NorthWestern Energy Group Inc (NWE) 2013 Q3 法說會逐字稿

Good day and welcome to the NorthWestern Energy Corporation third-quarter 2013 financial results conference call. Today's conference is being recorded. At this time I would like to turn the conference over to Mr. Travis Meyer. Please go ahead.

Thank you, Jennifer. Good afternoon and welcome to NorthWestern Corporation's financial results conference call and webcast for the quarter ended September 30, 2013. NorthWestern's results have been released, and the release is available on our website at www.northwesternenergy.com. We have also filed our 10-Q after market yesterday. If you're joining us on this call via webcast and you joined early, you may want to refresh your browser if you aren't seeing the introduction slide.

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

Before I turn the call over for us to begin, please note that the Company's press release, this presentation, comments by presenters, and responses to your questions may contain forward-looking statements. As such, I need to remind you of our Safe Harbor language. During the course of this presentation there will be forward-looking statements within the meaning of the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995. Forward-looking statements often address our expected future business and financial performance and often contain words such as expects, anticipates, intends, plans, believes, seeks, or will. The information in this presentation is based upon our current expectations as of the date hereof unless otherwise noted.

Our actual future business and financial performance may differ materially and adversely from our expectations expressed in any forward-looking statements. We undertake no obligation to revise or publicly update our forward-looking statements or this presentation for any reason. Although our expectations and beliefs are based on reasonable assumptions, actual results may differ materially. The factors that may affect our results are listed in certain of our press releases and disclosed on our company's public filings with the SEC.

Following our presentation, those who are joining us by teleconference will be able to ask questions. The archived replay of today's webcast will be available beginning at 6 p.m. Eastern Time today and can be found on our website under Our Company/Investor Relations/ Presentations and Webcasts. To access the audio replay of the call, dial 888-203-1112, then access code 8605196. Again, that is access code 8605196.

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

Thank you very much and thank you all for joining us.

As those of you who participate in these calls regularly know, we always move our Board of Directors meetings around to different locations in our service territory. This week we are in Great Falls, Montana. And I'm going to tell you just a word or two about where we are -- Great Falls sits where the Missouri River comes heading north out of the Rocky Mountains, out of the gates of the mountain, and eventually, of course, heads east and then south into our South Dakota service territory.

But when Lewis and Clark came through here well over 100 years ago, they ran into five enormous waterfalls. It was the most challenging part of their trip, by far. Ultimately they had to portage around the falls. It took about a month and the prickly pears tore up their moccasins.

But as bright people many years later figured out, it's a tremendous place to build hydroelectric dams. And although this Board Meeting was scheduled literally several years ago to be here, it was a wonderful coincidence that we were announcing the acquisition of the hydroelectric facilities in Montana just a couple of weeks ago.. And we're meeting here in Great Falls, which has so much history on our electric system and where several of those key facilities are located.

So, as is always the case, we started the week with a community meeting, extraordinarily well attended by community leaders and citizens. And there was just a tremendous amount of enthusiasm in the community for our announced purchase of the facilities.

Then we continued with the Board Meeting this morning. Had a great breakfast meeting with the Great Falls division employees and we'll be concluding the week with an employee call shortly after this call concludes.

As most of you know, our most significant activity for the quarter was on September 26th, when we announced the $900 million purchase of the 11 hydro facilities and storage reservoir. We've continued to make a lot of progress with that project and I'll come back and talk about it in more detail. Most notably, we did have a very substantive, informative, well attended meeting, informational meeting, concerning the project with the Montana Public Service Commission on October 18th.

This Tuesday, the Montana Commission took one of two key actions to allow our acquisition of what we're calling the South Bear Paw gas production fields to move forward. They granted a waiver from what we refer to as our bankruptcy stipulation that allows us to own those facilities. And they have the next key work session scheduled for next week. We'll come back and talk about that.

The Board declared a dividend of $0.38, payable on December 31 of this year to shareholders of record as of December 13.

Most of you know how important corporate governance is to NorthWestern and to our Board and to all of us on the executive team. There are a couple of things I want to highlight there, too.

First, we were thrilled to have finally clawed our way on to the Public Utilities Fortnightly Best 40 Energy Companies. And that's significant because the recognition is based ultimately on sustainable growth, on four years of very solid performance. And the article highlighting our addition to the top 40 recognized what a remarkable record that was. And if you haven't read it, I commend the article to you. It was a great interview with our Chief Financial Officer, Brian Bird.

A couple of other corporate governance highlights. We have, for the second year in a row, been recognized as a finalist by Corporate Secretary, the governance, risk, and compliance organization, as one of the five best proxy statements in the small and midcap category, with a number of other boldface names in the world of corporate governance.

And I was personally really pleased to be recognized by Corpedia, which is an affiliate of the New York Stock Exchange, for an A for our overall ethics and code of conduct program, placing us in the top 2% of all energy and utility companies reviewed. So, although we are focused on project execution, that comes from a position of strong corporate governance, good financial controls, and great transparency.

We're excited about our role as corporate citizens. Again, that was on evidence at the great community meeting two nights ago. And we can come back and talk more again about various aspects of the hydro transaction.

And with that, I will turn it over to Brian Bird.

Thanks, Bob.

In terms of our summary financial results, for the three months ended 9/30/2013, our net income was $15.6 million, or $19.4 million higher than last year's $3.8 million loss. Pretax income for that period was $17.5 million, or nearly $30 million higher than the same quarter last year.

Two large items did impact last year's third-quarter results, the first being $11.4 million Dave Gates Generating Station revenue deferral associated with the FERC ALJ decision, and also a $24 million MSTI impairment charge we took in the third quarter last year. More discussion on the components of our third-quarter results will be on the slides that follow.

On this slide we also do show our nine-months results ending 9/30/2013. Here we have net income of $67.9 million, or approximately $28 million higher than the $39.7 million for the three quarters ended 9/30/2012.

The main drivers for our results year to date 2013 are -- for gross margin we were up about $30.5 million from added gas production, Spion Kop. Takes into consideration the Dave Gates Generating Station deferral last year. We also have higher electric and gas transmission capacity this year, increased gas volumes, and also takes into consideration the natural gas rate increase we had in Montana.

Regarding operating expenses, they were down approximately $2.6 million. We did have increased operating, general and administrative expenses, property taxes, and depreciation. But they were more than offset by the $24 million MSTI impairment that occurred in 2012. These items result in a $33 million improvement in operating income 2013 versus 2012. This, combined with the $3.7 million increase in other income, offset by a $1.4 million increase in interest expense, results in a $35 million improvement in pretax income.

Income taxes were $7 million higher than last year due primarily to higher pretax income, partially offset by increased flow-through deductions and PTCs from Spion Kop.

The cumulative impact of all these changes results in the $28 million improvement in net income for the nine months we just mentioned a minute ago.

Moving on to focusing on the third quarter, for gross margin for the three months ended September 30, gross margin in 2013 was $158 million compared to $142.9 million in 2012, or a $15.1 million increase, approximately 10.6% increase. The increase was due mainly to the following factors.

We did have a approximately $13 million increase in electric gross margin and the three primary drivers for that were of course we did not have the DGGS revenue deferral this year. That $11.4 million deferral was in the third quarter of 2012. The other reason for the increase this year was we had $5.8 million of higher DSM lost revenues recognized. Those were partially offset by $3.5 million lower retail volumes due to cooler summer weather and reduced customer irrigation. That's on the electric gross margin.

On the gas side, we were up, an increase of about $2 million. The two primary drivers there was a gas production margin, primarily due to the Bear Paw acquisition in the third quarter of 2012, and the Montana natural gas delivery rate increase in April of 2013. That also was a $1.2 million improvement.

Moving on to operating expenses in 2013, for the quarter our operating expenses were $126.6 million compared to 2012 of $138.4 million. The variance is a decrease on a year-over-year basis of $11.8 million or an 8.5% improvement. The decrease is due mainly to the following factors.

First and foremost, $24 million decrease due to last year's MSTI impairment in the third quarter of 2012. That was offset by a $9.4 million increase in operating, general and administrative expenses.

We list those there for you, but capturing the large ones there -- obviously, as we've mentioned, we're going to be spending more on DSIP this year and we have, $3.3 million for the quarter. We did have hydro-transaction-related legal and professional fees during the quarter, higher labor, higher plant operating costs, and with the rising share price, our nonemployee directors deferred comp has increased for the quarter.

Those were partially offset by lower pension expenses, $3.1 million for the quarter versus the prior year.

We also did have a $1.2 million increase in property taxes and a $1.6 million increase in depreciation expense for the quarter.

At the operating income level, $31.4 million versus $4.4 million last year, below that. The improvement is primarily due to the value of deferred shares and director compensation which went up due to the rising stock price. Again, this benefit is offset by an equal and offsetting increase in operating expenses that shows up in the other income line there. Other than that, income tax expense increased approximately $10 million due to the increased pretax income on a year-over-year basis.

Again, and all in all, the resulting impact of all of these changes resulted in net income for the quarter of $15.6 million, or $19.4 million higher than the $3.8 million loss in Q3 2012.

Now, I'll move your attention to the balance sheet. Not much to note there, really, other than total asset growth is mainly due to additions to PP&E.

Our total debt actually declined since year end 2012. We did issue some shares under our equity program, of course, during the year. But our shareholders' equity actually broke through the $1 billion mark this year and is up $70 million during the year from the combination of those share issuances and, of course, the retained earnings contribution.

At the bottom of the page we do show debt to capitalization ratio. We're currently at 53.6%, which is down from 55.8% at the year end 2012. And our debt to cap usually approaches the middle of our targeted range of 50% to 55% at this point in the year. We do expect that ratio to push back up to approximately 55% by year end as we plan to close on the South Bear Paw or Devon transaction. We also typically see higher cash outflows or increased commodity purchases to meet higher customer loads in the fourth quarter.

Moving onto the cash flow statement, cash flow from operations is approximately $171 million through the first nine months of 2013, or $51 million worse than the same period of 2012. And the primary drivers for this decrease are due to timing of collection receivables and the payment of supply costs. We do expect that year end that we'll be closer from a cash flow from operations on a year-over-basis.

Cash used in investing activities was $150 million, or approximately $25 million less than the same period last year. And this is primarily due to the Bear Paw North, or the NFR natural gas reserves purchased last year.

Cash used in financing activities was approximately $20 million, which is comprised of $44 million in equity raised through our dribble program, $43 million paid in dividends, and $20 million in debt repayments.

Moving on to our 2013 earnings guidance, first and foremost we are reaffirming our 2013 guidance of $2.45 to $2.60 per diluted share. The midpoint of that guidance is $2.53. And that is a 6.5% increase over our non-GAAP adjusted EPS of $2.37 last year.

Below our guidance we do list our assumptions. And one additional assumption I should note is on a going-forward basis we would expect to exclude any hydro-acquisition-related expenses.

On an adjusted EPS schedule to give you an idea of how we're doing on both a GAAP perspective on a year-over-year basis and on an adjusted diluted EPS, we do show you on the Q3 up there GAAP EPS is $0.40. We did have three normalizing adjustments for the quarter.

First, we'd remove $0.02 for favorable weather. That's favorable weather versus normal. You may also note when you compare year over year, we actually had worse weather on a year-over-year basis, but it was $0.02 favorable versus normal. We'd also add back $0.05 for hydro-transaction-related expenses. And we'd remove $0.04 for the DSM lost revenue recognized during the quarter that related to 2012.

Netting these three items results in a $0.01 reduction in GAAP EPS to $0.39 on a non-GAAP adjusted basis, or a $0.03 improvement over the 2012 adjusted Q3 EPS.

For all three quarters in 2013 we have seen improved results as compared to the same quarters in 2012 on both a GAAP and non-GAAP adjusted EPS basis. Our total non-GAAP adjusted year-to-date EPS in 2013 is $1.75. If we can repeat our $0.78 per share for the fourth quarter in 2013 like we did in 2012, we will hit the $2.53 midpoint of our 2013 guidance.

Moving on to the 2014 earnings drivers, and don't want to get people's hopes up in terms of providing guidance. We'll give a little bit more detail on this at EEI and we'll give our full 2014 guidance in February.

But a first sneak peek at potential earnings drivers for 2014 -- obviously we will anticipate additional hydro-transaction-related expenses during 2014. And of course, with the hope of an approval from the Montana Commission, hopefully have a potential income offset for those expenses in 2014.

In addition, we hope to close on the Bear Paw South transaction yet here in 2013, obviously a full-year effect of that in 2014.

We do expect organic volumetric electric and gas load growth. We would have a full year of the 2013 Montana natural gas rate case results, a full year of depreciation with adjusted rates from our depreciation studies. We did have three quarters of that benefit in 2013. And increased operating, interest, depreciation, and property tax expected with the growing business.

And, lastly, we do expect upward pressure on income tax rates with the expected elimination of bonus depreciation in 2014.

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

Thanks, Brian. That was a nice little teaser for the EEI financial conference and we do hope to see folks there.

I'm going to start with one of our recurring subjects, the FERC DGGS decision. Let me preface that by saying that the Dave Gates Generating Station, as most of you know, is a regulating resource based in Montana. And it is providing 100% of the regulation needs for our Montana balancing authority.

The issue is obviously going back now over a year to September of 2012. A FERC administrative law judge issued a nonbinding decision allocating only a fraction of the amount of revenue that we believe should be allocated to FERC jurisdictional customers. The FERC commissioners are not obligated to follow any of the administrative law judge's finding. As you know, we did file a request for reconsideration many months ago and are still awaiting a decision from the Commission.

Once we receive a decision, if we disagree with all or part of it, we may pursue our rights through the US Court of Appeals. And that could extend the matter even longer.

We've deferred cumulative revenues of $22.5 million as of September 30th, and we continue to defer revenue of about $700,000 a month and will continue to bill our FERC jurisdictional customers interim rates that have been in effect now since January of 2011. And these interim rates are subject to refund plus interest.

Again, most importantly, the plant is providing all of our regulation resources and has proved itself as a good asset.

Staying with some of our regular supply updates and turning to environmental compliance activity -- Big Stone, as most of you know, we own 23.5% ( sic - see slide 18, "23.4%") of a 475 megawatt coal plant. We've been describing our efforts in the air quality control concerning SOx, NOx, and particulates. And we're now in the construction phase of our compliance activity there.

Through September we've capitalized about $28 million related to our share of this project. The project cost overall is about $405 million and our share would be, in total, $95 million to $110 million, including AFUDC and overheads. The project is on schedule, great work on project management, and we expect it to be completed by April of 2016, which is the compliance deadline.

Similarly, but with a smaller interest, at Neal 4, there we own about 8.7% of a 644 megawatt coal plant. And that project also is well underway. Through September 30th we've capitalized about $21 million related to this project. And we expect our all-in costs will be $25 million to $30 million, again, including AFUDC and overheads. And that project will be completed next year.

Turning to our gas production acquisition in Montana, this has been a great success story, I think, and is going to continue to provide very long-term benefits for our customers. We have pending the acquisition of what we're referring to as Bear Paw South. There we entered into an agreement in May of this year to purchase 64.6 Bcf, proven reserves, along with an 82% interest in the Havre Pipeline Company, for a total of $70 million.

As I mentioned, the regulator waiver necessary due to a stipulation in the bankruptcy case many years ago was filed in June with the Commission, and that was acted on just this week. The Havre Pipeline has submitted an application to the Montana Commission to approve the sale. We understand that the Commission will be considering that next week.

We aren't seeking preapproval from the Commission for acquisition of the gas reserves themselves as a closing condition. And upon closing we anticipate using our natural gas tracker to recover the costs of gas in a manner similar to what we did at Battle Creek and initially at Bear Paw, what we're referring to as Bear Paw North. The 20-year levelized price is about $4.10 per dekatherm.

Based on 2013 estimates, the transaction is expected to increase our own supply for our Montana retail customers from about 9% up to 37%. And we are still committed to a close here in the fourth quarter of this year. So in terms of our requirements to serve our Montana retail gas customers, we still have about 13% unfilled position with a goal to reach about 50% owned supply to serve our natural gas customers.

We are interested, certainly, in further opportunities to procure perhaps an additional 3 to 4 Bcf to provide fuel at Dave Gates Generating Station and also potentially our leased Basin Creek facility. And, again, the goal there would be to provide price stability for our electric customers served by natural gas generation.

Down at the bottom of page 21 we've got a nice summary of the three major transactions we've entered into and then a depiction of what our portfolio looks like, focusing on, again, the target 50% retail load that we would like to serve by owned resources.

Turning to the distribution side -- and the Montana distribution system infrastructure project is one of the things that we are really most excited about. I mentioned we are in Great Falls, Montana today. The Great Falls division is a big stretch of territory that runs quite a ways north, a little bit west, and quite a ways east out of Great Falls. It's a big area, a lot of exposure to the elements. Meeting with our employees here in Great Falls this morning, there's just an awful lot of energy and enthusiasm about what we're doing in both our natural gas and our electric systems.

As most of you know, the goals of the program are to reverse the trend in aging infrastructure, maintain our reliability, proactively manage our safety programs, build capacity into the system where we need it -- and we are seeing capacity needs on our system as growth has picked back up in a number of areas -- and to prepare our network for the adoption of new technologies.

We're very pleased with the great project management that our team has been doing with the accomplishments so far, certainly with the support that the program is receiving from policymakers and from customers.

At the bottom of page 22 you've got a table that provides the CapEx and O&M for electric, gas, and total project. As you know, we had an accounting order covering the O&M piece for the first two years. This is our first year in full production. And both our crews and contract crews are fully engaged and doing a great job.

Turning back to supply, you may have heard that we have entered into an agreement with PPL Montana to acquire their hydro assets, as I mentioned at the top of the call, something we are very, very excited about.

I do want to start by saying that PPL has been a very good steward of these assets. They've invested significantly in the assets during their ownership and have really played a good role in the community.

After we announced this transaction I got a card, actually, from a former Montana Power employee, who quoted one of my great predecessors, Paul Schmechel. And Mr. Schmechel said his strategy about cars and everything else was -- buy it used, when it's in good shape, and invest to keep it in good shape. And I think that's really what we are doing with this transaction.

We really organize our strategic activity, tie it back to our mission and vision statement. And, as you see on page 23, we believe this is a transaction that makes sense from multiple perspectives.

We're acquiring clean, reliable, long-lived generation, again, those waterfalls that caused such challenges for Lewis and Clark 200 years ago and where the dams were built about 100 years ago. And there really is no better resource, we think, for the next 100 years.

Because these will be dedicated to serve our customers with cost-based rates after an initial rate adjustment, probably about 5% from where rates are today, this will be a very stable part of our overall portfolio in Montana and will very nicely match our load requirements, light load in particular, with our own generation.

It will increase our fuel diversity in Montana. In fact, it will be about 50% either hydro or wind, with the stability that our coal assets provide and, again, Dave Gates as a regulating resource will continue to evaluate the needs. On top of this acquisition our supply team continues with its overall efforts around the assets.

I mentioned the great community interest we had. And we take our role in every community that we serve very seriously. Most of the communities where these assets are located are already areas where we have a strong presence, and we'll be reinforcing that presence.

We do expect to acquire 70 or more great employees from PPL's Montana hydro operations and are looking forward to them and our team really meshing. We've established a strong transition team, great leadership there from among NorthWestern employees with an awful lot of depth on the hydro side.

From an investor perspective, these assets will be added to rate base. Should be accretive in the first full year of operations and we expect to maintain or, in fact, enhance our credit profile.

We think these are the right assets and it's the right time for a transaction such as this. Essentially no development risk, in contrast to virtually any other new build project. Located right in the heart of our service territory next to the T&D assets that we acquired from Montana Power about three years after PPL acquired the dams. A great fit to our portfolio, as I mentioned, a wonderful match with our off-peak needs. And our supply team is continuing with the analysis, the site-banking that we actually managed to work through in 2013.

So we have an array of options we'll be looking at in the future, but our focus right now is on the central regulatory process over the next 9 or 10 months or so and then integrating these assets into our system.

Again, from an environmental perspective, we think our fleet in Montana is just in a great position. No fuel costs, very high levels of reliability, great history of reliability at these assets. And buying them at a very favorable time in terms of commodity prices.

In terms of financing, this transaction we plan to close into a permanent financing with approximately $450 million to $500 million in debt, and up to $400 million of equity and then $50 million from free cash flows. If capital market access is limited, we do have the option of closing into a $900 million committed bridge facility with Credit Suisse and BofA Merrill Lynch.

So, again, lots of activity in every part of the business --supply, gas and electric, transmission, distribution, all the customer care functions. Very pleased with where we sit at the end of this quarter.

And now we will open up the mic for your questions.

(Operator Instructions) Brian Russo; Ladenburg, Thalmann.

Just slide 25, the financing strategy, so up to $400 million of external equity. How are you calculating the $50 million of free cash flows?

Brian, do you want to provide some more color on that?

Sure, Bob. The issue is each year, as you know, we put out cash flow from operations. And we're not, obviously, utilizing all of that to finance the capital that we have. And we usually have excess free cash. So a component of that free cash will be allocated to this project.

Okay, great. And then, on the 2014 drivers, there's no mention of a Montana electric rate case. So is the base case scenario that you won't file?

Our regulatory focus is going to be in Montana on the preapproval filing for the acquisition of the hydros.

Okay. Are you confident or comfortable that you can earn close to your allowed returns without an electric rate case?

At this point, I think so. That's something obviously we evaluate at the start of every year.

Okay. And I may have misunderstood you earlier, but you mentioned that the costs associated with the hydro transaction, you hope to offset them with income. I'm a little confused. Will there be any regulatory lag from when these assets are acquired versus when you seek recovery? Or is it going to be pretty much simultaneous?

I'm glad you asked that question, Brian. Let me just be more clear. We will incur hydro-related legal and professional fees throughout the year. There will be an amortization, if you will, of the bridge financing up-front costs associated with that. So those costs will be incurred throughout all of 2014.

The comment I made is hopefully we have income, of course, to offset that. And that means we have a favorable regulatory commission and thus approval of the transaction. And once that approval's received it would be our expectation that the asset would be put immediately into rate base and that we would be earning on those assets. And so, when I said hopefully having income to offset those expenses, what I meant was a favorable transaction outcome and approval.

Okay, great. And then just lastly, again, back on the financing plan. If you were to issue -- if the mix is $400 million of external equity and $500 million of debt, does that put you kind of at the low end of that 50% to 55% debt target ratio, or at the high end? Any color on that?

I'd put it in this context. You can't ignore the fact that we continue to have earnings contribution that impacts the equity portion of our balance sheet. But our view is we're going to finance this transaction very close to our stated capital structure, at certainly within the 50% to 55% debt to capital we have as a company, but very close to the capital structure that we utilize in Montana today.

And what is that, 52%-plus?

In that ballpark of 52% debt.

Okay. Great. Thank you very much.

Jonathan Reeder; Wells Fargo.

One question regarding, I guess, the MPSC's approval for the Havre Pipeline. In the Q you were saying that you need to get the agreement extended with Devon Energy and everything. Is there any reason to believe that that wouldn't get extended or anything like that, that that would be an obstacle to getting the transaction completed?

No, we're very comfortable with where we sit with Devon right now. And I think the Montana Commission understands the importance of a timely outcome there.

Okay. So it's just I guess they weren't expecting to need approval and that's what's kind of pushed it back, but everyone's still on board.

On board.

Okay. And then, also in the Q you said that I guess the Public Service Commission expressed concern with the policy of continuing to allow DSM lost revenue recovery and that the burden of proof is now on NorthWestern to justify it. Can you go into a little detail what brought this about? And is this going to be potentially like an $8 million, roughly $0.12, kind of annual negative impact if that's no longer allowed?

A little bit of history there. The lost revenue adjustment mechanism was approved by a previous commission. So this commission hasn't really had an opportunity to look at it from a policy perspective. We're looking forward to actually seeing the final order from the Commission and what their specific language is. We will want to get the LRAM, the Lost Revenue Adjustment Mechanism, framed as a formal issue for the Commission's consideration and for all parties to comment on as early as possible. And that could be as an issue parties are called on to address in the current tracker; it could be as a standalone item.

So I personally understand the Commissioner's interest in having a careful look at the subject. That said, first of all, we consider cost-effective demand-side management to be a great resource, cost-effective demand-side management. And we believe we have to have a set of policies in place that support acquisition of that resource. The LRAM, or various other mechanisms, is an important part of that.

So we consider LRAM or something like that -- in some states it's decoupling, in some states it's moving more towards a fixed variable rate structure -- to be extremely important. And Brian --?

And I think I'd add to that, Jonathan. On a going-forward basis I think we'd expect to see -- let's say I'll use 2014 versus 2013, we'd expect to see DSM revenues to be equivalent. We wouldn't expect to see any increase in DSM lost revenue recapture, if you will, on a year-over-year basis.

And I also want to caveat that we do not have a final order yet on this matter.

Okay. So how would that work if they would just, say, strike it completely? And then I'd guess you'd lose recovery of that revenue. Is that just kind of a regulatory lag that you'd have to wait to pick up until the next rate case? And then going forward, any additional energy efficiency or conservation would continue to kind of eat at your earned returns until the next rate case picks up the new sales level? Is that how to look at it?

I think -- let's put it in this context. Anything that wasn't recoverable we'd have to deal with that the next rate case and readjust, if you will, our lost revenue from our DSM program at that point in time, reset that.

And there's some confusion in the press. There's a distinction between recovering the direct costs for the programs and then covering the revenue that's lost as a result of the programs' effectiveness. There was some discussion at the Commission about the likelihood of us coming in for more frequent rate case. And we've talked about that in the past. But we've, as I mentioned just a few moments ago, we are hopeful and as we try to manage costs for our customers, it's preferable where we can stay out, through good management of the business, through the favorable tax results we've been able to receive on the federal side through the depreciation adjustments. Those at least give us some comfort where we sit right now going into next year, able to focus on the hydro acquisition.

So an unintended consequence of eliminating the lost revenue adjustment could be more frequent cases. And, again, our investment is in the regulated utility business. That's where we put our capital; that's where we put our assets in serving our customers. We want to be able to continue that focus.

And the reason for the more frequent rate cases would be just kind of truing up the appropriate sales level. Is that correct, Bob?

Yes, in that kind of a lag situation that your question suggested.

Okay. Brian, I don't think you mentioned it, but do you still plan to take down the remaining portion of the $100 million equity by year end?

We will continue to utilize that facility. I won't commit to how much we'll use by year end.

Okay. Is it dependent at all upon the closing of the Bear Paw South? Is that what's --

(Multiple speakers) --

-- impacting the timing at all?

I would say obviously we're trying to finance these transactions in line with their expected long-term capital structure. So it would be a factor.

Okay. And then, the effective tax rate for 2014 versus the 12% this year? Any indication where we might be? Or is that something just to hang until EEI?

Jonathan, you have to give us something to talk about at EEI. But we'll give you guidance range at EEI on that matter.

Well, I was surprised you said for your guidance that then the true range wouldn't be until February. Aren't you going to release it at your Analyst Day?

(Laughter)

You know, we might. We might. If that's what it's going to take to increase attendance, maybe that's when we'll do it, Jonathan. Good call.

Maybe.

(Inaudible) Brian was such a promoter.

And then, I guess in line with the guidance and with Brian's question, so I guess in Q3 you excluded the transaction costs for the hydro, for [reaching] the hydro agreement. But in 2014 you plan on including whatever ongoing transaction costs until it closes within your range?

That's a great question. Thanks for bringing it up. Just to clarify, we will be consistent. We do expect to incur, of course, those costs. But we would exclude those from our adjusted EPS numbers, just for the comparison purposes, if you will, 2014 versus 2013.

Okay. All right, that's all I've got. Appreciate the time.

And at this time there are no further questions.

Great. Well, thank you all very much. And I'll join Brian in looking forward to seeing you at the EEI Financial Conference and at Analysts Day in December. Thanks very much for your interest in and support of the Company. And look forward to seeing you all soon. Take care.

This does conclude today's conference. We thank you for your participation.