NorthWestern Energy Group Inc (NWE) 2014 Q1 法說會逐字稿

Good day and welcome to the NorthWestern Corporation first-quarter 2014 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.

Thanks, Stephanie. Good afternoon and thank you for joining us for NorthWestern Corporation's financial results conference call and webcast for the quarter ended March 31, 2014. NorthWestern's results have been released and the release is available on our website at www.northwesternenergy.com. We also released our 10-Q premarket this morning.

Joining us today on the call are Bob Rowe, President and CEO; Brian Bird, Vice President and Chief Financial Officer; Kendall Kliewer, Vice President and Controller; John Hines, Vice President of Energy Supply; Mike Cashell, Vice President of Transmission; and myself, Travis Meyer, Director, Investor Relations.

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 Act -- excuse me, Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995. Forward-looking statements often address our expected future business results 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 as -- and disclosed in the Company's 10-Q, which we filed with the SEC this morning and 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 at www.northwesternenergy.com under Our Company, Investor Relations, Presentations and Webcasts. To access the audio replay of the call, dial 888-203-1112, then access code 9765855. Again, that's 888-203-1112, access code 9765855.

I will now turn it over to President and CEO Bob Rowe.

Thank you, Travis. We are joining you today from our general office in Butte, Montana. We have had a very successful Board meeting and annual meeting, although we did have cool temperatures and light snow, but in Montana, it is -- springtime is always just around the corner.

We also had, as we always do, a couple of neat side events. We had a great employee meeting this morning from folks who work in our grid control center and folks in our customer care center, including some of the people who were leads on the customer information system project and we continue to be pleased with the results that we are seeing there.

And we had a tremendous community meeting, over 200 folks. It really turned into kind of a revival meeting with so much enthusiasm for a lot of things that we are doing, but particularly enthusiasm for the Hydro acquisition.

A couple of other highlights for the quarter -- we saw an improvement in net income of approximately $7.7 million as compared with the same period last year and that was due primarily to the impact of our acquisition of natural gas production assets in Montana and the colder winter weather.

We were very pleased in January to receive from Moody's an upgrade on the secured side from A2 to A1 and unsecured from Baa1 to A3 and the Board declared a quarterly stock dividend of $0.40 per share, payable on June 30.

Now I will turn it over to Brian for the financial results.

Thanks, Bob. The summary financial results on page 5 shows at the bottom of the page on a diluted earnings per share basis for the first three months of 2014, we had $1.17 per share versus $1.01 the prior year's period, a $0.16 increase or approximately 16% increase on a year-over-year basis.

Moving to the next slide, as I speak to gross margin, from a gross margin perspective, the first quarter we had $202.3 million of gross margin compared to $180.8 million in 2013 or a $21.5 million increase or almost 12%. So you can see above is -- from electric margin and gas margin, that primary increase is really from the gas side of our business.

As you look below, for the increase in gross margin, natural gas production, primarily the addition of the South Bear Paw asset, really resulted in that increase on a year-over-year basis.

Secondly, we had electric retail volume improvement. We did experience a benefit of our Montana gas rate increase. That was effective last year, but on a year-over-year basis, certainly an increase. And then natural gas volumes -- $3.2 million. So all in all, $21.5 million. Very, very good quarter, certainly on a year-over-year basis.

From an operating expense perspective, on page 7, our operating expenses were up 5.7%. Operating expenses in dollars $130.9 million versus $123.8 million in 2013. That increase of $7.1 million or 5.7%. So you can see, by the percentage increases, property taxes was a major driver from a percentage increase for the quarter.

Matter of fact, down below, you can see a $3.3 million increase in OG&A expense; $2.2 million of that is natural gas productions. So obviously, with more natural gas production margin, we have had expenses, production expenses, associated with that. $1.6 million in labor expenses; $0.8 million in Hydro Transaction costs.

One thing I would point out here, if you excluded the natural gas production costs and you excluded the Hydro Transaction costs, you would see that from an OG&A perspective, we were relatively flat on a year-over-year basis.

That makes particular sense when you consider in 2013, we started our DSIP program. We had a pretty decent increase in expenses starting in 2013. As we continue that program, we have seen that our OG&A expenses level out.

Regarding property taxes -- talked about that, a $2.7 million increase there and a $1.1 million increase in depreciation expense. We certainly had an increase due to plant additions, but as a result of our depreciation study that we performed last year, that helped offset some of that increase from added plant additions.

Moving on to page 8, operating income to net income. You can see operating income itself, $71.4 million, versus $57 million the prior year a $14.4 million increase year over year. Interest expense below that was up $3.2 million, but $1.9 million of that increase was associated with the Hydro Transaction.

There was really a cost associated with the bridge facility that is in place, really, as an insurance policy if ultimately we are able to close that transaction and capital markets aren't available. We can utilize our bridge facility to close the transaction.

On other income -- other income actually was down $0.5 million for the year. We did have lower AFUDC. You might remember last year in completing the Peaker plant we had a bit higher AFUDC on a year-over-year basis there.

Lastly, we did have higher income tax expense, primarily due to higher pre-tax income, but we also did have a higher effective tax rate for the first-quarter 2014 versus the first-quarter 2013.

Moving on to the balance sheet on page 9. Assets increased about $36 million. That was right in line with our growth in PP&E of about $40 million from the liabilities.

And equity, isn't this interesting? It also increased by $36 million, as you expect, but that is primarily related with a $44 million increase in shareholders' equity. So our -- as we would hope to with an increasing growing business, as we continue to invest in our business, we are seeing our PP&E grow with it.

On a debt to capitalization basis, as we see each first quarter, we tend to see our ability to pay down debt and the seasonality that shows up in our debt to cap. We were at $53.6 million for the first quarter versus $55.7 million at year end.

That primarily is a result of cash flows that we collect in the first quarter, helped us pay down our short-term borrowings and that, coupled with the increase in shareholders' equity, allowed for a reduction of our debt to capital well within the range of our 50% to 55% targeted range.

Page 10 is our cash flow statement. Cash provided by operating activities is relatively flat, around $112 million. We did get some recovery of our accounts receivable in the first quarter. You may recall in the fourth quarter we were lagging a bit there. We are seeing some recovery.

We expect to see more of that in the second quarter, but a bit of a rebound there. The primary reduction, if you will, from a comparison basis on changes in working capital is really primarily a result of undercollection of supply costs.

In terms of investing activities, we did have an increase in investment on a year-over-year basis and net-net the excess cash flow remaining was used to pay down our short-term borrowings during the quarter.

On page 11, our adjusted EPS schedule -- I talked about $1.17 from a GAAP perspective. As all of you that participate in these calls understand, we do try to equate back earnings, and based upon a normalized weather, we did deduct $0.05 in weather, but we did also add back about $0.04 of hydro-related costs, both within our OG&A level and in our interest expense.

But after those two adjustments, we are at adjusted diluted EPS of $1.16 again versus the $1.01 from the prior year. A note at the bottom of the page -- regardless if it is on a GAAP basis or non-GAAP adjusted basis, we had approximately a 15% improvement on a year-over-year basis for the quarter.

On slide 12 is 2014 earnings guidance. We are affirming our guidance of $2.60 to $2.75 on an EPS basis. One thing I will point out in addition to normal weather, it is very clear, it is in bold, that we do exclude any hydro-related transaction fees in our guidance and any potential income if, in fact, we are fortunate enough to close on the Hydro Transaction.

And then the next thing I would point out, our guidance excludes any potential impact as a result of a FERC decision. And what I should point out here is primarily what we are talking about there is if in fact there is any impairment determined between now and the end of the year, that would be excluded from our guidance as well.

And with that, I will hand it back over to Bob.

Thank you, Brian. We will deal with the bad news up front. As you are aware, we did finally receive a decision from the full FERC, the Federal Energy Regulatory Commission, affirming the ALJ's decision.

A little bit of background for anyone who isn't following this quite as closely. You can think of NorthWestern Energy at the time the plant was built as neither fish nor fowl. We were essentially a Montana wires-only company in an unorganized market and, operating a large balancing authority, have the legal obligation to provide regulation service for all customers, both retail, state jurisdictional, and wholesale FERC jurisdictional.

Dave Gates Generating Station was built to meet a specific need. We were not in a reliable way able to meet on the market. The Montana Commission did the right thing and granted us advanced approval before construction. We brought the project in, actually, $20 million under budget in December 2010, and then went in for an after-the-fact review at the Federal Energy Regulatory Commission.

But based on significant discussion with FERC at the policy level, including in commissioners' offices, ran the gauntlet of the contested case process and received what we consider to be a negative, very negative decision, resulting in significant undercollection in September of 2012.

Notably, no party really disputed either the need for the facility or the revenue requirement. Indeed, even the FERC trial staff, the advocacy staff, stipulated to a total revenue requirement. We sought reconsideration in front of the full FERC, and 20 months later, finally received a decision that was really for the most part, with the exception of a couple of paragraphs, a pro forma affirmance.

We are obviously most troubled by the outcome, but the process, to me, certainly is dismaying. I don't say that about a regulatory body lightly. We are reviewing our options. Obviously, the decision was issued while we were preparing our quarterly SEC filing.

I did determine that no impairment was required at that time, but we will continue to evaluate that on a quarter-by-quarter basis. And as you saw, we are reaffirming our guidance on an annual basis.

The legal and regulatory option that we are focused on right now, and we are on a 30-day shot-clock, is the decision whether or not to request rehearing, and rehearing is a precedent, then, for appealing to a Federal Court of Appeals. So that is another important area of focus. I expect we will have interest in further discussion around that.

Moving on to -- and I should add, by the way, that the plant is in fact working the way it is supposed to work. We believe, operationally, the three-unit design has proven to be the right design, the smart design, and our customers, both retail and wholesale, are receiving the service we are obligated to provide them.

Moving on, though, to other projects. An update on our environmental compliance projects at both Big Stone and Neal. Neal is basically through. We came in -- it was substantially completed in 2013, ahead of schedule. It is in service and that was a MATS compliance project. Our share about $22 million.

Big Stone moving along very, very well. Great relationship with the other owners there. We have capitalized so far about $49 million. Expect our total share to be $95 million to $105 million and the project is on time for 2016 completion.

We have been talking about natural gas reserves for a number of years. We have made three acquisitions. The most recent was the largest. We refer to it as Bear Paw South. That was folded into our rate base through what we think is a really very effective process at the Montana Commission on December 1.

The employees who joined us as part of the acquisition are great and adding a lot of value as well. Factoring in depletion, which is an annual part of operating gas production, we are able to provide about 32% of the gas requirements for our Montana retail customers.

You see at the bottom of page 15, what I refer to as the roller coaster slide, the stable gas T&D and storage costs, and then the roller coaster of natural gas supply costs. So our premise had been that acquiring long asset lives, nonspeculative gas production when the market was relatively low, would provide real value.

Well, so our largest acquisition came on board on December 1 and our customers have been enjoying the benefits of that price stability all winter long. If they have any regrets -- and I have quoted them Commission Chairman Gallagher to this point, before, when we made the first acquisition -- it is that we did not at the time own more.

We do continue to be out looking at the market, obviously interested in optimizing our owner -- the resources we own already and looking at what would be further cost-effective acquisitions.

So we are very pleased from a utility operations standpoint, a corporate standpoint, and most especially from what we are able to do for our customers with that part of ownership.

We've also talked over time -- you have been with us as we have been developing the Distribution System Infrastructure Project, or DSIP. This is really an exciting project. Touches many, many folks all across the Company. Significant CapEx and O&M undertaking. After three years of planning and ramp up, we are now starting our second year of full production.

Curt Pohl, our head of Distribution, Mike Cashell, head of Transmission, and I just finished a tour of all of our Montana locations and that included all-hands meetings and then small group meetings. And when we asked the folks who have their hands on the system, are you seeing the results of what we're doing, the answer is absolutely yes.

So this is really exciting. And it is exactly the kind of thing that a responsible company needs to do.

Turning next to Hydro Transaction. I mentioned we did have a little bit of a revival meeting with customers and community leaders here in Butte a couple of nights ago. You have seen a number of these slides before. When we look at a major project, we look at it in terms of our risk screening, our mission and vision, what's the advantage to our customers, our communities, our employees, and our investors.

And this is obviously a very, very large project. One that because of a lot of discipline and focus we are able to execute on and one that does benefit all of our stakeholders.

As you know, we announced the transaction late September, had a prefiling meeting with the Commission, arranged bridge financing, filed our application to approve the purchase in late December. Have been working through the discovery process ever since then, actually making great strides on the federal as well as the state level.

In March, we received an order from FERC approving transfers for the facilities other than Kerr. Kerr is being treated separately because of the interest of the Confederated Salish and Kootenai Tribes there. I will come back and speak to that.

On the Montana side, one thing you might be interested in, in fact, the Commission has the ability under its additional issues procedure to instruct parties to address issues that the Commission believes are of note that aren't addressed in the initial testimony.

So the Commission did issue a couple of additional issues, primarily having to do with diligence and with future costs to maintain the facilities.

Last Friday, we filed our testimony -- supplemental issues testimony. It is a concise filing. It is available online. It is a good read, and I think the takeaway is that our diligence team did a very good job and these assets under any range of future scenarios provide tremendous value for our customers.

Turning back briefly to the issues at Kerr Dam. As you know, the Confederated Tribes, to their credit, participated in the licensing procedure, relicensing procedure, for Kerr in the mid-1980s and were able to achieve a specified formula under which they could acquire ownership of Kerr Dam.

It was anticipated at the time we entered into our transaction with PPO. The arbitration process between PPO and the Tribes has completed and the Confederated Tribes received a very favorable order.

We are essentially neutral in that process. We have a good relationship with the Confederated Tribes. And we are working with them on training and transition. But it certainly is good to have that piece set to the side, we believe.

The Commission, Montana Commission, is doing a neat thing. They are holding 19 listening sessions all around our Montana service territory. They have been through the first eight or nine so far, and we are really gratified by the way community leaders and citizens, customers, are turning out.

And we have included on the bottom of page 18 and the bottom of page 19 some of the statements from the people who have participated at the hearings.

Such as the first quote from Dr. Tom Power (sic -- see slide 18, "Powers") is from -- he is quite an outspoken activist in Montana, a well-regarded economist. And he has filed testimony that is very supportive of the transaction. He's an intervenor on behalf of a low income group and the National Resources Defense Council. So again, we are very encouraged by that.

The listening sessions will continue into mid-May. The technical hearing, the formal hearing, is set at the Montana Commission starting on July 8. Under the current schedule, we would hope to see an order on September 16, barring any extraordinary circumstances.

And I really appreciate first of all, the Commission's determination to stay with the procedural schedule and the care with which they are approaching this proceeding.

And secondly, the incredible amount of work that our employees who are participating in this, from regulatory, legal, finance, and supply, pulling together the workload in the regulatory process and all other aspects of this transaction, operational and others, are daunting. And everyone is rising to the occasion, because they know how incredibly important this is to our customers, to the Company, and really to the state.

We talked before about financing. On approval, we do plan to close into permanent financing of up to $500 million of debt, $400 million of equity, and $50 million of free cash flows. If the 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.

This is parenthetically, both on the equity and debt side, a very good time to --- for a transaction like this and we are hopeful that we will be able to successfully close and, again, do something we think is really pretty great all around.

With that, I am going to stop talking and you can address your questions to Brian.

Are there questions?

(Operator Instructions) Paul Ridzon, KeyBanc.

Good afternoon. I had one question about the seasonality of the earnings out of the gas assets. I was surprised at how strong the contribution to the first quarter was. Is that volumetrically tied to gas sales or can you just run through that?

Yes, Paul, this is Brian. It is volumetrically tied to that, but the first quarter should be the lion's share of the benefit from the gas production assets, anyway, particularly on a year-over-year basis. As you might expect, our first and fourth quarter are going to be our strongest, based upon our winter needs from a gas perspective.

Second and third quarter are going to pretty much wash -- not going to be much activity there. But when you consider the fact that this asset closed in December 1 of last year, on a year-over-year basis we're not going see as much of a benefit in the fourth quarter as we saw in the first quarter here.

So from a gas production benefit, it was no surprise to us that we saw the bulk of the benefit from the gas production assets in the first quarter on a year-over-year basis.

So was it exaggerated even more because the weather was so cold?

It is because there is a bit more of a draw on the fields themselves, so yes.

Okay. Thank you very much.

Brian Russo, Ladenburg Thalmann.

Good afternoon. In the 10-Q you guys filed today, you mentioned that you are evaluating options to use DGGS in combination with other generation resources to ensure full cost recovery and therefore do not believe an impairment loss is probable. Can you elaborate on that?

Yes, and I am going to be fairly general at this point. You can think about what we are doing in three areas: first, obviously, finance and accounting; second, legal and regulatory; and then third, operationally. In terms of finance and accounting, we will be evaluating the need for any impairment on a quarter-to-quarter basis, but again at this point we don't believe an impairment is necessary.

On the legal and regulatory front, our focus right now is whether or not to file a request for rehearing at the FERC, leading, most probably, to an appeal.

On an operational level there, first of all, we are providing essentially -- and no matter what the FERC administrator logics may say, we are providing the amount of regulation service that we can provide with the facilities that we have available right now.

There may be additional -- we believe there probably are additional services that that asset can provide as well. The -- where it gets interesting is that in -- on a going-forward basis, we hope we will look really quite different a year from now than we did in 2008 when this project began.

And we have been saying since the hydro project was announced that one of the things that we are excited about is the ability to optimize an entire fleet of resources. And our Montana resource set we hope a year from now will include hydro, will include wind, will include our interest at the coal strip and then Dave Gates Generating Station.

So we are looking at a range of different services the plant could provide. And the challenge is, we have the obligation to provide regulation and we chose the most cost-effective and from an engineering perspective best approach to meet that obligation for this Company.

Correct me if I am wrong, but you are uncertain whether you will ask FERC to rehear this case. Why wouldn't you?

There are expenses associated with the request for rehearing. We are actively -- I think I can say we are actively preparing for that possibility so we are doing everything necessary, but what we don't want to do is just kind of in a knee-jerk way pursue one course. But don't be surprised if we do file, let's say that.

Okay, and then throughout the FERC written order, it seems like one of the primary reasons why they upheld the ALJ decision was that they claimed NorthWestern failed to provide evidence why it would be unable to utilize the energy generated by the reserved regulation down capacity for non-regulation purposes.

Can you explain in your own words why you disagree with that? Or how -- why is this plant designed where you can't sell into the market?

Yes, and then that really --

-- Which would offset the revenue requirement.

That goes to the core. And, again, just for those who aren't following this quite as closely, there are probably three sets of issues. The first is what we refer to as the numerator issue and that is essentially how much is available, then the denominator, and then the fuel cost.

But the concern about whether or not we can sell product into the market and provide reg down as kind of a one-off product has to do, again, with the fact we don't have -- did not have at this time -- an integrated large fleet of assets. And to the degree -- depending on what the product is, but to the degree that you are selling most products into the market, you don't have that asset available to provide reg down.

So we look fundamentally different from a vertically integrated company in a non-organized market providing a service, really, on the shoulder of a large fleet. And, Mike, you want to add into that?

I would add one thing. Back in 2008, when this project was conceived, and then in 2010, when we filed with the FERC Commission, we were replicating the contracted service that we had purchased in the marketplace for years that had been approved by FERC, which included 60 megawatts of regulation capacity up and down and recovery of the cost associated with that as well as the recovery of the energy costs.

So we had no reason to believe that the methodology that we proposed for recovery of the cost associated with DGGS would be handled any differently than the approved cost we had been recovering under the contracts prior to DGGS.

That's Mike Cashell, our Vice President for Transmission. And, again, we are providing through our own assets essentially the same service that we were providing under contract.

Okay. And on the Hydro Transaction, it looks like the agreed-upon price for the Kerr Project, PPL Montana will pay NorthWestern the difference of $11.7 million. How does that work? Does that get credited to customers?

Well, you could -- no. Although there is a sense in which you could look at the project netted out to customers. And, again, I would -- you could think of it as, I suppose, an $870 million project ultimately from a customer perspective. And again from -- as we were negotiating with PPL, we knew that there would be an event associated with Kerr.

We knew there was a range of outcome somewhere between what the Tribes advocacy position was near arbitration of what PPL's position was. And so we picked a midpoint and then a mechanism to basically true up so that we would be neutral.

John Hines, our VP of Supply, anything to add there?

No.

Okay. And remind us of your dividend policy and when the Board is expected to review the dividend the next time?

Brian?

Yes, we discuss dividends at every Board meeting, as you probably have been aware, Brian. We typically make changes in our dividend in February after our annual results have been provided. And we discuss as a Board our plans for the upcoming year in terms of guidance, if you will.

So my expectation is if we are successful in closing the Hydro Transaction, we would discuss dividend policy. But I would also say it's likely we wouldn't make a decision on dividend policy until February the following year.

And I think, Brian, just to be clear to your earlier question, dividend policy currency is 60% to 70% payout ratio and we have been at the low end of that range in light of the amount of capital that we have. I don't see at this point in time that that would change.

Okay. Thank you very much.

Jonathan Reeder, Wells Fargo.

Good afternoon. Brian, if you could, you showed that the weather was a $0.05 positive in the quarter, but that the electric and natural gas retail volumes had a $0.14 positive impact on gross margin. Does that imply that the non-weather-related usage growth was a $0.09 positive?

Yes. We had, from an electric standpoint -- we anticipate on the electric side that weather didn't have as big an impact on the electric side as it did on the gas side. We did see quite a bit of improvement in our commercial loads.

They had been down the last two years and we saw a bit of recovery in commercial loads this year. Primarily that's the primary reason for the increase from the electric side.

So the $0.05 is pretty much all weather on the gas side?

Yes.

Okay. And then what would be the other part on the gas side for the gross margin increase, that is just due to volumes?

I think you have to take and consider, obviously, weather is a big part, but we did have increase in customer and volumetric growth from that increase in customers.

So we should look at that other $0.09 as hopefully sustainable going forward?

Correct. We are seeing a bit of recovery from customer growth that's impacting overall usage per customer as well, in addition to what we have seen from the weather perspective.

Okay, great. Then on the DGGS, if you filed for recovery under Section 10 as FERC almost suggests in its order, at least for a portion of those revenues, would that be separate from the appeal? Or would that be part of the appeal process?

I am going to ask Mike to speak to this. And if we could follow FERC's suggestion there, those are not necessarily easy paths. For example, Schedule 10 is a regulation service for intermittent resources. We don't have customers taking under Schedule 10.

Schedule 4 is another option, a potentially separate filing, but there would be parties who likely would participate in that proceeding as well. So it is not as if we simply picked the wrong door and other doors are going to be easy to pass through. Mike.

Really no additions to that, other than to clarify that to answer the question, either a Schedule 10 filing or a Schedule 4 filing would be separate from a request for rehearing.

Okay. And then, Bob, do you see any impact on the timing of the MPSC's, I guess, potential approval of the Hydro deal due to the recent determination that they wanted some more supporting rationale regarding the Hydro CapEx and O&M projections you provided versus what intervenors and other consultants came up with?

So, and again, the Commission has done, I think, a great job and our regulatory folks have done a great job staying with the schedule. The additional issues process was contemplated in the initial schedule. We filed on time and we are very comfortable with where we are.

In fact, actually, I very much believe that the additional issues testimony really affirmed -- very much affirmed -- the quality of the diligence that our team internally and our outside consultants did initially.

So that was a real value added to the process, I think. Parties had the opportunity to file discovery on that and there will be an opportunity for other parties to respond as well. That is coming up and then, of course, the next big date to look at in the technical part of the hearing is when we file rebuttal on May 9, and, again, we are all working very hard on that.

So in your opinion the hearings are on track still for, I think it is July 8, and then you think the final decision can still come by the current deadline and that the Commission won't need to extend it?

Yes, at this point, again, there have been no surprises and people have worked very, very hard to stay on schedule and so far, so good.

Okay. And then just out of curiosity, if the Commission would determine that your projections are too low and should actually be a little higher, how sensitive is the economic benefits of the transaction to those current assumptions that are called into question?

What I do urge you to do is actually read the supplemental cover to cover. First of all that includes our own professionals on staff speaking to the work that we did.

Secondly, testimony from two outside experts, one of whom, looking at the materials, says actually the going-forward costs could be a little bit lower than what we had projected.

And then ultimately testimony from, in fact, one bold face named Travis Meyer with testimony from two of our folks saying that under any scenario there is extraordinary positive value to our customers from this transaction. So we think it is, again, to quote Dr. Power, a no-brainer.

Okay. Thanks for the additional comments.

(Operator Instructions) Paul Patterson, Glenrock Associates.

Good afternoon, guys. Just to follow up on this DGGS stuff. First of all, when you mentioned the alternative methods of the plant being dispatched, or what have you, and the regulatory approval that you would need that, subject to read. What would that regulatory approval be? Would that be from FERC?

There are both FERC and state responsibilities. So depending on what you do, there will be future filings on both sides. We're pretty early to speculate too much on what those might look like.

Mike, do you want to speak to that anymore?

No, I think that is right on with what we already described in terms of the couple of schedules available to us at FERC. Yes, you are right on, that we are just a little too early in the process now to predict.

Okay. Your previous comments on Schedule 10 and Schedule 4 kind of suggested to me that those would not be necessarily likely paths. Is that referring to Schedule 10 and Schedule 4? Or is there something else?

No. I think what we -- what you should know is, again, currently, we don't have customers under Schedule 10. Schedule 4 certainly is a possibility, but there are other parties out there who take some set of services from us to would say: no we don't think Schedule 4 is the proper door; we think Schedule 3 makes the most sense.

And I guess I would say that the final order that was the strongest indication from FERC that recovery of costs for our variable costs, for fuel, primarily, the route would be scheduled for us. So we are looking hard at that.

Okay, and then when -- the comments, I guess, when you were talking to Brian about it's not a knee-jerk response to file for rehearing, would filing for rehearing cause any issue with respect to these filings? Or, put it another way, I guess just in general experience, it often seems that rehearing a request, rehearing it is kind of a knee-jerk response, if you follow me.

So it is a little bit noteworthy, maybe, or perhaps not, that you guys sound a little bit more cautious on that. And I'm just wondering if you could elaborate a little bit on that, because like I said, usually it seems like that is standard move in so many of these proceedings.

We are just not a very knee-jerk bunch out here, I guess, is what I would say. The day we received the order, again, we started doing a lot of work in all three of those areas that I mentioned. Including, very much including, doing the groundwork for a rehearing with the understanding that that could well be the precursor to an appeal.

Okay. Would that have an impact on filing under Schedule 4, Schedule 3, or what have you?

It should not based on the FERC decision.

Okay. Thanks so much.

We have no further questions at this time.

Well, it sounds like we better get while the getting is good, then. Thank you very much for your support and interest this quarter. Look forward to visiting with you again next quarter and seeing a number of you in person between now and then. Thank you very much.

And this concludes our conference. Thank you for your participation.