NorthWestern Energy Group Inc (NWE) 2016 Q2 法說會逐字稿

Good day everyone, and welcome to the NorthWestern Corporation second-quarter 2016 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, sir.

Thank you Laurie. Good afternoon and thanks for joining NorthWestern Corporation's financial results conference call and webcast for the quarter ended June 30, 2016. NorthWestern's results have been released, and the release is available on our website at NorthWesternEnergy.com. We also released our 10-Q pre-market this morning. On the call with us today are Bob Rowe, President and Chief Executive Officer; Brian Bird, Vice President and Chief Financial Officer, and several other members of the management team in the room with us today to address your questions.

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 will remind you of our Safe Harbor language.

During the course of this presentation, there will be a 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 contains words such as expects, anticipates, intends, plans, believes, seeks or will.

The information in this presentation is based upon our current expectations of the date hereof unless otherwise noted. Our actual future business and financial performance may differ materially and adversely from 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 upon reasonable assumptions, actual results may differ materially. The factors that may affect our results are listed in certain of our press releases, and disclosed in the company's Form 10-K and 10-Q along with other 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 PM Eastern time today and can be found on our website, again, at NorthWesternEnergy.com under the Our Company, Investor Relations, Presentations and Webcasts link. To access the audio replay of the call, dial 888-203-1112, then access code 2437706. I will now turn it over to our President and CEO, Bob Rowe.

Good morning everyone, thank you Travis. I will start with some high-level results and then turn it over to Brian for the financial report.

Net income for the quarter was $35.6 million, or $0.73 per diluted share, as compared with net income of $31 million and $0.65 per diluted share for the same period last year. This $4.6 million which was a 14.8% increase in net income, is due primarily to improved gross margin and lower income tax expenses. However, these improvements were partially offset by the inclusion of a $20.8 million recovery of environmental-related cost in our second quarter of 2015 as a reduction of operating costs. Non-GAAP adjusted earnings per share increased 35.4% to $0.65 as compared with $0.48 for the same period in 2015.

On July 12, parties involved in the Colstrip litigation, and that includes all of the Colstrip owners, plus the Sierra Club and the Montana Environmental Information Center, reached a settlement and lodged a consent decree with the Federal District Court that provides for no shutdown date for units 3 and 4, and dismisses all claims against all units. We will come back and talk about that in a little more detail.

Also, issuance of $60 million of South Dakota First Mortgage Bonds at a fixed interest rate of 2.80% maturing in 2026, to refinance our 6.05%, $55 million First Mortgage Bonds which were due 2018. At its meeting yesterday, the board approved a quarterly stock dividend of $0.50 per share, and that is payable on September 30. Off to you, Brian.

Thanks, Bob. On page 5, the summary financial results for the second quarter, we are pleased with the results, as Bob pointed out. Net income improved $4.6 million, or 14.8%. On a fully diluted earnings per share perspective, up $0.08, or 12.3%. I will get into the details throughout the P&L, but at a very high level, we had $20.3 million improvement in gross margin, partially offset by a $17.8 million increase in operating expenses, for a $2.6 million improvement in operating income. Below the operating income line, we did have an increase in interest expense, that was more than offset by an improvement in income taxes, again, resulting in a $4.6 million improvement in net income.

Regarding gross margin, on page 6, regarding that $20.3 million improvement, you can see all of that improvement was in our electric segment of our business. It was up 13.3%, and the high-level items from gross margin, those items impacting net income -- the first three shown there, the Lost Revenue Adjustment Mechanism -- effectively those were deferred revenue we have been deferring over the last three tracker periods.

You may recall, as a result of a tracker decision several years ago, we started booking lost revenue adjustment mechanism revenues of about $7.1 million per year. Over that three-year time period, our LRAM revenues were actually higher than that, but the amount over $7.1 million we deferred. The most -- with the final order that we received in the second quarter on the previous tracker periods, we determined based upon that final order to release those deferred revenues, resulting in a net improvement of $12.6 million for the quarter.

The second item is the $10 million improvement in South Dakota electric rate increase, of course, inclusive of the Beethoven improvement. And the third item is $6.1 million electric QF adjustment. Effectively, we had that adjustment in 2015. In fact, we did not had that adjustment in 2016 as the result of the improvement on a year-over-year basis.

Those are the three biggest drivers, obviously, in our electric and gas business. You don't see a material change in that on a year-over-year basis. What I would argue here is we had improvement certainly in customer loads, good -- excuse me, customer increases on a year-over-year basis. Those are offset by loads primarily due to weather.

The total change in gross margin impacted primarily as a result of those top three items I talked about, was $27.3 million. We do have $7 million of items that reduced gross margins, but those items are offset elsewhere within the P&L. The biggest driver of that is the hydro operations. With the Kerr conveyance we have lower margin in our business as a result of no longer having to pay the Kerr rent, and other items associated with the Kerr conveyance. Net-net, taking all of those things into consideration, we had a $20.3 million increase in consolidated gross margin for the quarter.

On page 7, the second quarter is an interesting quarter for us, we transitioned of course, certainly, from a heating period into a cooling period. I do want to point out at the top of the page those are quarterly numbers, and as you can see at the top of the page, the number of cooling degree days in the quarter are substantially lower than heating degree days.

So, even though June is a cooling degree period, it is actually more of a heating degree period for us. And as a matter of fact, it is one of the reasons we showed -- we broke things out by month, by month on a year-over-year basis. Primarily, we want to point out on the heating degree side, at the top of the page again, on the quarter, an historic average, we're, you can see, substantially warmer in Montana, South Dakota and Nebraska versus normal, and that has resulted in a $5.7 million detriment versus normal, and we will talk about that later. But even on a year-over-year basis, because it was so much warmer in April of 2016 that it was in April of 2015 in Montana, it was a primary driver for an impact on our business.

Moving forward, on operating expenses for the second quarter, you will see operating expenses increased $17.8 million or 13.7%. You can see in all three categories operating: general administration, property tax, depreciation and depletion, each of those went up significantly during the quarter. As you get into the details of that $10.9 million increase in OG&A, the biggest driver was a $20.8 million insurance recovery that we received in 2015. So, on a year-over-year basis, we look $20 million worse as a result of that.

That and the other item, the hydro operations, the Kerr conveyance, not having those operating costs on a going-forward basis, so the result on a year-over-year basis from that item. The following items I would categorize to a great expense as a big part of our cost control. I will take the DSIP expenses for instance, and the other category and those two items are -- captures a lot of the cost control. The total company has really done a nice job during the quarter managing our expenses, and it definitely shows up in those two categories.

If I looked at operating general and administrative expenses at the top of the page, that $10.9 million increase in expenses, of course, would've been about a $10 million decrease had we removed the insurance recovery. So again, it demonstrates how we've managed costs, certainly during the second quarter.

Regarding property taxes, primarily they are up $2.7 million or 8%, primarily the result of plant additions and property valuations in Montana. And lastly, in terms of depreciation, $4.2 million increase, a third of that associated with the Beethoven wind acquisition last year.

Moving on to page 9. In terms of operating income at the top of the page, up $2.6 million or 4.3% as I mentioned earlier, below that, an increase in interest expense, really from three drivers. First and foremost, as a result of the MPSC disallowance on Colstrip, we had interest for that three-year time period that equates to about $2.9 million that we booked during this quarter. We also had increased debt on a year-over-year basis, and we had lower capitalization AFUDC for the quarter, as well.

The other significant driver during the quarter was an improvement in income taxes and really, the two primary areas there really are for higher flow-through repairs, deductions and higher production tax credits. So net-net, again, net income up $4.6 million or 14.8%.

Moving on to the balance sheet on page 10, not a significant amount of change. Obviously we would like to see and continue to increase in PP&E, and increase in shareholders' equity is certainly the case, but as I pointed out, not a significant amount of change. Matter of fact, the ratio of debt to total capitalization stays the same at 55.2%. As of the end of June versus the end of December of 2015.

Moving on to cash flow on page 11. Cash from operations was down approximately $49 million. Really the two biggest drivers associated with that decrease on a year-over-year basis was, we refunded $30.8 million of cash to our large industrial FERC customer associated with the DGGS/FERC ruling. We were required to do that during the quarter, and we did that. Another primary driver was just the $9 million, approximately $9 million difference in net income on a year-over-year basis.

Cash used in investing activities was about the same, around $121 million, and so the main difference in the financing activities is we raised approximately $30 million more debt on a year-over-year basis.

Moving forward to income tax reconciliation. You can see at the top of the page, income before taxes. There wasn't a significant amount of difference between the two, but we did see a $5.3 million improvement in income tax expense in the primary drivers that I talked about: Flow-through repairs deductions increased on a year-over-year basis, production tax credits associated with Beethoven certainly associated with the increase there, and we did have some differences in state income, net of federal provisions for the quarter.

Moving to page 13, non-GAAP adjusted earnings. And we know that there is a lot of information here on this page, but we hope it is helpful to investors. What we are trying to do here, on the top of the page, you can see for the three months ended June 30, 2016 we show our GAAP numbers in the far-left column. With the adjustments we make, either for prior-year adjustments or things like weather, we make those adjustments and move towards a non-GAAP number closer to the middle of the page. We also did the same thing in 2015, going from the far right GAAP to non-GAAP. So the middle of the page on a non-GAAP basis, try to compare results.

If you take a look at gross margin, for instance, from GAAP moving from $211 million to around $202 million on adjusted, non-GAAP basis. Comparing the $202 million to $192.8 million non-GAAP from 2015, you see a $9.3 million improvement or 4.8%. And again, I would equate that primarily in -- reason for the increase is the South Dakota rate case, [exclusive] of Beethoven, and organic growth and primarily the result of good customer growth we have seen.

On the operating expense standpoint, you make the adjustments -- very few adjustments in 2016 -- but in 2015, for instance, adding back the insurance settlement, showing the impact of how Kerr flows through the income statement, you can see comparison on a non-GAAP basis, $147.5 million versus $146.2 million in 2015. There's a slight increase in total operating expenses, $1.3 million or 0.9%. But more importantly, one thing we have been able to do to offset the increases in property and other taxes is depreciation, and we certainly did a nice job of managing our OG&A. And so on comparative purposes, that is actually down 7.5%.

Taking that all into consideration, we saw a nice improvement in operating income on an adjusted basis, $8 million and 17%, flows down to a $6 million improvement in pretax income, and ultimately an $8.7 million in net income, or 37.8% increase. Finally on this page, diluted EPS, Bob pointed out earlier in the call, on an adjusted basis $0.65 versus $0.48 on an adjusted basis for 2015, a $0.17 or 35.4% improvement year-over-year for the quarter.

Moving forward on a year-to-date results on page 14, we do show a $73.6 million year-to-date net income, that's $8.8 million or minus 10.7% variance. On an earnings per share basis diluted, $1.52 versus $1.74, a 22% decline on a year-to-year basis. The primary drivers there, we did show improvement in gross margin but certainly overwhelmed by the increase in operating expenses on a year-over-year basis. So operating income actually down $19.3 million. And I would again point out, the $20 million insurance recovery, if you back that out, we would've seen about flat operating income on a year-over-year basis.

Moving forward to weather on page 15. I think this page might be even more impactful. Just to give an understanding of what we have seen from weather on a year-to-date basis to the -- quarterly -- excuse me, on a 2016 year-to-date versus 2015 in a historic average, significantly warmer throughout all our jurisdictions, resulting in about a $12.8 million year-to-date impact associated with weather. And as you look at the maps at the bottom half of the page on the bottom right, you can just see the hottest spots really versus normal weather in the country happens to be in our service territory to a great extent, in Montana, South Dakota and Nebraska.

If you look to the far left, what might be even more impressive, or we could say disturbing, is in 2016, it was the second warmest period in Montana, the fifth warmest in South Dakota, the fifth warmest in Nebraska over the last 122 years. So, certainly it's having an impact on our business on a year-to-date basis.

Page 16, I won't go into the same amount of detail. For each of the line items certainly the information is there, but the main thing we want to point out, the very bottom of the page an adjusted EPS perspective, back to $1.66 in 2016 year-to-date versus $1.66 in 2015. So the way I would sum that up, and probably best is to maybe move on to page 17. The non-GAAP adjusted EPS perspective through the first half of 2016, again I show the $1.66 versus the $1.66 in 2015. It made up a lot of lost ground from the first quarter.

There is still a lot of work to be done as you see on page 17. For the third and fourth quarters of 2015, we had the $1.49 in the second half of 2015. We need a nickel to $0.20 higher for the remainder of 2016, or $1.50 to achieve -- or $1.54 to $1.69 in order to achieve our $3.20 to $3.35 earnings guidance. So we feel confident in terms of progress we've made in the second quarter that we will be able to achieve that.

With that, on page 18, not any significant changes in terms of our discussion around earnings guidance. We did remove language associated with the Dave Gates Generating Station, in terms of any FERC decision there, obviously that decision has been had, but as we move forward, we feel again as I said, confident we will be able to achieve our $3.20 to $3.35 fourth quarter. And with that, I will but it back to Bob.

Thank you Brian. And on page 19, you see our capital spending forecast out through 2020 and you are familiar with this depiction. A very solid focus on our operating units. You'll see South Dakota electric and Montana Electric, Montana Gas and South Dakota Gas, and then we have identified, as you know, some electric supply needs in both jurisdictions.

So, cumulative estimated capital spend over this period is $1.66 billion, and this reflects a $187 million increase from the capital plan that was included in our 2015 10-K. And about $122 million of this increase is for internal combustion units that were identified in the Montana supply plan, and $65 million for a peaking facility in South Dakota. And the actual spends on these assets would be subject to development of a plan for a clear approach to regulatory recovery. And additional information is available in our 2015 Montana and 2014 South Dakota electric resource plan.

Then we do anticipate funding our identified capital projects with a combination of cash flows aided by NOLs that are now anticipated to be available into 2020, and then long-term debt. And then if other opportunities arise that are not in these projections, such as natural gas reserve acquisition, new equity funding, may be necessary to deal with that.

We have discussed our 2015 Montana electric supply plan in previous calls, and we really do like where we are in Montana right now, with a very diverse set of assets and the ability to focus on some areas where some of our peer utilities have actually been focusing for quite a while. We look like much of the rest of the region in our focus on planning to meet peak need. We look different from our peers in that we have essentially a negative reserve margin and over the coming years, we need to plan to address this operating reserve.

I'm thinking back to an investor meeting that we had a couple of years ago over lunch at one of the conferences and we got the question, well, tell me about your reserves. We don't have any reserves. Look of kind of shock around the table. What do you mean you don't have reserves? So this is one of the needs that we are planning to address.

Turning to 21, put on your cheaters to see what is going on here. To the left is our current capacity, you see a couple of -- these are thermal resources, thermal QFs, CELP and YELP rolling off over the next several years and then, you see on the right, our current plan to meet what we anticipate to be our needs. We refer to this as our economically optimal portfolio, and recognizing that there are various strategies as to how to meet these needs. But in terms of providing our customers long-term least-cost least-risk reliable service, this is the economically optimal approach to doing that.

We did last quarter start including on one page, a regulatory update. On the left side you see the subject matter, and then on the right side, you see the current status. So, from the FERC DGGS, as you know in April 2014, we received what we considered an adverse and very troubling order concerning cost allocation at Dave Gates between our retail and FERC jurisdictional wholesale customers. FERC denied our request for re-hearing ultimately, and we have now made refunds that occurred in June. Also in June, we did file a petition for review with the US Circuit Court for the District of Columbia, and a briefing schedule has not been established there.

You are all aware of the Commission's October 2015 decision eliminating the lost revenue adjustment mechanism in Montana. Brian spoke to the subsequent decisions there. We will, of course, be in future rate cases, we will be recovering our test year costs. In those cases, we are looking at decoupling as an option. We have supported a proposal in our last electric and gas rate case to reestablish decoupling in Montana. Montana actually did have decoupling before supply deregulation, we are certainly encouraged by the Montana Commission's interest in doing an inquiry, probably a roundtable concerning decoupling and they are hopeful to set that this Fall, and we really are very pleased that they are interested in taking another close look at that subject.

The natural gas filing in the October 2015 gas tracker addressing interim rates for our last two of three, two of our three gas production asset acquisitions. The Commission gave us a set of alternatives as to how to proceed but did say that an alternative to essentially true everything up was to file a kind of general, natural gas rate case by October of 2016 to formally bring those assets into rate case, and we do intend to file a general natural gas case by the end of September of this year. And, as we have discussed before, we do a first look for each jurisdiction in the first quarter of the year and did conclude based on that, that it was appropriate to file a gas case in Montana this year.

Turning to Colstrip, in May the Commission, the Montana Commission, issued an order disallowing recovery of replacement power costs that had been included in the electric supply tracker. That concerned a 2013 outage at Colstrip unit 4. In May, we filed a motion for reconsideration with the Commission, the Commission invited other parties to brief that, as well. And the Sierra Club and Montana Environmental Information Center submitted a brief, as did the Consumer Council, that has not been scheduled for action yet by the Montana Commission.

A hydro compliance filing, in December as we were required to as part of the earlier hydro acquisition case, we filed a compliance filing to remove Kerr project costs and to adjust for actual revenue credits and actual property taxes. That was made as a compliance filing. In January the Commission approved an interim adjustment and also opened a separate contested case docket to look at, in greater detail at rate adjustments. And the Montana Commission identified additional issues, requested information. Both we and the Montana Consumer Council have filed testimony there and a hearing is set for September, so we expect the Commission to issue an order in the fourth quarter.

Turning to page 23, an update on the Colstrip/Sierra Club litigation. In March 2013, Sierra Club and MEIC, as we mentioned, filed suit in federal district court against the six owners of the four Colstrip units, and as you are aware, units 1 and 2 are older and smaller units; 3 and 4 are the larger and significantly newer units. NorthWestern has a 30% joint interest in unit 4 and then an operating agreement with Talen concerning joint operation of units 3 and 4. So, essentially, we receive 15% of the combined output of the units.

The original suit was for alleged violations of the Clean Air Act and the Montana SIP. The case proceeded through discovery and litigation for a number of years. On July 12, we lodged a consent decree with the court and in summary, the decree provides that all claims against all units are dismissed. It does not indicate a shutdown date for units 3 and 4. It does provide that units 1 and 2 must shut down by July 1, 2022. And again, NorthWestern has no ownership interest in 1 and 2; decisions about units 1 and 2 will be made by the owners there, and that is Talen and Puget. And then it does permit parties to petition the court for attorneys' fees.

So the consent decree has been filed, under the statute the EPA, federal EPA and Department of Justice have 45 days from July 12 to comment on the consent decree or to intervene as a matter of right. And then we will see what position they take and ultimately, what the court does.

In the appendix, I would urge you to take a look at page 35, which gives a overall picture of our supply portfolio on the electric side, South Dakota and Montana and then combined, and it's a portfolio that we are very proud of. And then on page 36, a slide that demonstrates the real -- the value of the diversity of our Montana portfolio. With that, I will open it for questions.

(Operator Instructions)

Our first question will be from Scott Senchak with Cannon.

In the past, you guys have done a good job with acquisitions to grow your earnings, and I was just wondering in the future, if you are still considering acquisitions, whether they be single assets or entire companies, or what type of things you guys would be interested in or looking at?

Our primary focus really is on the plan that is summarized in the capital slide. We are actually very excited about that. We obviously don't comment on transactions in the abstract. I will say that we have been disciplined about our approach to acquisitions and have focused on assets that do provide value to both our customers and our shareholders, and if those kinds of opportunities present themselves, we are certainly going to be focused on them and pursue them, but do that in a disciplined way. But again, our core focus is on the plan that is identified.

Okay, thanks.

And some of the power plants -- it looks like you are going to be building over the next five years -- do those need some kind of approval or do you start construction, or do you just build them and then get recovery later on? How should we think on that?

It's going to depend on the specific asset. In South Dakota, there is a statute -- it is actually quite a broad statute -- that allows recovery for what are called major projects. Interestingly, that statute has been expanded to include infrastructure more generally. In Montana, there is a statute that provides the Commission, I think, very good tools to evaluate significant projects in advance and make decisions before significant capital is committed. So that is a tool available to the Commission and to us. It is something that we would use when we and the Commission, and then it makes sense. For smaller projects, that is something that would not necessarily be the case.

Before actually going to construction on any project, there is a tremendous amount of work that needs to be done in terms of site selection, project design, the various permitting requirements. And those are things certainly on the soft side of site selection that you can be doing in the run-up to determining, for making major capital commitments.

Got you. So for the Montana IC units, we should see something be filed at some point in the future. Do you have any timeline on that?

Not a specific timeline, no. Beyond what is identified in the supply charts that we included in the material.

Okay. Thank you very much.

Thank you.

We will go next to Paul Ridzon with KeyBanc.

Good morning.

Good morning, Paul.

The cost cuts you had in the quarter -- how sustainable is that savings? Is it kind of one-time? Or how much can you carry through for the rest of the year into next?

I will start and then hand it off to Brian. First, we pride ourselves on running a lean, efficient organization. Just a couple of weeks ago, we shared some benchmarking data with the Montana Commission. So we post up very well against our peers, and that is something that we just build into our ongoing operation and it becomes, if anything, more important this year and into next year. And we start every budget process with a recognition that we have to be able to make changes, smartly but quickly, as the year goes on. So, certainly we want to continue being efficient but we want to do that while we are allocating our resources in the most important way.

Brian can add some color to that.

Yes, I think all I would add, Paul -- I think Bob did a nice job answering the question. I think from our perspective, over the last two years we have seen unseasonably mild weather that has impacted our business, and we need to plan accordingly to that. That might not change materially, and so I think we have just done a nice job -- and this is throughout the Company, by the way -- and I am very pleased with everyone stepping up and looking at it from a cost perspective and trying to manage those things. But be aware that, making sure we do those things that are most important on a going-forward basis as well. So I think we've done a nice job in the quarter; we'll continue to be focused on cost control; but obviously, we want to continue to provide great customer service on a going-forward basis, too.

And with the Dave Gates refund that hit this quarter, that did not flow through the income statement, is that correct?

That is correct.

And then, just, how's the landscape for incremental gas reserve acquisitions? It's been kind of a tough market to transact in -- any changes there?

You are right. It is a tough market to transact. Our folks are certainly actively looking.

And then, any sense of this next court case with Dave Gates? Is this months, is this years? Can you just put one bookend on it?

Most likely, I would say years.

Thank you very much.

It is the federal court system.

Understood.

(Operator Instructions)

We'll go to Brian Russo with Ladenburg Thalman.

Good morning.

Just to clarify -- given that you don't have ownership or a role in Units 1 or 2, there is no replacement power needed for Northwestern as a result of the Units 1 and 2 retirement, is that correct?

That is correct.

A little more color there, though 1 and 2, first of all, serve Puget's customers in the state of Washington. But secondly, Talen 's ownership has been an important asset on the market in Montana for the industrial sector. And as you know, we're the electric supply provider for retail customers, which is a very significant industrial load in Montana that benefits from the presence of those units in the market and avoids the wheel back from the mid-Columbia trading hub, as well. So, the eventual shutdown of 1 and 2 will have an impact in the state of Montana.

Got it. And was Northwestern a party of this settlement or no?

Yes, and the settlement documents make clear that we do not -- that the decision around shutting down 1 and 2 is the decision for the owners of 1 and 2. We obviously were pleased that the decision clears all of the back litigation and uncertainty for 3 and 4; and our interest in unit 4 continues to be extremely valuable to our customers. Again, slide 36 in the appendix is a very graphical illustration of that value.

Okay -- so just to clarify, you were not part of the settlement?

We were a part of the settlement.

You were part? Got it.

And then -- I might have missed this earlier -- but the FMBs that were issued, when did that occur? And then, when did the refinancing occur?

In the second quarter, Brian, we developed the financing that took place.

Okay, so that interest expense savings is embedded in your guidance reaffirmation?

Yes, that is correct. Continue to explore further opportunities to reduce our interest costs.

Got it. And then, is there any potential financial impact scenario of this hydro compliance filing? I mean, given the particular outcome, would there be a financial impact?

I can describe the range of issues. Under the contested case, the focus is on A&G. The Commission raised an additional issue, asking whether there should be essentially a pro rata adjustment at A&G based on the amount of generation associated with care, per relative to everything else. That would be potentially $2 million.

We obviously filed testimony explaining that, in fact those A&G costs are not diminished at all in that way, and then Consumer Council filed testimony that you could look at it two ways. You can look at it essentially the way Northwestern does; or if you did not want to do some kind of a pro rata reduction, the amount would be about $1.1 million, not $2 million. We have indicated that, based on adjustments we think are appropriate, about a $600,000 A&G reduction would be proper.

Brian, anything to add to that?

I think that's fine, Bob.

Okay, great. Thank you.

Since there are no other questions in queue at this time --

Great. Well, thank you very much. I feel like you are letting us off easy, but I will take that, and we'll look forward to seeing many of you over the coming months and visiting with you next quarter. Thank you.