NorthWestern Energy Group Inc (NWE) 2014 Q4 法說會逐字稿

Good day and welcome to the NorthWestern Corporation Year-End 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.

Thank you, Kevin. Good afternoon and thank you for joining us NorthWestern Corporation's financial results conference call and webcast for the year ended December 31, 2014.

NorthWestern's results have been released, and this release is available on our website at NorthWesternEnergy.com. We also released our 10-K premarket this morning.

For any of you logging in, in the webcast we have had a few reports of trouble logging into the webcast. We know some of you are logged in but we do have the full slide deck, as always, loaded out on our website as well under the Presentations and Webcasts at NorthWesternEnergy.com.

Presenting today are Bob Rowe, President and Chief Executive Officer; Brian Bird, Vice President and Chief Financial Officer; we also have several members of our executive team with us in the room today that are available to ask questions if they come up. 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 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, speaks, 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 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 10-K, which can be we filed with the SEC this morning, and our other public filings with the SEC.

Following this presentation, those of you joining us by teleconference will be able to ask questions. The archived replay of today's webcast will be available beginning at 6:00 PM Eastern time today and can be found on our website at www.NorthWesternEnergy.com under the Our Company, Investor Relations, Presentation and Webcasts link.

To access the audio replay of the call, dial (888) 203-1112, then access code 525-9563. Again that is (888) 203-1112, access code 525-9563. I'll now turn it over to our President and CEO, Bob Rowe.

Thank you Travis, and happy birthday.

Well thank you, Bob.

And we are calling in today from our Sioux Falls office. I will start with some recent activity and then turn it to over to Brian.

In November, as I am sure all of you know, we completed the purchase of the 11 hydroelectric facilities in Montana with a total of 633 megawatts of capacity and one storage reservoir for an adjusted purchase price of $904 million. And to finance the transaction we accessed the capital markets and issued $400 million of common equity, 7.77 million shares at $51.50 a share, and then $450 million of 30-year Montana First Mortgage Bonds at a fixed rate of 4.176%.

Just a word more on Hydro, you will see the photo on the cover of the deck, our Thompson Falls Dam, and I had the real pleasure of visiting community leaders in Thompson Falls just a couple of weeks ago along with our dam foreman and our account manager on the distribution side. Had a great conversation about how important NorthWestern was to the community of Thompson Falls; it reminded me of the long-standing community roles that we play in larger cities and smaller towns, but also I think the really exciting environmental role that we are taking on with the acquisition of the dams and 600 to 700 miles of riverfront. So it's been, to me, a positive transaction from that perspective as well.

Back to the significant activities, we had $26.7 million of net income improvement in 2014 as compared with 2013, and gross margin improvement from energy supply acquisitions and income tax benefits that were recognized. That was partially offset by higher operating costs and hydro transaction expenses. We'll come back and discuss that.

We had non-GAAP adjusted EPS of $2.68, that's a 7.2% improvement over 2013 adjusted EPS of $2.50. Our 2014 adjusted EPS was at a midpoint of $2.60 of our guidance range of $2.60 to $2.75, we had an upgrade of our senior secured and unsecured credit rating by Fitch in November, and notably a 20% increase in our quarterly stock dividend was announced by our Board of Directors, and that's $0.48 per share payable on March 31 of this year, and with that, off to Brian Bird.

Thanks, Bob. On page 5, I show the summary financial results for the 12 months ended December 31, 2014. In 2014 our net income was $120.7 million, or $26.7 million increase over the prior year. Diluted earnings per share, that was in 2014, $2.99 which was a $0.53 increase over the prior year.

Moving ahead to page 6, I will get into greater detail on the P&L itself. From a gross margin perspective gross margin was $722.3 million in 2014, which was an increase of $47.4 million or 7% increase over the prior year. We had nice increases in both our electric and gas businesses.

Of that $47.4 million, the three primary drivers were the $21.4 million increase in natural gas production, $20.5 million in hydro operations, and $5.9 million from our electric transmission or OASIS revenues during the year. We did have an improvement in retail volumes and a full-year impact of our Montana natural gas rate increase, those were offset by reduced tracker revenues and via some lost revenues during the year.

Moving on to operating expenses on page 7, we had total operating expenses of $544.3 million, which was a $40.4 million increase or 8% increase overall versus full-year 2013. On the operating, general, and administrative expenses, they were up about $20.3 million or 7%. The three primary drivers for that increase, $8.9 million increase in natural gas production costs, a $5.5 million increase in hydro operating costs, a $5.1 million in hydro transaction, legal, and professional fees.

Other operating expenses included a $9.1 million increase in property and other taxes, about a third of the increase during the year was associated with gas production assets and the hydro assets. The other remaining two thirds [of primer] just an increase in methodology from a property tax perspective and additional capital additions as well. We also had $11 million increase in depreciation and depletion expense during the year, and about two thirds of the increase was associated with our gas production and hydro assets during the year.

Moving on to operating income as a whole was $178 million which was $7 million higher than the prior year, and the items below operating income, for instance interest expense, was up $7.3 million in 2014 versus 2013. The primary drivers for that were associated with the hydro transaction. We had $3.9 million from a bridge credit facility associated with the hydro transaction and we had $2.4 million of interest expense associated with the $450 million Hydro debt deal. We had other incremental debt costs from an issue that we did in late 2013 that were offset by other interest expense, favorable variances for the year.

From an other income perspective, other income was up $2.5 million, that was primarily driven by the $1.7 million gain on deferred shares held in trust for our non-employee directors deferred comp programs. I think as many of you who follow the business are aware, when we have an increase in that category in our operating expenses, we also will have an offsetting increase in other income. And that was certainly the case again this year.

So our pretax earnings were $110.4 million, which is a $2.1 million increase over the prior year, and then from an income tax perspective, we actually had an income tax benefit of $10.3 million, which was a $24.6 million improvement over the prior year. The three primary drivers of that large improvement was a $12.6 million release of unrecognized tax benefits that occurred in the third quarter.

We've also had a higher-level $7.5 million of flow-through repairs deductions this year versus the prior year, and $5.7 million returned to accrual adjustment, especially with the Safe Harbor election. Those again were the three primary reasons for the improvement in taxes for the year.

Moving on to the balance sheet on page 9, our balance sheet today at the end of 2014, we have nearly $5 billion of assets. Just a quick note, that's about double of what we had back in 2005 or slightly after we came out of bankruptcy, to a nice improvement in assets and particularly our PP&E.

As it notes in the top right of that slide, that's 34% increase in total assets in 2014 versus 2013, primarily driven by the hydro transaction and continued investment in our system. From a shareholders' equity standpoint, that also has increased of course, not only with the share issuance, but continued earnings from our business that's upwards close to $1.5 billion at this point in time.

At the bottom of the page we do show our debt to cap. We show that as a year-end number at 56.3%. That is slightly above our targeted 50% to 55%, primarily due to seasonality of cash flows and on an average for 2014, we are at 54.6%; we do anticipate that to remain near 55% and on average within our 50% to 55% range during 2015.

Moving on to our cash flow statement on page 10, we are happy to report that in 2014 we did have a recovery in our cash flows from operations as we noted we should. We did have a $56.3 million improvement in cash flow and driven primarily from higher net income and the improved collection of customer receivables and then we're happy to say that we feel very, very good in terms of the recovery we've shown there. We've taken that cash flow and with some financing activities, invested over approximately $1.2 billion in PP&E additions during the year, of course $900 million of that is associated with the hydro transaction.

Moving on to page 11, talk about our non-GAAP adjusted EPS at the top of that, well, to the far right of that page I would note that our non-GAAP adjusted EPS of $2.68 is $0.18 or a 7% improvement over our 2013 non-GAAP earnings. And to kind of work our way to our $2.68, I'd take you to the top of that page.

We started with reported GAAP diluted EPS of $2.99. We did back out $0.02 of favorable weather. We did add back $0.24 associated with hydro transaction costs that we incurred during the year.

We did back out $0.14, the net benefit of operating our Hydro facilities for the last 45 days, approximately, of the year. We did add in $0.08 for the Hydro equity dilution that resulted from our share issuance that wasn't in our original guidance. And lastly, we did back out $0.47 associated with the income tax adjustments to get us to our $2.68 and again, an $0.18 improvement over 2013's $2.50 a share.

On page 12 I'll very quickly point out what I just shared with you in terms of our non-GAAP adjusted numbers; this shows how those flow through a full P&L perspective. The one thing I'd highlight, obviously at the bottom of the page again you see the highlight in yellow, the $2.68 versus the $2.50, and you see the components that make up those changes. I would note at the pretax income line, even after all the adjustments we did see a nice $6 million improvement in pretax income on an adjusted basis, or a 5.4% improvement there.

Moving forward to page 13, one of the significant items that did adjust -- our adjusted earnings were on the tax side; this page tries to capture the non-GAAP effective tax rate. You see highlighted in yellow the three items that up to $18.5 million of impact on the net income that we did remove from our GAAP results to get to our non-GAAP results, those items were a $12.6 million release of unrecognized tax benefits that occurred in the third quarter, $4.3 million of a cumulative adjustment for election of Safe Harbor method related to deductibility repair costs for years prior to 2014. We had a $1.3 million adjustment for benefits related to 2014 bonus depreciation that we did not contemplate in our guidance, and approximately 300,000 other prior-year adjustments.

One thing we would want to point out as we talk about our tax rate, effective tax rate, we do anticipate that our tax rate over time will move up to be approximately 20% through 2017. And through the years we expect, like I said, that to ratchet up to about that level by then, and additionally we expect NOLs to be available to us into 2017 to reduce our cash tax.

Moving forward, on page 14 discussing our 2015 earnings guidance, to the far right at the top you see our $3.10 to $3.30 a share. That, of course, is to the right of a nice trend line, if you will, from both, not only a GAAP earnings results shown in the blue bars, but also our adjusted GAAP earnings based upon the redline there shows those. So in 2014 we had $2.99, again the GAAP earnings shown there, and with the $2.68 shows up within our guidance range for 2014.

Back to the 2015 earnings guidance of $3.10 to $3.30, we do show our general assumptions there, especially with normal weather. We do exclude any impact associated with the FERC decision on the Dave Gates Generating Station. We do show a 15% to 19% tax rate, and then we do have diluted average shares of approximately $47.1 million.

Lastly, I would point out we believe as we continue to move forward into 2015 and beyond, we do expect to have targeted 7% to 10% total returns for our shareholders and a combination of earnings growth and a strong dividend yield. Moving to page 15, just this breaks out really how we come from our $2.68 2014 non-GAAP adjusted diluted EPS up to our $3.20. I won't get into each of those measures but I know a lot of you will want to dig into those and potentially ask questions; the information's here.

That increase, by the way, from $2.68 to $3.20 was approximately a 20% increase and thus gave the Company the comfort to offer, as we did today, the 20% increase in our dividend of $1.92 a share on an annualized basis. Of course we announced the $0.48 for the quarter this year. But on an annualized basis, again $1.92 per share.

With that, I will put it back to Bob.

Thank you Brian, I appreciate you highlighting 2014 but also taking us back and reminding us just how far we came [from emergence], and that's a great success, obviously, for our shareholders but our customers as well. I'll continue with some more detail around some highlights, starting of course with the hydro acquisition, which is now complete.

In late September, after a year-long, very, very thorough process, the Montana Commission issued a final order approving our application to purchase the hydro facilities at a total of 633 megawatts from PPL Montana, and subject to certain conditions that I'll run through. We've included $870 million of the $900 million purchase price in rate base with a 50-year asset life, return on equity of 9.8%, cost of debt of 4.25% and a capital structure 52% debt and 48% equity, and that resulted in a first-year annual retail revenue requirement of approximately [$117] million. The Commission authorized issuance in aggregate of $900 million of securities necessary to complete the purchase with the debt portion of the financing to have a term of 30 years and not to exceed 4.25%.

A final compliance filing is due in December of this year to reflect post-closing adjustments in the conveyance of the Kerr project to the Confederated Salish and Kootenai Tribes, and that's to be accomplished with no financial risk to customers, and then the actual property tax expense for the hydroelectric facilities would be included in the compliance filing.

We'll have tracking of revenue credits on a portfolio basis through our electric supply cost tracker. We successfully completed equity and debt financing, $400 million of equity, that's 7.767 million shares that were issued at $51.50 a share, and then $450 million of 30-year First Mortgage Bonds with a 4.176% coupon.

4.353% is the estimated all-in cost of debt including the upfront costs and the hedge amortization, and again a 4.250% cost of debt is what is recoverable under the Montana Commission's approval for transactions closed on November 18. Slide 17 includes some detail for you around shareholder-incurred hydro-related costs, and this is broken down first of all by year, starting with the last two quarters of 2013, all four quarters of 2014, and then specific detail around a loss on the interest rate hedge and the equity issuance fee, then broke down again by legal professional fees, bridge financing, the loss on the hedge, and the equity issuance fees, so a total depicted here of just under $50 million. We certainly think that that is a very defensible contribution by shareholders to obtain this great bit of assets.

A second notable development towards the end of last year was the South Dakota rate filing, this is something we've discussed for a number of years, usually in response to the question, when are you going to file in South Dakota? And we finally have.

And this is, again, no one likes to file rate cases, and customers certainly don't like to have them filed, but the story that's depicted on slide 18 is extremely positive, and what you see in the upper left is extraordinary stability in the fixed charge and energy portions of the bill going back well into the 1980s, and then even fairly modest adjustments in the tracker-related portions of the bill, fuel transmission had the lower impacts, and that's a nominal number. Then you drop down to look at the nominal rate in real terms, and an extraordinary value for customers.

Over on the left side, upper left, is a breakdown of what we have requested in the filing: equity at 10%, and 53.61% equity, and debt at 5.18% for an overall rate overall rate of return of 7.76%. We think that's very, very attractive from a customer perspective and that's on a rate base of $447.4 million. And down at the bottom you see allowed revenue and rate base in 1981 as compared to 2014, and you see the revenue deficiency and the justification for the requested increase.

The case has been filed and [eventually] closed last Friday. A number of industrial customers have filed with intervenors in South Dakota. We are, of course, vertically integrated.

There isn't a procedural schedule issued yet by the South Dakota Commission, but we do look forward to working through this case with and in front of the Commission. Other activities summarized on page 19, Big Stone Air Quality Project, and this is subject to Regional Haze Rule requirements, are a 23.4% portion of the total project now projected to cost between $95 million and $105 million. We capitalized almost $72 million through the end of 2014, and we do expect this project to be complete and in operation by the second half of the year.

Our distribution and transmission system investments, we've talked about our [dista] project over the years, which is gas and electric distribution in Montana. Very successful project, great project management on that, and we're taking the same approach now to our transmission infrastructure and we intend to essentially broaden the programmatic approach to include transmission as well as distribution including substations, and it would be our entire system rather than the specific Montana focus that we had under the so significant capital expenditures over the next five years of about $340 million, we will come back and give you a little more detail on that.

Natural gas reserves, we do currently own about 25% of our Montana natural gas needs, that's factoring in both retail and power gen, and our investments so far have been dedicated to serve just our retail customers and we've invested about $100 million through the end of last year. We have a target to meet at least 50% of our overall need over the coming years, we'll have to come back to talk about that a little bit in the discussion as well.

Dave Gates Generating Station, our perennial subject, as most of you know in April of 2014 the Federal Energy Regulatory Commission issued a decision to allocate only a fraction of the costs to FERC jurisdictional customers. In May of last year we filed a request for rehearing which remains pending, and we, as far as we know, are not on the procedural calendar for next month at FERC. Consistent with the FERC's decision we have deferred $27.3 million of revenue through the end of 2014, and if unsuccessful on rehearing, we certainly will take a close look at appealing to the US Court of Appeals.

We evaluate for an impairment on a quarterly basis. I don't believe an impairment is probable at this time, however we do continue to evaluate facts and circumstances.

A couple of things that I'm really very, very proud of in 2014, we had the best ever year for safety at NorthWestern across the Company and that's a big deal. It reflects so well on our employees and approach to safety and is notable because we haven't had a busier year just in terms of work being done in the field and across the Company, and high-quality work, high levels of work, and very high levels of safety. We also received our best ever customer satisfaction scores on the J. D. Power's overall satisfaction survey, and again we're very pleased with that.

We cost-effectively brought two separate legacy customer information systems, one which has supported South Dakota and Nebraska, and one which supported Montana onto a new combined platform. And compared to our peers we're particularly pleased with the functionality now that we finally have a stable system and the overall cost. So we think we took a good approach, did a lot in-house, high level of attention from senior Management, a very hands-on approach, and we like the platform that we have now.

I'm every bit as proud of our recognition in 2014 as a Corporate Governance Award winner. We were recognized for our best proxy statement for a small to mid cap company by Corporate Secretary Magazine. As I've said before, that's the Oscars or the Emmys or whatever for corporate governance and our corporate secretary Tim Olson was on hand to accept that award. And we were recognized, we had been recognized as a finalist in this category in both 2012 and 2013.

And then finally, we were recognized as a Top Trusted Utility Brand by Cogent Reports, and we were one of 53 companies nationwide to earn that honor, but even more significantly we were recognized as the top regional, in the Western region of the United States, combined electric and natural gas utility in terms of earning the trust of our customers, so that meant a lot to all of us.

Turning to our capital spending forecast, and as you know we tend to be very WYSIWYG in terms of what we actually project and include on tables like this. So this does not include any future natural gas reserves that we might acquire, does not include future peaking generation or other acquisitions. This is based on what we know and what you see is maintenance CAPEX continuing out through 2019, ongoing DSIP expenses, you see Big Stone as I mentioned being completed this year, and then our Transmission System Infrastructure Project, which ultimately really rolls into just an overall infrastructure project. Then our identified hydro-related capital on all of that. So it's a significant amount of capital, $1.45 billion for 2015 through 2019, and we do anticipate funding this with a combination of cash flows aided by our NOLs and by long-term debt.

So I talked more than you wanted to hear me talk, and with that we'll open it up for questions.

Thank you.

(Operator Instructions)

Paul Ridzon, KeyBanc.

Just latest thoughts on potential timing of more nat gas reserves and any progress that's been made with MCC around the test of (multiple speakers).

Good question, good place to start. I don't want to talk about specific projects; I know you're tired of hearing me use the metaphor kicking tires and my toes are getting sore. But there has been, actually, a significant change since we discussed this last fall and I described the test, which essentially requires a showing of net customer benefit over a period of years, and the higher the price the more immediate you have to show that benefit.

And the challenge that I described on the last call was essentially that prices were very low but the curve was very flat. What's happened since then, prices are obviously still extremely attractive, but the curve now does show a pretty clear customer benefit, so we think this is a much better environment in which to pursue transactions, and we are still kicking tires but kicking tires with more optimism that we can find transactions to pass that test.

Thank you, and any sense of the timing of when you're going to meet incremental peaking capacity?

I'd say a couple things there. We filed our South Dakota electric plan just a couple of weeks ago and that's available online, and that identified a need for online capacity in 2019. And we're a couple years out from that, but we do have to start some more serious planning well in advance, and that might be around a 50-megawatt need. There are a number of ways you could meet that need.

Our folks did meet with the South Dakota Commission staff and begin discussion of the plan, it's a very positive process working with the South Dakota staff and we'll expect to get any questions from them and answers. On the Montana side we'll be filing our plan at the end of this year and we expect we will be talking about needs there. And you've all probably seen our Montana light load heavy load chart, and our hydro acquisition does help us meet light load for the next several years, but we do have an unmet need for peak and even super-peak assets, and that's something that we will be describing to the Montana Commission and the plan when we file that.

On the South Dakota side, did you say in service in 2019?

Yes.

Thank you very much.

Dan Eggers, Credit Suisse.

From an economy perspective, with slowing, not exactly with you guys but in the region, slowing activity of oil and gas drilling and ancillary jobs and activity, are you seeing that having an impact on load outlook or what we should be watching externally to see if that has any ring-true effects to you folks?

I'll start and hand it off to Brian.

We -- the good news, bad news, two years ago we were pretty envious that we did not directly serve the Bakken. We ring in South Dakota and certainly in Montana; now we're not feeling maybe quite so badly about that. We do serve a staging area, really, for the Bakken, probably out of both states, but certainly out of Montana in places like Billings. And there's been a lot of economic benefits in our service territory as a result of that. But I would say that generally the local economies are a little more diverse.

One of the things I really enjoy doing in January, I travel around with the University of Montana Bureau of Business and Economic Research attending local economic events. There's a lot of diversity and energy in most of our local economies. There certainly are concerns about slowdown in the Bakken, and that probably translates into not a lot of new activity, but what we're hearing is generally existing projects are much less likely to be affected.

And as you get further away from the immediate impact areas, again we've got -- we've been saying this for years, we're not flashy but it's steady, and there are periods where there's really pretty tremendous growth. Bozeman is starting to look a lot more like -- the Bozeman Big Sky area is looking a lot more like it did back in 2006, 2007.

And actually one further comment there, we started our DSIP project, because it was the right thing to do, but we started it at a time when we were not racing quite as hard to keep up with growth and now all the processes and structures associated with our infrastructure program are in place. They're working well and it seems that we're much better able to work to accommodate the growth where we're seeing it.

Brian?

I would just add that we are seeing, certainly, upward pressure on new connects pretty much throughout the system, but as Bob pointed out, definitely in pockets in places like Bozeman. I don't want to get people too excited that that translates into a lot more growth because this is a utility that has pretty steady growth, pretty much throughout our economic cycles that we've seen, so, but certainly encouraged by the new connection information we're seeing in 2014 and continuing into 2015.

Any if any you want to build or buy second homes, now is the time to do it and we guarantee you high-quality affordable service.

That's a fine offer, I appreciate that. I guess the next question is on bonus depreciation, what should we be thinking about as far as the effect of bonus this year, both from a cash flow and then from an effect on the tax rate maybe this year, years out, as you expect that to start trending higher?

I think from a bonus perspective, obviously this is retroactive back to 2014, and we saw the pick-up there. And since we didn't consider that in our guidance we excluded it as we discussed. We don't anticipate much of a benefit, of course, of any bonus on a going-forward basis. And quite honestly, Dan, I wish the government would quit doing bonus on a going-forward basis.

Is it affecting the rate base and the way we should be paying attention to it, or is it still kind of small enough given your tax position we don't need to think about it?

I don't think you need to think about it on an ongoing basis.

Okay, and then just going back to the gas reserve conversation as you get them more comfortable with the task, can you just remind us the process of when we could see an agreement on a new math behind benefit and then progression to prospectively-announced projects and when those could go into rate base?

I don't think we need any new math; with the curve as it is right now this is a significant change from last fall. We think we ought to be able to do transactions that pass the test as it is so the challenge now is just moving forward and identifying projects and closing on them, and then we'd bring those in initially through the existing gas tracker mechanism.

Would you be of the mind if you did not get that $100 million committed this year that it would be a disappointment now?

No, and the per-unit prices for gas, of course, are much lower. We view this as an ongoing process and we would expect that you would see a number of different transactions over a period of time.

The one thing I would add to that, Dan, is obviously there is an expectation that gas prices stay low, but from our perspective we've seen changes in how the curve works. So, obviously, as Bob pointed out this would be an attractive time, and so to say that we would be disappointed or not would be one thing, and we would be disappointed if things change with gas prices going up or the curve changing on us. I guess that's the best way to answer that.

So the shape of the curve is where you get the confidence relative to where you're seeing reserves for sale effectively? Is that the difference?

Yes, but I think in fairness Bob's commentary on kicking tires, you always have to have a willing buyer and a willing seller at a reasonable price and that's still something we need to consider.

Are you finding people with this downturn and some cash constraints in the E&P world, are you finding more interest in folks cutting deals than they were, say, six months ago, or is that climate similar?

Probably don't want to comment on that.

Okay. Thank you.

Brian Russo, Ladenburg Thalmann.

A lot of my questions have been asked and answered, but I was just curious, since you discussing the regional economy, what should we assume in weather-normalized load growth or customer growth?

At this point time, until we see that translate to any changes I would continue to expect to see 1% customer and load growth as an overall metric, Brian.

Okay, great, and then you mentioned some peaking capacity that you might need in Montana, can you quantify the amount of capacity?

That should probably wait until after -- until we're worked through the plan. What I would say in addition to that, I think I've mentioned our intent to do this before, but we are undertaking an optimization study of our Montana fleet, and I think that's the first project to complete. So, we understand what the fleet looks like operating together, what the opportunities are there, and then that's one of several inputs into a Montana Electric plan.

Did the unrecovered portion of David Gates as it stands now, could that fill the need for peaking capacity and are you going to include that in this optimization study?

I can't answer the question about outcomes from the study, but yes, Dave Gates is, along with the other Montana facilities, is included in the study, yes.

And when will that be filed and made public?

The optimization study is something that we're doing internally because we need and want to know what the total set of values is that we can achieve through the fleet. The Montana Resource plan will be filed before the end of this year.

Okay, and you mind commenting on any capital markets or external capital needs for this year?

Yes Brian, I think it's in fairness we talk about our capital slide that we've shown in the past and on that slide. It pretty much talked about we can finance this plan without any equity needs. Obviously if we were to do something the gas reserves standpoint, that can make things a bit lumpier and we may need to have some equity to help finance that.

I would go on to say from our perspective, there always is an opportunity for us to do some things from the debt side to balance out our capital structure and we typically will look at refinancing opportunities and things like that. So from a total capital markets perspective that runs the gamut.

Okay, and then lastly on the impairment test that you do on the David Gates Station on a quarterly basis, hypothetically if FERC chooses not to rehear the case, would that trigger an impairment? Or would it not because you'll likely appeal it in a court of appeals and then therefore (multiple speakers).

I would say this, Brian, if they didn't hear it or it was a negative outcome from a rehearing, that doesn't help, that doesn't necessarily result in impairment at that time as we continue to evaluate this on a going-forward basis, and obviously the optimization Bob is talking about is something that we believe should help us manage through that.

Okay, great. Thank you very much.

(Operator Instructions)

Brian Chin, Merrill Lynch.

I'm sorry if I missed this in the earlier prepared comments because I missed the part of the call, but is there a schedule out for the South Dakota rate case, or can we get a sense of key dates coming up between now and interim mid-2015?

Just to recap that a bit, and there is some information in the deck on the South Dakota filing, interventions were due last Friday. There were, I think, four interventions from industrial customers. There is no procedural schedule yet.

Okay, great. And then on Montana, I know that there was some thought of thinking about going in for a rate case sometime in 2015 or late 2015, maybe 2016. Any better sense of timing as to how you're thinking about the timing of that process?

No, really can't comment on that right now, no.

Understood (multiple speakers).

Brian, what I would add on that, as we've said on earlier calls, and you might not have participated in those, is what we typically do at the end of each year as we evaluate where we've come out. We don't anticipate based upon where this year's come out based upon a 2014 test year, that will be filing in -- we will not be filing in Montana this year. We already are obviously in the South Dakota case. We won't know when we would file next in any jurisdictions, probably until this time period and maybe even up through into April of 2016.

Very good, very good. Thank you, the rest of my questions were asked and answered.

(Operator Instructions)

And there are no further questions at this time.

Okay, great. Well, thank you all for your interest, look forward to seeing some of you at conferences over the next couple of months and we'll be speaking again next in April.

Ladies and gentlemen, this does conclude today's conference. We thank you for your participation.