generators, each 50 megawatts. But the third machine is used to backup the other 2. So it's the typical redundancy that's built into a transmission system, and also into ancillary services, that's necessary to make sure that you have enough capacity to meet the need anytime. So we believe that we have a strong argument on that as well. And again, those points are all pretty well made in our brief on exceptions.

And just to reinforce what Mike said, those are 3 drivers. Reg down is paid service that, if one owns a large fleet you can provide, just really kind of offer that capacity. That's not the case for our company in our market. In terms of the design of the plant including the 3 units, the third unit was provided and was built specifically to provide this service to ensure the reliability of the unit. As everyone knows, and certainly the FERC knows, reliability has a certain price, and if only 2 units were required to achieve what DDGS was designed to do, the plant would have been built with 2 units. And by definition if we are then somehow committing that, the third unit to some other use, it's not available to do what it was built to do.

Just one last one in that, we had regulation down cost in our contracts, and again precedent, we pass those contract cost of regulation down through to our customers prior to the DDGS facility, so we structured the same way as we had done in previous contracts.

And then just on your 2012 guidance of 230 to 240, are there any non-recurring tax related gains or losses that we should be aware about when thinking about 2013?

If there were any non-recurring type things, we would have excluded that from guidance anyway, but there are no non-recurring type tax items.

I think I read in your Q that your DSM loss revenue request is $5.7 million, and you've collected $3.3 million, and the balance is currently under MPSC review, is that correct?

Yes.

So there is a possibility for an extra $2.4 million if the MPSC rules in your favor?

If in fact they rule in our favor that's correct.

And just getting back to the contract, the 200 megawatt Colstrip contract that rolls off in mid-14. I'm just trying to get a sense of what the evaluation process is and what the timing of it is. If you’re considering building something as proposed in the IRP, wouldn't you have to the start fairly soon on the permitting, in order to get that time to the contract role off, or would you be interested in signing a short term PPA to bridge the gap?

We've talked about a few things. Certainly contracts are an option. And we've talked about doing some what would effectively be project banking, so that we can short the lead time when a project might be needed. That's -- we look at the situation as providing a number of options.

I think I'd put it in this context: We have talked about, in IRPs, something like a 2018 time period for building anything. And I think, noted in there, obviously we would have to enter into shorter term contracts to bridges during the construction standpoint. So obviously if you get in a situation where you'd enter into PPA's, you're going to need to start doing that sometime in mid-13 in order to execute something, by '14 to take that power up.

And I guess if, hypothetically speaking, you were to acquire PPO's interest, that would obviously need pre-approval by the Montana Commission, and would you have to do any sort of RFP process to kind of identify whether that's the least cost option?

Generally speaking any major generation acquisition we would submit for pre-approval.

We'll go next to Chris Ellinghaus with Williams Capital.

Can you just explain the difference between the $11.4 million DDGS reserve and $9.6 million which shows up as the pre-tax amount on the third page?

The difference between those 2 numbers is some benefits of bonus depreciation; that's the really difference between the 2 that showed up this year.

And as far as DDGS goes, if you were to believe that you could be successful in recovering the discrepancy between FERC and the local jurisdiction from the Montana Commission, can one presume that you'd have to go through the entire appeals process and get to 2015 before you had even approach that concept?

In terms of going back through the Montana Commission, is that the question?

Right.

I don't want to actually cross that bridge at all. Our view is that this is appropriately recovered through the federal jurisdiction, and that is where we're focusing. I'm not inclined at this point to speculate on what we might do. And again, it's notable, I think, that the Montana Commission and we appear to be fully aligned on that point.

And lastly, with the cancellation of the Collector System, I'm just kind of curious: What is taking place in Montana? I know it was a fairly significant policy objective to develop wind in the state. What's generally going in Montana as far as wind development goes?

Actually, Mike Cashell, head of the Transmission Department has probably the most visibility into the wind market. So I'm going to ask him to provide some color. Generally, first of all, our Transmission Department is very busy, both gas and electric transmission, I should say, meeting the needs of our on-network customers. So we have some significant transmission projects underway right now. In addition to that there certainly does continue to be some fairly significant interest in interconnection onto our system by some larger and some smaller parties. There is, obviously, uncertainty -- a couple kinds of uncertainty around what the federal policy for renewable incentives will be. Also probably some near-term uncertainty about what the requirements for participating in the California market will be. And Mike has, I think, the most direct exposure there. Mike?

Well, actually, Bob, you did a nice job of explaining in general terms what's going on our system. I will say that we still have about 2,800 megawatts of generation interconnection requests on our system as well as transmission service requests on our system from wholesale customers that we're working through, some of which would require significant transmission upgrades on our system. So we still work through process. Obviously, it's dropped off some in the last handful of years. We at one point had over 7,000 megawatts of generation in our connection requests on our system. So it has fallen off with the general trends in the marketplace. We have built facilities, though, for these wholesale customers, and last year we built 5 different substations of various sizes for different project developers. So the process continues and it's not as organized or as large as the Collector System that we had envisioned but we are still building transmission for wholesale customers. And as Bob pointed out, we're still making significant investment on our system every year for our native customers to the tune of and upwards of 30. And next year we're planning over $49 million worth of investment for our network system.

[Operator Instructions] We'll go to next to Jonathan Reeder with Wells Fargo Securities.

Could you just clarify if the ongoing annual impact from this decision and your decision to defer the revenues as $0.12? I mean, is that how we should view it, as what's kind of being stripped out of 2012?

Correct.

And then, should we also view the fact that you guys are stripping it out at all, as your level of confidence in the appeal process to FERC, or what kind of went into that decision process of actually stripping it out since you haven't got a final decision?

Yes, I think that's a fair question, but we're trying to be consistent with the other decision to make adjustment in our financials this year and we will. And on a going forward basis, we're being consistent there until we learn more from FERC decision as we move forward.

But I mean we should interpret that at all, you not believing that the FERC will overturn the ALJ's initial decision?

You should just draw the conclusion. We're being consistent what we've recorded today. You shouldn’t be drawing any conclusion in terms of our optimism.

And then Brian, on 230 to 240 range, I just want to make sure I'm interpreting this correctly. Does that exclude essentially the $0.08 negative year-to-date weather impact, where just on the actual way the weather has played out thus far, it should be 222 to 232?

I think what you should do is that 230 to 242 takes in consideration backing out both the negative weather we had in the first 2 quarters and the positive weather in the third quarter. That's taking out all the weather, if you will, that we see above and beyond normal for the full year.

Right, so essentially you're saying, 230 to 240 if you have normal weather for the entire year, even the fourth quarter.

Correct.

And then I guess last question, did you indicate that the Montana electric rate case you were contemplating, I guess, at 2014 filing with the '13 test year or is the door still open to potentially filing something in '13?

I think, yes, the door is still open for that. As Bob pointed out, we'll evaluate that every year if it make sense to come in sooner than that, we would do that. My point about talking about the 2013 test year is this is a significant amount of capital investment in that particular year. But we will evaluate each and every year, much like we did with the Montana gas case and the filing issue based upon our 2011 test year.

We'll go to Andy Levi with Avon Capital.

When are you guys going to give guidance for '13?

What we do is at EEI we give drivers, drivers in terms of our thoughts on '13, but we don't give actual guidance until after we release our yearend earnings, and so it would be in mid February.

And I guess you mentioned, you're still looking for gas assets, right, is that correct?

Correct.

And if I heard correctly -- I'm sorry, I was kind of off and on. But ultimately you guess will wait until the end of the regulatory process on the first acquisition to make any future acquisitions?

We do expect a decision from the Montana Commission before the end of year and that would be certainly important in making any decision. But I wouldn't want to say is that a bright line that we would wait. Obviously, we're actively looking at the market.

And when do you think you'll complete your -- 50% of your target?

I can't give you a specific date; that depends on the availability of assets at a price that we think make sense for our customers. But again, the market right now is very, very good and we are certainly actively looking at opportunities. I think you're aware of this, but there may be some on the call who are not. First of all, our interest is in the traditional gas properties that are renown, that have fairly stable and long asset lives. And the reason we're focusing on Montana is that there in our Montana operation we have an extensive transmission, gathering and storage system that, at the Northern end, is adjacent to just the kind of gas fields that I am describing.

Just back on the potential PPL assets, which I know you can't really comment on. But just to understand, if for some reason, if they were for sale and you were successful and you bought a portion or all of them or whatever the case may be, the regulatory process which you kind of briefly talked about -- I would assume that if you kind of structured a deal it would be subject to Commission approval, right?

We would take in anything to the Montana Commission. Obviously, the Commission will have to approve to include anything in rate base. And our focus is on assets that make sense to serve our Montana customers.

So any acquisition that you would make, again, just to understand, would be subject to approval by the Commission, and that would probably be structured within the deal. So unlikely you would get stuck with some type of merchant facility.

Correct. And that's just a general comment that would apply to any electric supply acquisition.

We have no further questions at this time.

And again, thank you for your continued interest in the company. I look forward to visiting with many of you next quarter and probably quite a few of you at EEI here in a few weeks. Thank you.

Ladies and gentlemen, this does conclude today's conference. We appreciate your participation. And ladies and gentlemen, if you would like to listen to a replay of today's call, it will be available from 6:00 p.m. October 24, 2012, to 6:00 p.m. November 23, 2012, by dialing toll free 1 (888) 203-1112 or the toll number (719) 457-0820 and entering the access code 3754155. Thank you.