NorthWestern Energy Group Inc (NWE) 2012 Q1 法說會逐字稿

Good day, ladies and gentlemen. All sites are now online in a listen-only mode. Please note, today's conference may be recorded, and also note there will be a question-and-answer session later on in today's call. (Operator Instructions)

We'll now turn the program over to our speaker for today, Dan Rausch. Please go ahead, sir.

Good afternoon and welcome to NorthWestern Corporation's financial results conference call and webcast for the quarter ended March 31, 2012. Our 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; and 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 listed on 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 the presentation, those of us joining by teleconference will be able to ask questions. A replay of today's call will be available starting at 5.00 Eastern Time today through May 26, 2012. To access that replay dial 800-723-0498. That number again is 800-723-0498. You should not need a passcode, so that should get you straight into the replay number.

And with that, I will turn it over to President and CEO, Bob Rowe.

Thank you, Dan. Despite the significantly milder heating season that challenged most of the industry, we were able to provide stable earnings in the first quarter of this year. Consolidated net income was $32 million and that's $0.88 for fully diluted share for the quarter ending March 31. And that compares with consolidated net income of $32.2 million, or $0.89 per fully diluted share for the very wintry first quarter of 2011.

In addition, we received a final order from the Montana Public Service Commission approving total project costs and establishing final rates for the Dave Gates Generating Station, or DGGS. And we received approval from the Montana PSC for the Spion Kop Wind project. And as you may recall, the Commission did include a condition in it's approval that would reduce our -- potentially reduce our revenue requirement if a minimum performance threshold at the end of the initial three years of operation was not met. We analyze that condition and decided that to move forward by issuing the notice to proceed to Compass Wind. And again that will be a rate case project.

Also related to electric supply, we continued construction on the 60-megawatt peaking facility located in Aberdeen, South Dakota, which we expect to achieve commercial operation before the 2013 summer season. At the end of the quarter, we submitted an application with the Montana Commission to place our majority interest in the Battle Creek Field natural gas production fields and gathering system that we've acquired into our regulated natural gas rate base in Montana.

And I'm very proud of how our operations team has been able to handle issues at the DGGS station with the turbines. We expect two of the three units to be placed back into service and be operational by the end of April. And by getting two of the three units running so quickly again, we were able to keep the first quarter incremental costs for replacement regulation down to about $0.5 million. We believe that those incremental contracted costs should be recoverable through the normal course of business. Last, but certainly not least, yesterday the Board of Directors declared a common stock dividend of $0.37 per share payable on June 30 to common shareholders of record as of June 15.

And now our Chief Financial Officer, Brian Bird, will discuss our 2012 financial results in more detail. Brian?

Thanks, Bob. As Bob said we reported net income of $32 million, or $0.88 per fully diluted share for the quarter ended March 31, 2012 compared with consolidated net income of $32.2 million, or $0.89 per fully diluted share for the quarter ended March 31, 2011. So for all intents and purposes, we were flat year over year. Gross margin decreased by $5.5 million during the quarter end 2012, compared with the same period of 2011. The primary drivers were a decrease in electric and natural gas volumes driven by warmer winter weather and a decrease in Montana property taxes included in a tracker. These were offset by higher Dave Gates Generating Station related revenues, including approximately $2.7 million that we had deferred in prior periods, and also an increase in South Dakota natural gas rates.

Our operating, general and administrative expenses decreased by $1.8 million during the quarter ending 2012 compared with the first quarter of 2011. This was primarily driven by timing related proactive line maintenance as compared with the same period of 2011. Property and other taxes decreased by $1.7 million compared with the same period of 2011. Depreciation expense increased by $1.1 million over the 2011 as a result of increasing our investment in the business.

Interest expense for the first quarter of 2012 declined about $1.1 million compared with the first quarter of 2011 due primarily to lower interest rates on debt outstanding. And finally, income tax expense decreased by $1.1 million for the quarter ending 2012 with an effective tax rate of 20% for the quarter compared to a 22% tax rate in Q1 of 2011. The income tax expense reduction was primarily due to higher repairs deductions and lower taxable income, and we still expect the overall tax rate for the full year of 2012 to be between 18% and 20%.

So to sum up the quarter, there were primarily three drivers. First, warm weather impacted all of our service territories. From a heating degree basis, it was 25%, 17% and 13% warmer in South Dakota, Nebraska and Montana respectively in the first quarter of 2012 than it was in the same period in 2011. This had an $8.2 million impact on our margins.

Secondly, DGGS, or Dave Gates Generating Station's results were $4.5 million better than the prior year. This also included $2.7 million that was previously deferred pending an outcome of allocation uncertainty in Montana. And third, we had lower operating costs than we did in 2011, some of which are due to timing, and some associated with contingencies implemented as a result of mild weather we experienced in the first quarter.

Both the negative impact of the warmer weather and the favorable impact from the deferral reversal associated with the Dave Gates Generating station are items we would reverse from our non-GAAP earnings calculation for the first quarter. So our fully diluted GAAP EPS in the first quarter of 2012 was $0.88 per share. After adding back what we calculate to be $0.09 per share for the warmer winter weather and deducting $0.05 per share for the positive effect on income from the DGGS related prior period deferral, we calculated non-GAAP fully diluted EPS for the first quarter of 2012 to be $0.92 per share.

Now I'll talk about our earnings outlook for 2012 for the total year. For the full year of 2012 we are reaffirming our fully diluted earnings per share for 2012 to be in the range of $2.35 to $2.50 per fully diluted share. Our primary assumptions including the 2012 guidance are consolidated income tax rate of approximately 18% to 20% of pretax income; secondly, the DGGS outage costs fully recovered; third, no expected increases in insurance reserves or insurance recoveries in 2012; fourth, no scheduled maintenance at Colstrip Unit 4, Neal and Big Stone plants; and lastly, fully diluted average shares outstanding of 37 million. And I should say also, we expect normal weather in the Company's electric and natural gas service territories for the remainder of 2012.

So moving on to the balance sheet, as of March 31, 2012, cash and cash equivalents were $7.8 million, compared with $5.9 million at December 31, 2011. The Company had $177 million available from its revolving credit facility at the end of the first quarter. And total debt at March 31, 2012 was approximately $1 billion. The Company has a long term debt to total capitalization ratio of approximately 53.6 at March 31, 2012. And to fund the growth opportunities of the Company, we intend to utilize available cash flow, debt capacity that would allow us to maintain investment grade ratings and based on our current plans. You may have already seen this, but this morning we filed with the SEC an 8-K relating to the sale from time to time of up to $100 million of common stock pursuant to an equity shelf program, or dribble plan. As we had previously mentioned, we plan to issue equity -- enough equity to stay within our 50% to 55% debt to total capital ratio.

With that let me turn it now back to Bob.

Thank you, Brian. As is always the case, we're busy across all parts of the business and I'll provide you first an update on our regulatory calendar. As I mentioned, during the first quarter the Montana Commission approved the Spion Kop project and the regulated-- it's to be included in regulated rate base in Montana. And this $86 million project provides a 25-year levelized cost to our customers of approximately $54 a megawatt hour. On March 30, we filed with the Montana Commission to seek approval -- to obtain approval to add our interest in the Battle Creek Field and gathering system into rates. We anticipate a decision there by the end of the year.

While-- now turning to several of our strategic initiatives. First, in distribution, over the past several quarters, we've continued very actively to implement our DSIP, that's the Distribution System Infrastructure Plan for both our electric and gas operations in Montana. We're currently estimating incremental DSIP expense of about $12 million which will be deferred under an accounting order that the Montana Commission granted last year, and approximately $18.2 million of DSIP capital expenditures during 2012.

During the first quarter, our capital expenditures for DSIP were about $2.9 million. In addition we're projecting approximately $72 million of incremental DSIP expenses and about $253 million of DSIP capital expenses over a five-year time span beginning in 2013. Again, think of this as a project with a two-year ramp up and then five years of full execution. Based on our current forecast, along with the Montana Commissions approval of the accounting order, we believe DSIP related expenses and capital expenditures will be recovered in rate base through either annual or biannual general rate cases.

Moving to base-load electric supply in Montana, as you know in Montana we obtained a significant portion of our supply from power purchase agreements that will have expired by the end of 2014. Over time, we'd like to transition the power purchase agreement supply into rate base in order to provide reasonable and stable rates for our customers over the very long term. Consequently, we're evaluating opportunities to buy or build electric supply over the next several years. As we stated in our biannual integrated resource plan that we filed with the Montana Commission late last year, we plan to begin analysis on the viability of building a base-load natural gas plant in Montana to serve our electric supply.

Now turning to natural gas reserves, we have filed to place our Battle Creek property into rates and the Montana Commission has commenced processing of that filing. In the meantime, we are continuing to explore investments in proven natural gas reserves that will be rate based and dedicated to serve our customers.

Turning to supply investments in our South Dakota territory. On October 14 of last year, we had a groundbreaking for our peaking facility near Aberdeen, South Dakota of about 60 megawatts, and that will be to replace an agreement that expires on December 31 of 2012. And this facility will provide peaking reserve margin necessary to comply with our capacity reserve requirements in South Dakota. During the first quarter of this year, we've incurred capital expenditures of about $12 million associated with the Aberdeen peaker. We expect additional capital expenditures of about $44 million during the rest of the year, and we expect to achieve commercial operation before the 2013 summer heating season.

As we've been discussing for some time, we need to address emissions reductions at the Big Stone Power Plant in Northeast South Dakota. Parenthetically we had an opportunity over the last few weeks to visit all of our plants serving South Dakota and was very impressed with the quality of operations there. So at Big Stone we have a 23.4% interest in that 454-megawatt coal-fired plant to address regional haze or regionally impaired visibility caused by multiple sources over a wide area. The plant operator, Otter Tail, has recommended flue gas desulphurization for sulfur dioxide emission control along with a fabric filter for particulate emission control. And studies and evaluations are continuing and pencils are being sharpened, but the current project cost is estimated to be around $490 million. So our 23% portion of the CapEx would be around $125 million. We're keeping the South Dakota PUC informed of developments on an ongoing basis as we continue our analysis and as that project proceeds. Currently we expect the project to be completed in 2016.

Also in South Dakota, the owners of coal plant Neal 4 in Northwest Iowa are moving forward and installing a scrubber in the 2013 to 2015 time frame. MidAmerican is the plant operator there and has good experience retrofitting some of its other operating plants. The planned addition at Neal includes a scrubber, bag house and an activated carbon injection system and are currently under way and are expected to provide max compliance for that facility. CapEx is currently estimated to be about $270 million. There we are only an 8.7% owner, about 56 megawatts of a 655-megawatt facility, so our capital portion is likely to be right around $25 million. Again in South Dakota, we plan to file a 2013 electric case 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 the rate case filing, we plan to propose to file environmental riders from 2013 to the end of the installation of the equipment on both of these projects.

Turning to the transmission side of the business in Montana where we operate an extensive and large electric transmission system, as well as a gas transmission system to serve all of our customers, we do have three transmission projects that are related to growing energy development potential in Montana. Those of course are MSTI, the Mountain States Transmission Intertie, the Collector system and an upgrade to the current 500kV Colstrip transmission system. First with respect to Collector and MSTI, in January of this year we signed a Memorandum of Understanding with the Bonneville Power Administration whereby BPA has indicated a potential interest in significant capacity in the MSTI line as an alternative source for serving their Idaho loads.

BPA has current and future requirements to serve customers in Idaho, Western Wyoming and Southern Montana. BPA currently serves these customers through agreements with PacifiCorp using the South Idaho exchange agreement and with PacifiCorp and with the general -- PacifiCorp general transfer agreement. Because the South Idaho exchange agreement will terminate in 2016, BPA is evaluating various alternatives to serve its customers affected by the termination. Though we've experienced delays with MSTI, as is true for many major transmission projects, we do continue to see opportunity and are very pleased with the progress related to the projects.

Moving to the proposed upgrade to the Colstrip 500 KV line, earlier this year, or pardon me, in 2012, BPA issued a statement proposing two transmission line agreements, one in Washington and then the Colstrip upgrade project in Montana. 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 to the west.

Now concerning the analysis we've been performing related to transmission opportunities in South Dakota. In the past, we have stated that FERC gave the Midwest Independent Transmission System Operator, MISO, authority for a cost allocation tariff for certain projects that have been identified as having regional reliability capacity constraint relief and other attributes and values to the regional MISO footprint. These are the so-called multi-value Oregon BP projects. And we continue to advance our analysis in proposing a project or projects to the MISO. However, any possible transmission investment opportunities from our South Dakota service territory into the MISO would be several years out, at this point, if any are to occur. And because of that, we plan to remove that discussion from our project summary list that many of you are familiar with until those projects gain more clarity.

So in summary, despite the significantly milder heating season, we were very happy with our earnings in the first quarter, consolidated net income again was $32 million, $0.88 per fully diluted share for the quarter, compared with consolidated net income of $32.2 million, or $0.89 per fully diluted share for the first quarter last year. We received the approval from the Montana Commission for Spion Kop and have issued the notice to proceed on that project, continue construction on the Aberdeen peaker facility. We submitted the application to the Montana Commission to place our interest in Battle Creek into rate base and are very active on our distribution projects as well.

Finally, we are hosting this call from Butte, Montana, had a very successful annual shareholder meeting earlier this morning. Last night we had a wonderful reception for many of our 561 Butte area employees. Tonight we're having a community reception as we celebrate the century, the first century of providing service not just in Montana but across our service territory, and so an accomplishment we are very proud of. We refer to it as celebrating our first century and building for our second.

And with that, I would like to conclude the dissertation portion of the call and open it up to discussion and questions.

(Operator Instructions)

Brian Russo from Ladenburg Thalmann.

Just on Battle Creek, just could you just give us a sense of what the criteria that the PUC will evaluate in the review and approval process for that?

The Commission has supported a portfolio approach to electric and gas resource, so they will look at the contribution of this resource as part of a portfolio. Part of it is price but, as importantly, is long-term stability. And, as we've mentioned previously, as we've moved back into owned resources, we have continued to consult with the Commission staff and with the Montana Consumer Council.

Okay. And, the PPL supply contracts that expire in early '14, you guys mentioned earlier that you're evaluating the alternative scenarios. I would imagine it's going to take a good three years to build a base-load plant with permitting and construction. What are you going to do to fill in that gap if the supply contracts roll off in '14 and a base-load plant isn't commercially available for a year or two after that?

Sure. Well, we are very mindful of the lead time on construction and, as part of the filing, we talked about the concept of kind of project banking to deal with the long lead time. But, effectively, what we would do -- again, depending on how facts on the ground develop -- would be to transition from contracts to owned resources, and we're comfortable with our ability to manage the market there.

Do you have a deadline in which you have to notify PPL that you're not going to renew contracts?

No.

Okay. Also, is there any -- are you taking any bonus depreciation this year that will impact rate base in the form of increased deferred taxes in the next Montana general rate case?

We utilize bonus depreciation. We also establish deferred-tax assets. But, we provide the benefit of a bonus to our customers and -- but we adjust our revenue requirement respectively for a bonus depreciation. But, long term, the rate base will be adjusted for ultimate investment (inaudible).

Any way to quantify that?

I can't quantify that on the call today.

Okay. And lastly, you mentioned the kind of the 2012 test year rate case for South Dakota for-- to be filed in '13. How does the South Dakota peaker recovery play into that since that won't be operational until after the test year in mid '13?

We will expect to treat that and have already talked to staff about that as a known and measurable adjustment. And so it would be included in the rate base calculation, even with a 2012 rate base.

Okay, great. Thank you.

Paul Ridzon from KeyBanc.

You had a notable uptick in industrial sales. I was wondering if there's anything behind that -- is it a timing issue or is it really a fundamental increase in load?

We're evaluating that ourselves, Paul.

Okay. And then, just back to base-load, there's what appears to be an abandoned asset out in Montana, wonder how you're thinking about that and a potential rate base opportunity there?

Sure. What I can say is just that we actively look at the whole range of options on the supply side -- new build, existing resources, the SME site that you're referring to. Every one has its own set of advantages and disadvantages, and beyond that I really can't comment.

And could you just give us an update on your latest thinking about potential magnitude of a natural gas reserve investment?

Sure. Well, ultimately, we would like to get to perhaps 50% of the supply we provide to our customers and a similar ratio of gas we would need to provide electric supply. As we move forward in that direction, though, we would be in close communication with the Commission staff and with the Consumer Council. But that's based on Montana Power Company's very successful experience managing a portfolio about that size. And, currently, we have a very, very long way to go even to achieve that as to our gas load, let alone providing any kind of fuel for power generation.

And, since you started kicking the tires on potential acquisitions on that front, what have you seen as far as pricing on the interfaces?

Brian?

Yes, I think at this point in time, we know what the Battle Creek pricing is and we're not comfortable sharing any other pricing that we're seeing in the marketplace today.

Okay, well thank you very much.

(Operator Instructions)

Jonathan Reeder of Wells Fargo.

Good afternoon, gentlemen. Brian, if you could kind of discuss the $100 million dribble plan that you guys just announced, how long I guess do you expect that to last? Is that something you're going to draw down by the end of this year so that it's part of the rate case filings, the 2012 test year, or is that something that's going to be accomplished over a couple years?

I'd put it in this context, Jonathan. We see this as a very valuable tool, so as we approach the end of the year, and throughout the year, to ultimately try to get ourselves back within our 50% to 55% debt-to-capital ratio. And I guess it's a tool that we'll use over the years to come to see how to ultimately do that, so it's difficult to tell you if it's one year, two years or three years. It'll be dependent on how much investment we make, and, ultimately, think of it as a tool to make sure we stay within that ratio.

Okay. And then, Bob, if you could just reiterate I guess your comments on the MISO transmission investment opportunity. I know you said you're going to pull it from the potential project list. I guess, what's going on around that? I think, before, you talked about potentially a 2016 time frame. Is it just uncertainty in the timing or overall ability to I guess participate in MISO since you aren't a member?

Yes, really, it has to do with the fact that we've tried to be very specific and very clear about the identified projects, you've seen our project chart. And then, we, in addition to that, typically footnote projects that are strong possibilities earlier in development but don't have enough definition to really belong on the chart. And our best sense about the opportunities out of South Dakota right now, given what's happening in the Midwest market, is this is still something that is of interest, something we are certainly looking at actively. But it really belongs more in the footnote than it does on the chart. So, we're just trying to be as accurate in our communications with all of you as we can. I wouldn't really read anything into it more than that. But I don't think it changes our level -- it does not change our level of interest in participating in any relevant transmission project out of South Dakota.

Does it change your thoughts along the potential timing of that, or do you just need to I guess advance those conversations a little more and it could be something that transpires rather quickly?

I don't see something developing quickly. And, again, part of the reason for pulling off of the bar chart is just being as accurate as we can about that.

Okay, thanks.

(Operator Instructions)

Michael Klein from Sidoti & Company.

Just quickly on the time line of Battle Creek, when are you expected to get a decision back?

We hope by the end of the year.

Okay, is there any way that could be sped up or expedited just because you're already recovering from the tracker or that's just unlikely?

The filing is so early in its development now. Obviously, we like to see things like that move quickly. But your point is probably the most relevant in that we are recovering there. But, obviously, whenever we look at processing a case, we like to move things quickly and I know the Commission likes to do a good job of managing its dockets as well.

Okay. And, with potential new acquisitions is that something that you would seek pre-approval for, or go through a formal rate case?

It would depend on the particular acquisition, but on the electric side, certainly our preference is for obtaining pre-approval. We think that's a good way to manage projects for our customers, as well as for our shareholders.

Okay, great. That's all I had.

(Operator Instructions)

Brian Russo.

Yes, hi. In the event that Battle Creek reserves are disallowed or not approved to rate base by the Commission, how should we view the tracker? Will you be required to refund any money to customers? And then, just remind us, what is the annual margin contribution of the Battle Creek tracker?

The first question is extremely speculative and, quite honestly, we have not looked at that because it has been incorporated into the tracker so far. Second question, if Dan could pull that up and get back to you.

Okay, sure.

By the way, we do have -- I should have pointed out, we do have a stipulation with MCC as part of Battle Creek and that certainly gives us a higher level of confidence. But, again, that makes the question a little bit more difficult to answer and a little bit more speculative.

This is Brian. I'd also add that, since things are flowing through the tracker, we're able to earn on this asset. But, at the same time, because we don't have a decision in terms of whether it's included in the rate base or not, we've been reserving revenues, or, I should say, the margin associated with that. So, you'd see no financial impact if, in fact, it wasn't approved; you would see a favorable financial impact if it was approved. Does that make sense?

Yes, it does, thank you.

Right, that's a key point.

(Operator Instructions)

It looks like we have no further questions from the phone lines.

Okay. Well, again, thank you all very much for joining us today and your interest in the Company. We'll see probably many of you over the next quarter and certainly talk to most of you at the end of the quarter. Thank you.