Northwestern Energy Group Inc (NWE) Q3 2012 Earnings Report, Transcript and Summary

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 ongoing adjusted fully diluted earnings per share 2012 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 2 items, the MSTI and the FERC ALJ item, totaling about $0.52 per share, account for nearly all of that difference. As you can see from our disclosures there are couple of other normalization items for the first 3 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 232 to 240 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 at 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. 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. 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 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 or 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 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 22. We’ll have another opportunity to file an answering brief to other queries they 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 3 other briefs filed, all generally consistent and supportive of our position. If you like to read this sort of thing, I would particularly comment to you the Montana Public Service Commission brief, which was really very eloquent in describing the context in which we built this plan for 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 an issue a binding decision. And the FERC is expected to issue a final order in the proceeding sometime in the next 6 to 9 months. Now, if NorthWestern is forced to pursue 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 build FERC jurisdictional customers at the interim rates, which have been effective since January 1, 2011. Obviously, these interim rates are subject to refund plus interest, a pending final FERC resolution. Now I'll provide you a bit of an update on a 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, as an 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. 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 underway 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, at 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 of the cost, the asset is already being recovered through a tracker. There will 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 2 purchases, we have now procured about 10% of our retail Montana natural gas needs. NorthWestern plans to improve 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, pending 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 transmission rates by about $15.7 million to account for the expensive investments we have made in our natural gas transmission, distribution and storage systems, and to implement the 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 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 was 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, 2013. We're obviously in very earlier stages of this case. No procedural schedule has been issued yet. So we don't know when we might see the 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 an interim rate for the 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 are projecting approximately $72 million of incremental DSIP expenses and approximately $253 million of DSIP capital expenditures over a 5-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 by 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 PPA supply toward rate base in order to provide reasonable and stable rates and supply for our customers. We have stated in our biannual integrated resource plan, filed with the Montana Commission in 2011, that we plan to begin analysis with a viability of building a baseload 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, enough to replace a Power Purchase Agreement that expires at the end of this year. This facility will provide peaking reserved 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 of 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 cost associated with the 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 2 projects from 2013 to the end of the projects at both plants. Turning to the transmission side of the business in Montana, as stated earlier we do plan to shelve the Mountain States Transmission Intertie or MSTI in Montana Collector system. However, through a request 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 cost of the MSTI project, depending on the likelihood of reaching an agreement with the Bonneville Power Administration to serve its Southern Idaho loads. And the BPA notified us that it had ranked other options ahead of MSTI to serve BPA Southern Idaho loads, and we are 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 cost totaling approximately $24 million associated with the MSTI project. 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 of likely over the next several years. We remain very much engaged in the process related to the proposed upgrade to an existing Colstrip 500KV line, which runs from the coal plant to Colstrip, to the west and eventually to the Pacific Northwest. In 2011, the Bonneville Power Administration issued a statement proposing 2 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 500 KV upgrade and the BPA Montana to Washington upgrade are complementary project, as each is required for the success for the other. Also both projects are subject to, or are 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 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 potion 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 2 onetime 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.

[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.