NorthWestern Energy Group Inc (NWE) 2012 Q3 法說會逐字稿

Good day ladies and gentlemen, and welcome to the NorthWestern Energy Corporation Third Quarter 2012 financial results conference call. Today's call is being recorded. At this time for opening remarks I would like to turn the conference over to Mr. Dan Rausch, please go ahead, sir.

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. 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 listed 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 of us joining by teleconference will be able to ask questions. A replay of today's call will be available beginning at 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 is 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. When the board meeting was over, 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 certification through a day of training.

I'll summarize the quarter's ending activities. First, we're 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 two 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 costs 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 natural gas production interests 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 continue 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 of this year to common shareholders of record as of December 14. Now, Brian Bird will discuss our Third Quarter '12 financial results in more detail. Brian?

All right, 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 three 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 and investigative costs 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'll talk about our earnings outlook for the remainder of 2012.

For the full year 2012, we are estimating our ongoing adjusted fully-diluted earnings per share 2012 to be in the range of $2.30 to $2.40 per fully diluted share. As you can see from our press release, our GAAP earnings would be around $1.80 to $1.90 per share. Basically the two items, the MSTI and the FERC ALJ item totaling about $0.52 per share account for nearly all that difference.

As you can see from our disclosures, there are a couple other normalization items for the first three quarters of 2012 that essentially offset one another.

Our primary assumptions for the remainder of 2012 are our effective tax rate of our ongoing earnings of $2.30 to $2.40 in 2012 would be approximately 14% to 16%. Non-GAAP adjustments are made using our Federal and State combined statutory rate of 38.5%.

Based upon our forecast for 2012 our effective tax rate for GAAP purposes would be between 3% and 6% for the year ending December 31, 2012. We also would assume our Dave Gates Generating Station cost allocation methodology would be consistent with the initial decision excluding the 2011 effect of the initial decision. It also assumes fully diluted average shares outstanding of 37.1 million for 2012, normal weather in the Company's electric and natural gas service territories for the fourth quarter of 2012, and lastly we'd exclude any potential impact of an arbitration decision in the Colstrip Energy Limited Partnership or CELP matter, which is expected in the fourth quarter of 2012.

The Company currently estimates that if CELP prevailed entirely, we could be required to increase our QF liability by approximately $30 million. If we prevailed entirely, we could reduce our QF liability by up to $52 million.

Now, moving on to the balance sheet, as of September 30, 2012, cash was about $18 million compared with $6 million at December 30, 2011. The Company had $294 million available from its revolving credit facility at September 30, 2012, compared with $130 million at December 31, 2011. Total debt at September 30, 2012 was approximately $1.1 billion. The Company has a long-term debt to total capitalization ratio of approximately 54% at September 30, 2012, and as we have consistently stated our long-term goal is to be within our 50% to 55% debt to total capital ratio.

During the quarter we issued another $5 million from our equity [dribble] program bringing our total proceeds year-to-date to $28 million since inception. We may issue additional equity through this program to bring the total proceeds up to $50 million by the end of 2012.

With that, let me turn it now back to Bob.

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 allocation methodology which was challenged by several other interveners.

Our methodology proposed to allocate about 20% of the DGGS revenue requirement to our FERC jurisdictional customers and is consistent with past practice of allocating contracted costs for similar service. The ALJ's initial decision issued in late September concluded 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 of similar costs of service.

The initial decision would have the effect, if it's allowed to stand, of either shifting costs to other customers or allowing costs simply to fall between the cracks, and 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 22, we'll have another opportunity to file an answer in brief to other parties who might file in response to ours, on November 13. Additional good news from our perspective is that we are not alone in this fight. There were three other briefs filed, all generally consistent and supportive of our position. If you like to read this sort of thing, I would particularly recommend to you the Montana Public Service Commission brief, which was really very eloquent in describing the context in which we built this plant, the specific needs in Montana, and really was very thoughtful.

Also, a very good supportive brief by the Bonneville Power Administration which is concerned about implications for the larger region, and also a brief by the Montana Consumer Council, which was again on our major points, I think consistent as well. So, following these briefs, the full FERC, the Commissioners, will review the entire matter and issue a binding decision. The FERC is expected to issue a final order in the proceedings sometime in the next six to nine months.

If NorthWestern is forced to pursue its full, our full appeal rights through rehearing and eventual appeal, to the United States Courts of Appeals, the procedural schedule certainly could extend into 2015. In the meantime, we continue to bill customers, FERC jurisdictional customers at the interim rates which have been effective since January 1 of 2011. Obviously, these interim rates are subject to refund plus interest pending final FERC resolution.

Now, I'll provide you a bit of an update on our regulatory calendar which as always is busy. As I previously reported during the first quarter, the Montana Public Service Commission approved the Spion Kop wind project in Montana, in addition to our regulated rate base as an electric supply resource. This $86 million project provides a 25-year levelized cost to customers at approximately $55 a megawatt hour. The project is being constructed by Compass Wind with a turnkey closing actually expected within the next few weeks, and we expect Spion Kop to go into rates through a tracker as early as this December.

As you know, we've been actively exploring opportunities to acquire natural gas reserves dedicated to serve our Montana customers. We held a hearing with the Montana Public Service Commission this quarter to officially place our Battle Creek property into rate base, and the Commission will likely process that filing before the end of the year. Importantly there we had a stipulation with the Montana Consumer Council agreeing to a 10% ROE, 52% debt-48% equity capital structure and because the cost of the asset is already being recovered through a tracker, there would be no effect on rates should the Commission decide to allow Battle Creek into rate base.

Also related to Montana natural gas supply, we've completed the purchase of a natural gas production interest in Northern Montana's Bear Paw Basin. That was for approximately $19.5 million. With these two purchases, we've now procured about 10% of our retail Montana natural gas needs. NorthWestern plans to include the cost of service for the Bear Paw Basin properties as part of our monthly natural gas supply rate adjustment on an interim basis commencing on November 1, ending NorthWestern's filing with the Montana Public Service Commission for full review of the costs.

In the meantime, our goal continues to be to own and rate base about 50% of our Montana natural gas needs, and that would be about 20 BCF annually. As I mentioned earlier, we filed with the Public Service Commission a request to adjust natural gas rates, distribution and transition rates, by about $15.7 million to account for the extensive investments we have made in our natural gas transmission, distribution and storage systems, and to implement pipeline integrity and infrastructure improvements and cover our increased expenses.

We requested a capital structure of 52% debt, 48% equity, and a 10.5% ROE. Significantly the return on rate base, the overall return on rate base that we requested, is 7.83%, and that's based on a very attractive cost of debt of 5.39%. This is compared to the rate of return we received in our 2009 rate case of 7.92%, so we've been very successful in accessing the debt market and passing that benefit on to our customers.

A decision is due from the Montana Commission by June 30 of '13. We're obviously in the very earliest stages of this case. No procedural schedule has been issued yet so we don't know when we might see a [intervener] testimony or when the hearing in front of the full Commission will occur. We have asked for an interim natural gas rate increase pending a full review of the filing by the Commission. The Montana Commission is not bound statutorily to grant interim rates at a specific time. They have granted interims in the past. Generally interims are decided upon after intervener testimony is filed and reviewed.

Now, I'll give you an update on our distribution operations. Over the past several quarters we've been implementing our Distribution System Infrastructure Plan, or DSIP, and this focuses on our Montana gas and electric distribution systems. It's important to note that we are making significant investments in gas and electric distribution in South Dakota and gas distribution in Nebraska, too.

During the third quarter, our capital expenditures for the Montana DSIP were about $6 million and about $14 million to date. In addition, we're projecting approximately $72 million of incremental DSIP expenses and approximately $253 million of DSIP capital expenditures over a five-year time span beginning in '13.

Based on our current forecast along with the Montana Commission's approval in March of '11 of an accounting order to track expenses, we believe DSIP-related expenses and capital expenditures will be recovered through annual or bi-annual general rate cases.

Moving to our baseload electric supply in Montana, as you know we obtain a significant portion of our electric supply from power purchase agreements that will expire by the end of '14. Over time, and where it makes economic sense, we'd like to transition that TPA supply toward rate base in order to provide reasonable and stable rates and supply for our customers. We've stated in our biennial integrated resource plan filed with the Montana Commission in 2011 that we plan to begin analysis of the viability of building a base load natural gas plant in Montana to serve our electric supply.

Turning to supply investments for South Dakota, as I mentioned in 2011 we began constructing our peaking facility that we will fully own, located here in Aberdeen, of about 60 megawatts and that's to replace a power purchase agreement that expires at the end of this year. This facility will supply peaking reserve margin that is necessary to comply with capacity reserve requirements.

With respect to this plant, we've incurred capital expenditures of about $46 million to date. We expect additional capital expenditures at about $10 million to finish construction and we expect to achieve commercial operation before next summer season.

As we've been discussing for some time, we also need to address emissions reductions at the Big Stone Power Plant in northeast South Dakota as well as the Neal Plant in northwestern Iowa. These are both jointly-owned facilities in which we participate.

We have no significant third quarter updates to provide other than to say that both emission reduction projects are proceeding very much as planned. We continue to expect our portion of the CapEx to be about $125 million for Big Stone and about $25 million for Neal, and we expect both projects to be completed around 2015.

We plan to file a 2013 electric rate case with the South Dakota public utility Commission with a 2012 test year and would include costs associated with both emissions reduction projects incurred up to that point.

In addition as part of that rate case filing, we plan to propose to file environmental riders for the two projects from 2013 to the end of the projects at both plants.

Turning to the transmission side of the business in Montana, as I stated earlier we do plan to shelve the Mountain States Transmission Intertie, or MSTI, and the Montana Collector system. However, through requests from customers for generation interconnection and transmission service and capital expenditures for growth and reliability, we do continue to improve our transmission infrastructure. We disclosed in the second quarter that we would consider writing down or writing off the costs of the MSTI project depending on the likelihood of reaching an agreement with the Bonneville Power Administration to serve its Southern Idaho loads. The BPA notified us that it had ranked other options ahead of MSTI to serve BPA Southern Idaho loads and we promptly made and then disclosed that decision.

So, based on BPA's notification, the continued market uncertainty and permitting issues, we have now [impaired] substantially all of the preliminary survey and investigative costs totaling approximately $24 million associated with the MSTI projects. We do not anticipate incurring significant additional costs in the foreseeable future related to MSTI. We have notified both the Federal and State agencies of our decision and also notified them to keep our application on file while we continue to review our long-term options likely over the next several years.

We remain very much engaged in the process related to the proposed upgrade to the existing Colstrip 500kV line which runs from the coal plant at Colstrip to the west and eventually to the Pacific Northwest. In 2011 the Bonneville Power Administration issued a statement proposing two transmission line upgrades, one in Washington and the Colstrip Upgrade Project in Montana.

BPA began its public comment period on its upgrade to the 500kV system in Montana which they refer to as the Montana-to-Washington upgrade. The Colstrip 500kV upgrade and the BPA Montana-to-Washington upgrade are complementary projects as each is required for the success of the other.

Also, both projects are subject to or essentially dependent on an upgrade further, deeper into BPA's system. The Colstrip transmission owners have made their compliance filing on March 28 with the FERC. The next major contract to be modified will be the Montana Intertie Agreement between the Colstrip transmission owners and BPA. The investment potential for the Colstrip 500kV upgrade ranges from about $40 million to as much as $70 million depending on how many Colstrip transmission owners decide to invest in the project, and the upgrade to the system could be completed by the end of 2016. However, the timing will need to be coordinated with BPA's portion of the upgrade further west.

So, in summary, we are very disappointed with the quarterly results, of a loss of $0.10 per share, which again was largely driven by the two one-time items we've discussed. However, our core business continues to perform to expectations as we've also discussed, and we remain very much committed to funding our distribution improvement plans and improvements to the transmission infrastructure that serves our existing customers, and also to seek additional regulated energy supply resources to provide our customers long-term price stability and resource adequacy.

So with that, I'd like to conclude this part of the call and open it up to your questions. Thank you for your attention.

(Operator instructions) We'll take our first question from Paul Ridzon with Keybanc.

Good afternoon.

Hey, Paul.

Can you hear me?

Yes.

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

Sure. 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. At this point we're not actively developing the entire Collector system. If at 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, too, as I've 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 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 system 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 divestiture, so 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 believe we were on good ground first of all in that they had consistently approved the contracts that we used to obtain the service, and as part of that process, I noted favorably our plans to build a resource like this.

But, one of the challenges appearing before the FERC in Washington, D.C., and I think, 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 their decision, the ALJ decision failed that test.

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

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

Then lastly, there's a rumor that PPL is potentially looking to divest Colstrip. Just wondering if you looked 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. Thank you for the question, though.

Okay.

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

Hey, good afternoon, guys.

Michael.

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

What I'm referring to specifically are the contracts that we had to 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 contract. Mike?

Thanks, Bob. What I'd add to Bob's comments is that the contracts that we believe had this precedent firmly within them were entered into in the 2008 and 2009 time frame, so very much recent precedent, 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.

Okay great, thanks for that added color. Now, throughout the process of building the Dave Gates station and communicating with the FERC, did the allocation of costs ever come up or was it just assumed, and the discussions were just mainly focused on prudency and absolute cost?

There are two different processes, I'm going to ask Mike to provide some color because he was in these, in these meetings. On the state side as you know, there's a 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 Commissioners' offices, Commissioners and their staffs, talked about the need for the project, the design of the project, and the fact it was intended to meet both our state jurisdictional and our FERC jurisdictional obligations. Mike, beyond that?

The only thing I'd 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.

Okay, 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?

The -- you can think of it as a seven-year project, again, this is Montana-specific, in both gas and electric. A two-year ramp up with primarily expenses associated with expenses, that are covered under the accounting order that I mentioned, and then five years of full production. So, we are including the two-year ramp-up page right -- the two-three year ramp up period right now, and then converting to full production starting at the first of the year.

We, I mentioned we have 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 rate cases on the electric side in Montana, we will be folding in the capital there and we make, 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 committed to -- and fundamentally committed to this project and to 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 in capital spend in '13, it likely through 2013 would be a test year to start captioned, a 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 tester Michael, I think you know in terms of the timetable, by the time you file, the full year effect of receiving the benefit of any rate cases is, so I'd say would be in 2015 we'd see a partial year in 2014, if 2013 was a test year, if that makes sense.

Sure. Okay, thank you.

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

Good afternoon.

Hey, Brian.

Just 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? I think you proposed 105 megawatts 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.

Thanks, Bob. Well, two reasons for the capacity needed to serve the wholesale customers. First of all, the ALJ found that NorthWestern was not entitled to receive [bit] 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, regulation up.

Of course, we believe that that's not accurate and we have strong FERC policy, namely in most recent FERC orders regarding the integration of variable energy resources, into balancing authorities, to support our position is our view. By the way, our brief explaining this was filed yesterday -- excuse me, Monday the 22nd, and is available publicly as well and explains that point pretty well.

Secondly, the denominator -- excuse me, the numerator was also reduced by diversity and 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 loads sometimes offset the need for at least some regulation between the two of them, that those diversity benefits should be shared among those customers, 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 reduced -- increased, that is, from 105 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. The Dave Gates Generation Station has three generators, each 50 megawatts, but the third machine is used to back up the other two. 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 at any time.

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.

Just to reinforce what Mike said, is those were the three drivers. Reg down is a service that if one owns a large fleet, you can provide just really kind of off of that capacity. That's not the case for our company in our market.

In terms of the design of the plant including the three units, the third unit was provided, was built specifically to provide the service to ensure the reliability of the unit, as everyone knows and certainly the FERC knows reliability has a certain price. And if the, if only two units were required to achieve what uh, DGGS was designed to do, the plant would've been built with two units. By definition if we are then somehow committing the third unit to some other use, it's not available to do what it was built to do.

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

Okay great, and then just on your 2012 guidance of $2.30 to $2.40, are there any non-recurring tax-related gains or losses that we should be aware about when thinking about 2013?

No, if there were any non-recurring type things, we would've excluded that from guidance anyway, but there are no non-returning type tax items [included].

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

Yes.

So, there's 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.

Okay, 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 start fairly soon on the permitting in order to get that time for the contract roll-off, or would you be interested in signing a short-term TPA 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 shorten the lead time when they, when a project might be needed, but we look at the situation as providing a number of options. Brian?

Yes, I think I'd put it in this context. You know, we've talked about an IRP in something like a 2018 time period for building anything, and I think noted in there obviously we'd have to enter into shorter-term contracts to bridges to any construction standpoint. So, obviously if you get in a situation where you need to enter into PPAs, you're going to need to start doing that some time in mid-'13 in order to execute something by '14 to take that power out.

And I guess, if hypothetically speaking you were to acquire PPL'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.

Okay, thank you.

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

Hey guys, how are you?

Hey, Chris.

Ca you just explain the difference between the $11.4 million DGGS reserve and the $9.6 million that shows up as the pre-tax amount on the third page?

In terms of the difference between those two numbers is some benefits of bonus appreciation, that's really the difference between the two. That showed up this year.

And as far as DGGS 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'd even approach that concept?

In terms of going back to 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.

Right, okay. 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 on in Montana as far as wind development goes?

Actually, Mike Cashell again who heads our 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 under way 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 -- uncertainty around what the Federal policy for renewable incentives will be, also probably some nearer-term uncertainty about what the requirements for participating in the California market will be. Mike has I think the most exposure, the most direct exposure there. Mike?

Actually Bob, you did a nice job of explaining in general terms what's going on in our system. I will say that we still have about 2800 megawatts of transmission -- excuse me, generation interconnection requests on our system as well as transmission service requests on our system, from wholesale customers that we were working through, some of which would require significant transmission upgrades on our system. So, we still work through that process, obviously it's dropped off some in the last handful of years. We at one point had over 7000 megawatts of generation interconnection 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 five 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 upwards of $30 million, next year we're planning over $40 million worth of investment for our network system.

All right, thank you very much.

(Operator instructions) We'll go next to Jonathan Reeder with Wells Fargo Securities.

Good afternoon, gentlemen. Thanks for the additional clarification on the Dave Gates issue. Could you just clarify if the ongoing annual impact from this decision and your decision to defer the revenues is $0.12? I mean, is that how we should view it as what's kind of being stripped out of 2012?

Correct.

Okay, and then should we, 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 you know, what kind of went into that decision process of actually stripping it out, since you haven't got a final decision?

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

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

You should just draw the conclusion we're being consistent with what we reported today (inaudible) shouldn't draw any conclusion in terms of our optimism or not.

Okay, and then Brian, on the $2.30 to $2.40 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 you know, just on the actual way the weather's played out thus far, it should be $2.22 to $2.32?

I think what you should do is, the $2.30 to $2.40 takes into consideration backing out both the negative weather that we had in the first two quarters, and the positive weather in the third quarter. So it'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 $2.30 to $2.40 if you have normal weather for the entire year, even the fourth quarter?

Correct. Correct.

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

I think the door is still open for that. As Bob pointed out, we'll evaluate that every year, and if it makes sense to come in sooner than that, we would do that. My point about talking about the 2013 test year is just 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 this year based upon our 2011 test year.

Okay, thanks. I appreciate it.

(Operator instructions) We'll go to Andy Levi with Avon Capital.

Hi, how are you?

Hey, there.

Most of the questions were asked already. When are you guys going to give guidance for '13?

Yes, what we do is at EEI we give drivers, but we don't -- drivers in terms of our thoughts on '13, but we don't give actual guidance until after we release our year-end earnings, and so it'd be in mid-February.

Okay, and I guess you mentioned you're still looking for gas assets, right? That's correct?

Correct.

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

We do expect a decision from the Montana Commission before the end of the 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.

Okay, 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 makes sense for our customers, but again, the market right now is very, very good and we're 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 have, that are known, that have fairly stable and long asset lives, and the reason we're focusing on Montana is that 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 field that I'm describing.

Okay, and just back on the potential PPL assets, which I know you can't really comment on, but just to understand, if for some reason you were -- 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 have to -- we would take in anything to the Montana Commission. Obviously, the Commission would have to approve to include anything in rate base, and our focus is on assets that make sense to serve our Montana customers.

Right, 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 it's not like you would get stuck with some type of [merchant] [facility]?

Correct.

Okay.

That's to say the general comment that would apply to any supply, to any electric supply acquisition.

Okay. Thank you very much.

We have no further questions at this time.

Great, well going once, going twice, and again thank you for your continued interest in the Company. 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.