NorthWestern Energy Group Inc (NWE) 2014 Q3 法說會逐字稿

Ladies and gentlemen, please stand by. We're about to begin. Good day and welcome this NorthWestern Corporation third-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.

Thank you, Shannon. Good afternoon and thank you for joining NorthWestern Corporation's financial results conference call and webcast for the quarter ended September 30, 2014. NorthWestern's results have been released and our release is available on our website at NorthWesternEnergy.com. We also released our 10-Q pre-market this morning.

Presenting today are Bob Rowe, President and Chief Executive Officer; and Brian Bird, Vice President and Chief Financial Officer. Also joining us around the table today we have several members of the executive team and they're available for questions as well as we go through this.

Before I turn the call over for us to begin, please note that the Company's press release, this presentation, comments by presenters and responses to your questions may contain forward-looking statements. As such, I need to remind you of our Safe Harbor language.

During the course of this presentation, there will be forward-looking statements within the meaning of the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995. Forward-looking statements often address our expected future business and financial performance and often contains words such as expect, anticipate, intend, plan, believes, seeks, or will.

The information in this presentation is based upon our current expectations as of this 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 our 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 6:00 p.m. Eastern Time today and can be found on our website at www.NorthWesternEnergy.com under the Our Company, Investor Relations, Presentations and Webcast link.

To access the audio replay of the call, dial 888-203-1112, then access code 2111100. Again, that's 888-203-1112, access code 2111100. I'll now turn it over our President and CEO Bob Rowe.

Thank you very much. Obviously, the biggest news for the quarter was Montana Public Service Commission's historic approval of our application to dedicate the hydroelectric facilities we are proposing to acquire to our Montana customers.

I'm tempted to stop right there, but I would also note that we achieved non-GAAP adjusted gross margin improvement of 2.1% for the third quarter as compared to 2013. Year to date non-GAAP adjusted gross margin was up 5.6%.

We achieved improvement of net income of about $14.6 million as compared with the same period for 2013. And that was due primarily to the release of an unrecognized tax benefit and tax method change resulting in an income tax benefit of $18.4 million in the third quarter of 2014.

Our Board of Directors declared a quarterly stock dividend $0.40 per share payable on December 31 of this year. Also notable, Public Utilities Fortnightly released its Fortnightly 40, and we moved up from 38th place to 36th. And as you all know, that's notable because that's based on multiple years of performance. So we're very pleased to be included in the Top 40, and certainly pleased with the movement as well.

So I'll turn it over to Mr. Bird to walk through the financial results. Brian?

Thanks, Bob. On Page 5, we show summary financial results for both three months ending September 30 and nine months ended September 30. For the three months ended September 30, 2014, versus 2013, on net income we had $30.2 million of net income for the three months ended September 30, 2014, versus $15.6 million the prior year's quarter.

That was really drived (sic) by relatively flat gross margin on a year over year basis. Flat operating expenses on a year over year basis, resulting, of course, in flat operating income. I'll get into certainly more detail on each of these matters in a moment.

Below operating income, though, we had increases in interest expense and reductions in other income that were more than offset by the improvement in income tax benefits that Bob just suggested, resulting in the benefit on a year over year basis in net income.

On a EPS perspective, diluted earnings per share were $0.77 for the three months ended September 30, 2014, versus $0.40 from the prior year's period. For the nine month period ended September 30, 2014, net income of $83.5 million, compared to $67.9 million from the prior year.

Here I'll start really talking about from an operating income perspective with $127.4 million through the nine months this year, versus $121.1 million through the nine months 2013.

That improvement on a period over period is primarily due to the strong first quarter that we had. And I think people realize our first quarter was approximately between 40% and 45% of our earnings for the year. And a big driver was the strong first quarter that we had in those results.

Below operating income, we did have, again, higher interest expense. And I'll point out in a minute that high interest expense is really associated with the hydro bridge facility that we have in place. We also had lower other income.

But again, because of the tax benefit that Bob mentioned earlier, that more (technical difficulty) offset of the increases I just mentioned, again, resulting in the vast improvement in net income for the nine months ending September 30, 2014, versus the prior year period. And again, from a diluted earnings per share perspective, $2.13 for the nine months this year versus $1.78 for the period last year.

Moving forward, from a gross margin perspective, our electric gross margin for the quarter was down $4.1 million or just over 3%, whereas our gas was up $3.8 million, which is up about 14.7%. Again, taking into consideration the relatively flat year over year quarterly performance from a margin perspective.

What makes up those components, first and foremost, we had reduction in demand side management loss of revenues of $4.9 million this year versus the prior year. And in the prior year, $2.3 million in 2013 was associated with 2012's demand side management loss revenues. There was adjustment last year for that.

The $1.7 million reduction in gross margin was due to just lower operating expenses recovered in trackers during the quarter. And, of course, that's offset in expenses, you'll note in a minute.

Regarding retail volumes, we're down about $800,000 in terms of retail volumes. A little bit better on the gas side, a little bit worse on the electric side. Net net down, again, $800,000. And speaking about that, just quickly and weather, on a year over year basis we were much cooler in both Montana and South Dakota. And that's the primary driver for this $800,000 reduction in retail loads.

If I could, quickly just kind of talk about normal weather, for the quarter versus normal weather, we did have a warmer Montana, which was offset by a much colder South Dakota. And those two really washed and from our perspective didn't feel that the weather had an impact in our results versus normal.

Moving back to the decrease in gross margin, one of the things that offset the decrease was an improvement in our electric transmission capacity we call oasis revenue. And that's primarily due to ability to wield more power and the fact that MATL line's come online now has certainly helped in that regard.

We have $2.8 million improvement in natural gas production. As you recall, we added gas production in December of last year. And that's certainly helped on a year over year basis but as I'll point out in a second, our gas production business typically doesn't do all that well in the third quarter, relative the other quarters in the year. And lastly, when you include other ultimately represents, gets down to a $700,000 decrease in gross margin on a year over year basis.

If I could, moving over to operating expenses on Page 7. Operating expenses were $126.4 million or $200,000 less than the prior year. Again, very flat quarter over quarter. Decrease in operating expenses are -- and I talk about those first and foremost. Operating and general administrative expenses were actually down $4.4 million, or just over 6%.

But property and other taxes and depreciation depletion actually increased. Property taxes were up about $1.8 million and depreciation depletion up $2.4 million, adding, again, to the slightly decrease, if you would, operating expenses of $200,000.

The primary components have changed in the operating general administrative expenses, a $4.4 million decrease there. $3.6 million of that decrease was associated with non-employee directors deferred compensation. You're probably aware that that is offset in other income and thus doesn't have an impact on our pre-tax earnings at all.

Also, I'd point out the $2.2 million hydro transaction costs, that's a reduction in year over year expense from the prior year's quarter. And then as I pointed out, operating expenses recovered in trackers were down as well in this quarter versus the prior year.

Some good news on the bad debt expenses. We had a $600,000 decrease in bad debt expenses versus the prior year's quarter. But more importantly, it's a vast improvement over the second quarter of this year. Very quickly on that, we did have slightly under $100,000 of bad debt expense recorded in Q3 this year. We had $3.5 million recorded in Q2 of this year.

So as we've noted, we are making -- have made changes to our customer information system. And we would expect to see improvements in credit and collections in the coming quarters. And we saw that immediately here in the third quarter. So that's good news certainly on a going forward basis.

In terms of increases to OG&A expenses, our natural gas production costs were up $2.6 million on a year over year basis. If I could, moving down to property and other taxes. I mentioned that's up $1.8 million, primarily due to plant additions in our Montana business. In terms of depreciation depletion, of that $2.4 million increase, $1.2 million of that is associated with our natural gas production assets.

And for those of you very quick math, you might note that of the $2.8 million improvement in gas production margin from the previous page, in the $2.6 million increase in expense and the $1.2 million increase in depletion associated with our natural gas production assets, quickly do the math, it's a loss, if you will, or at least a $1 million worse performance, if you will, from our gas production on a year over year basis.

No need for alarm because we typically have a loss from that business in the third quarter. Again, because there's just not a lot of volume metric activity associated in the third quarter. That is certainly more than made up for in the first and fourth quarters. And I know I explained quite a bit about that in the second quarter on our last call.

Brian, everyone on this call is quick with math. (laughter)

Thanks, Bob. Moving to Page 8, operating income to net income. At the top of the page, we note operating income of $31 million in three months ended September 30, 2014, versus the $31.4 million. Note the variance there.

But below that, interest expense. We're up $1.7 million in interest expense quarter over quarter. But $1.9 million of that was associated with the expense from the bridge facility associated with the hydro transaction. So otherwise, interest expense right in line with the year over year basis.

And the other expense or income component, our other income was down $3.5 million, again, all of that was really attributed to the decrease associated with the $3.6 million reduction in the value of our deferred shares held in trust for non-employee directors deferred comp. That is impacted by changes in our share price.

And then lastly, from the income tax benefit, and I'll go into more detail on this in a moment, but there was a $20.3 million improvement on a quarter over quarter in income taxes. $12.6 million of that associated with a previously unrecognized tax benefits. The release of FIN 48 reserves. And then the other $4.3 million is the result of an election for the Safe Harbor method related to the deductibility of repair costs.

Those were, again, the primary drivers. The other remaining components would be lower pre-tax income and any other adjustments. And associated with those adjustments, if you turn to Page 9 in the presentation, we lay out what those are for the quarter. We do highlight in yellow the two changes.

Again, the $12.6 million, that release of FIN 48 reserves is associated with non-regulated losses that we had certainly many, many years ago in our business. The $4.3 million is the ability under the Safe Harbor method to elect that to add more clarity around our repairs deductions. And the $4.3 million is a prior year impact of releasing reserves associated with that. You can see how those two items have a significant impact on our taxes for the quarter.

If I move forward to Page 10, just to give an idea of how taxes have flowed for the quarter. Certainly on a GAAP basis at the top of the page, we go first, second, and third quarter. And you get a year to date GAAP number. And you can see on a year to date basis, on the middle of the page, the effective tax rate of minus 12.4%.

When you adjust out favorable weather and a full tax rate, hydro transaction expenses and a full tax rate. And then these two adjustments, both the FIN 48 reserve release and the Safe Harbor election prior year adjustments, at the end of the day you get down to a positive 12.3% tax rate on that non-GAAP adjusted net income. And as a result of that new tax level, from our perspective, it's the primary driver why we changed our guidance from the 14% to 16% down to the 12% to 14% tax rates.

The other thing I'd point out on this page, and certainly bolded at the bottom, I think it's very, very important to point out, even with the hydro assets now included in our business, assuming we ultimately get successful FERC. Indication on our financing, our Section 204 filing, and we're ultimately able to close those assets. When those assets are included into our business, we anticipate the ability to have our tax rate creep up to around 20% through 2017.

Historically, we've noted that. But that was prior to hydro. So even with hydro, our view now is that we'll creep up towards the 20% through 2017. And additionally, on NOLs, we now expect that we'll be able to have NOLs available to us into 2017, even with the hydro reduced cash tax.

Moving forward, Page 11, on the balance sheet, quickly I'd point out there, it's since the end of the year to 2013. So through nine months this year, $160 million improvement of PP&E as we continue to invest in the business. And an increase greater than $50 million in shareholders' equity during that same time period.

And one measure we keep a close eye on at the bottom of the page, in terms of our calculation of debt to total capitalization, slightly down. Down now to 55.2%. So some it's an improvement there as well.

Moving forward to Page 12, our cash flow from cash provided by operating activities improved nine months 2014 versus the nine months 2013 by $34 million. That's primarily related to improvement in working capital. And I guess what I'd point out there is the improvement we've seen in bad debt certainly in the third quarter this year.

It's also shown up in terms of the collections that we've had. That's certainly been a primary driver in changes in working capital. And so it's good to see cash provided from operating activities already over $200 million through the first nine months of this year. And from a cash used in investing activities, and we continue to invest for the benefit of our customers more than we have from the prior year.

If I move forward to Page 13, we do show our non-GAAP adjusted EPS. From a diluted EPS perspective, Q3 we showed $0.77. With the adjustments that we pointed out earlier, the hydro transaction fees and the benefits from income taxes, we make an adjustment and ultimately get down to $0.38 on adjusted EPS perspective.

We would compare that to an adjusted diluted EPS in 2013 of $0.39. So again, in pointing out relatively flat quarter on a year over year basis. On a year to date indication, utilizing the same methodology, we also had weather that we went back out in addition to hydro transaction fees and income tax benefits. On a full year basis, we go from $2.13 down to $1.78. And that $1.78 on an adjusted diluted EPS basis compared to the prior year's level of $1.75. A slight improvement there.

Lastly, we talked about guidance. We have reaffirmed our guidance for $2.60 to $2.75. In order to do that, we're going to need to see a range of $0.82 to $0.97 in the fourth quarter 2014. That's about $0.07 to $0.22 higher than the adjusted $0.75 from 2013. And our expectation, why are we going to be able to do that.

We believe we're going to be able to do that primarily due to customer and load growth, full quarter of Bear Paw South earnings contributions are going to be the biggest drivers. Cost control and a lower effective tax rate will benefit us as well. So our expectation, we'll be able to do that. And certainly to achieve the guidance that we've laid forward for you today.

Moving forward, on Page 14, we wanted to provide a bit of a sausage making, if you will, to get to how we calculated even in an income statement format the adjustments to look at a GAAP and a non-GAAP basis. We even made some adjustments, if you will, as we look at non-employee deferred compensation, so you could see if there's an increase in OG&A, expect to see an increase in other income as well.

We show those movements. And matter of fact, if you take a look at the page, the top left you can see for 2014 we take our GAAP, we identify the items for adjustments. Weather, hydro transaction expenses, I mentioned non-employee deferred comp, and then the tax benefits.

Take those adjustments, you get to a non-GAAP number for 2014, the three months ended 2014 in the middle. On the right-hand side of the page, we do the same thing, but actually move back from the middle from right to left. Take our GAAP for 2013 for the quarter and move back to a non-GAAP for 2013 with adjustments that we had last year.

After doing that, we had a relatively flat GAAP gross margin. But after those adjustments, particularly adjusting out favorable weather last year and the prior year DSM revenue adjustments. Actually on an adjusted basis, gross margin was up about $3.2 million or just over 2%.

If you follow all the way down to pre-tax, (technical difficulty) there's other adjustments, certainly, that happened from that regard going from a $5.7 million difference, if you will, or $11.8 million of pre-tax for three months ended September 30, 2014, versus the three months ended September 30, 2013, that large negative variance, if you will, gets -- is a vast improvement down to a $2.1 million variance at the pre-tax level after these adjustments.

And then when you take into consideration on the net income basis, we do have, as we pointed out earlier, quite a wide band between a $30.2 million GAAP net income down to $15.6 million from the prior year. When you do back out the tax adjustments and -- for the variance I mentioned, or the items I mentioned, plus the tax adjustments for the FIN 48 Safe Harbor, after taking out those adjustments, though, you have a relatively flat net income on a year over year basis. And that flows down to diluted EPS as well, $0.38 for the three months 2014 versus $0.39 for the three months September 2013.

We do the same thing on a nine month basis, also, on Page 15. I won't get into the methodology again. But on an adjusted basis for gross margin at the top of the page, we have a $27.5 million improvement. Think gas production, think gas rate increase, the volume metric improvement.

That $27.5 million or $5.6 million improvement is a decent improvement, certainly, on gross margin for the nine month period year over year. Take that down to pre-tax, again with the adjustments pointed out, $4.2 million improvement, or 5.6%.

And lastly, at net income for the nine month period, $2.8 million improvement, or 4.2%. And again, I mentioned diluted EPS of $1.78 versus $1.75. So a lot of information there. But, again, hopefully helping investors understand the moving parts between GAAP and non-GAAP earnings.

Moving to Page 16, again, reaffirming the $2.60 to $2.75 diluted earnings per share range. We do, as we point out with some of the assumptions, normal weather for remainder of the year. We are excluding hydro-related expenses. We also exclude any gross margin or expenses associated with the assets that we're able to close certainly before the end of the year. And we would exclude that as well from that guidance.

It excludes any potential impact result of any FERC decision regarding the Dave Gates Generating Station. It takes into consideration the new tax range I discussed earlier. And takes consideration diluted shares of 39.3 million.

The last thing I'd point out on this page is this and what we're going to continue to talk about in terms of 2015 guidance certainly fits in with our long-term look in terms of the 7% to 10% total return to our investors through a combination of earnings growth and dividend yield.

And with that, I'll take a breath and pass it over to Bob.

Very well done, Brian. I'll start with a little more information around the hydro project. As you know, we made the public announcement in September of 2013, the $900 million acquisition of 11 baseload facilities, representing a total of 633 megawatts, in addition to one storage reservoir. And that was an acquisition from PPL Montana.

That was the culmination of several years of very, very hard work. On September 26 of this year, after a year-long process, a contested case process, the Montana Public Service Commission issued a final order approving the application, subject to certain conditions that they determined to be in the public interest.

And those conditions included the following. $870 million of the $900 million purchase price would be included in the Montana jurisdictional rate base with a 50-year asset life. The Kerr facility would be excluded. And that was actually based on a recommendation that we made.

Return on equity of 9.8%, cost of debt of 4.25%, and a capital structure of 52% debt, 48% equity. And that would result in an associated first-year annual retail revenue requirement of approximately $117 million.

The Commission authorized issuance in the 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 will be due in December of 2015 to reflect post-closing adjustments, the conveyance of the Kerr project from NorthWestern to the Confederated Salish and Kootenai Tribes and their Energy Keepers Tribal Corporation.

There is to be no financial risk to customers associated with Kerr. And then we would pay the actual property tax expenses for the hydroelectric facilities based on what PPL has paid. There'll be tracking of revenue credits on a portfolio basis through our electric supply cost tracker.

So a very, very thorough examination by the Commission. And a strong order, again, with strong protections for customers. But very strong direction to the Company about our direction.

So now what do we do? On September 26, following receipt of the order, we requested the final necessary approval from the Federal Energy Regulatory Commission. And this is an approval under Section 204 for the financing. The FERC, because we don't have a holding company structure, the FERC wanted to see -- needed to see the Montana Commission order before it could act on the financing approval.

We hope that the FERC can issue that order within 30 to 60 days from the date of filing. Upon receipt of the FERC approval, we plan to close in the permanent financing of up to $450 million of long-term debt and up to $400 million of equity, and $50 million of cash.

If capital access -- if access to the capital market is limited for some reason, we do, as you know, have the option of closing into the $900 million committed bridge facility with Credit Suisse and Bank of America.

One of the conditions directed by the Commission in connection with its approval -- the Montana Commission, is that the Company issue long-term debt with an effective interest rate not to exceed 4.25%. And following that instruction, on September 5, we entered into forward-looking -- into forward-starting interest rate swaps to effectively fix the benchmark interest rate associated with the $450 million debt issuance at a rate that we anticipate would meet the Public Service Commission's condition.

A fourth quarter 2014 close is anticipated, but that is dependent on timely FERC approval. We give you the URL for the web page where we are updating information about the project.

Very importantly, from an operational perspective, John Hines, our Vice President for Supply, would confirm and reported to the Board over the last several days, we are ready to go. And that's a big undertaking with H.R. issues, operational issues, IT security aspects to it.

So although the focus has been, of course, on the regulatory side, all parts of the Company have contributed to get us to this position. And we are not just ready, willing, and able, but really very, very eager to take over operation.

While, of course, much attention has been focused on the hydro project, there's an awful lot of other activity around the Company as well. We do intend to file an electric rate case in South Dakota towards the end of this year. Don't have the details of that filing yet, but it would be based on a 12-month test year ending September 30 of 2014.

Notably, our South Dakota customers have had basically three and a half decades of flat base electric rates. And that's flat in nominal terms, obviously declining in real terms. So the increase is driven by our ongoing three and a half decades of investment in the South Dakota network, particularly our more recent construction of the Aberdeen generating station and our significant [Cleaner Act] compliance expenditures at Big Stone.

Dave Gates Generating Station, in April of 2014, FERC issued a decision, as most of you recall, to allocate only a fraction of the DGGS costs to the first jurisdictional customers. Although we do, obviously, continue to provide the regulation service. In May, we filed a request for rehearing with the FERC, which remains pending.

And it's uncertain what timeline the FERC will act on. And we are, as we've discussed previously, subject to ex parte restrictions in terms of communication. We've deferred $27.3 million of revenue through September 30, consistent with the FERC's decision. If we are unsuccessful on rehearing, we have the right to appeal to the US Court of Appeals. We do not believe an impairment loss is probable at this time. However, we continue to evaluate as facts and circumstances change.

Mentioned the Big Stone Air Quality project. The plant at Big Stone is subject to best available retrofit technology or BART requirements to meet the Regional Haze Rule. The so-called [VIPAP]. And as a result, we and the other owners must install and operate a new system to reduce SO2 and NOx and particulate emissions.

Our 23.4% portion of the project will come in somewhere between $95 million and $105 million and $64.4 million has been capitalized through the end of September. We do expect the project to be operational during the second half of 2015. This has been a successful project, good project management all around.

Our distribution system infrastructure project in Montana, DSIP, focused on both gas and electric, basic distribution system infrastructure expected to be approximately $314 million undertaking with $119 million capitalized to date.

I just can't say enough about what a great job our distribution operations is doing with that project. Our employees are reporting that they're seeing the results and our customers are certainly seeing the results.

We are taking the same kind of systematic long-term approach to all of our infrastructure. And consistent with that, our transmission team has been developing a transmission system infrastructure project. Ultimately, we will be taking an integrated approach to all of our assets end to end as part of an integrated utility. And we're looking forward to communicating with our regulators, our customers, other stakeholders about our overall approach to long-term asset management.

That said, the transmission system infrastructure project would be formally initiated in 2015, with capital expenditures expected to be approximately $150 million through 2018. Again, this is all just very much part of a stewardship approach to the infrastructure that we build, maintain and operate.

Natural gas reserves, this has been one of the unique opportunities that we have had focused on our Montana operation where the interest has been in the acquisition of -- primarily the acquisition of traditional long asset life gas production reasonably adjacent to our gathering storage and transmission system.

We currently own about 25% of our natural gas retail needs. Our goal would be to move that up to 50%. We've invested approximately $100 million so far in that project. We're still actively looking at possibilities as they make sense for our customers and could conceivably invest another $100 million there.

Also, we certainly are looking at strategies to optimize the value of the assets we already have for the benefit of our customers. We'll play a little bit of hot potato here and I'll toss the potato back to Brian.

Thanks, Bob. With our reaffirmed 2014 non-GAAP adjusted EPS guidance range of a dollar -- $2.60 a dollar -- $2.75, and using $2.68 as the midpoint -- as a starting point, we've provided 2015 preliminary EPS guidance range of $2.95 to $3.30 per diluted share. And a 2015 preliminary EPS midpoint of $3.13 a share.

I'm not going to go through each of the primary drivers there that make up that change to come up with the guidance we have. But it's (technical difficulty) to say that a lion's share in the improvement is associated with the hydro transaction.

Taking $3.13 2015 preliminary EPS midpoint of the $2.95 to $3.30 preliminary EPS guidance range for 2015, if you take that range, if you will, I should say, and apply a 60% target dividend pay out range, our preliminary target dividend range of $1.77 to $1.98 with a midpoint of preliminary target dividend of $1.88 per share. Want to make sure people are aware of, again, our desire to continue to provide a 60% payout, even with our increased earnings into 2015.

I think the assumptions are off to the left there. They're very similar to the assumptions that we have for our 2014 guidance, other than the tax rate is a 15% to 19% tax on our pre-tax income. And then a diluted average shares of 49.1 million, the low end of our guidance, and 47.5 million at the high end of our guidance.

Speaking of that, one impact of our range here, the $0.73 to $0.68, certainly all of our sell side folks are very bright out there. One of them did put out a report today that pointed out that that range of $0.73 to $0.68 in terms of the diluted impact of the $400 million share issuance has an approximate range of a $40 to $50 share price issuance, or share issuance price. Excuse me. To get to our $3.13 midpoint.

If, in fact, you were to change that range, assuming our price as we speak today is around $15, if you were to change that range to $45 to $55, the midpoint of our guidance would be moved from $3.13, we would move up to $3.18.

Having said that, the fact that we don't know when we'll receive FERC approval or where the share price'll be at that point in time, we are not planning to change our guidance. And our preliminary 2015 EPS guidance range is still $2.95 to $3.30 per share. But I think people do all understand the impact of the share price on our guidance.

With that, I move to the next page, Page 21. Thinking about net investment in our existing business, we continue to invest at a rate nearly double our depreciation. Matter of fact, in 2009 through 2013, our capital expenditures have cumulatively outpaced appreciation by over $190 million over the last five years. And while maintaining at that time a positive free cash flow for the same period.

One thing I should point out, that's maintenance CapEx. Prior capital spending on the South Dakota supply projects, Big Stone, Neal, Aberdeen Peaker, they totaled just shy of $150 million and they are not included in the CapEx above. And it's one of the primary reasons why we seek recovery of these investments through our anticipated South Dakota electric rate filing in the fourth quarter of 2014.

If we move to Page 22, at the bottom of that page we show what as we reported in the 2013 10-K. As we pointed out in the past, we put in our 2013 10-K is the projects we know we plan to do. Since February, things have changed in terms of our planning process.

Obviously, we've now launched the TSIP project. Hydro is now in the mix. And at the top of the page is our new CapEx forecast 2014 through 2018. And as you can see to the right, that total is $1.45 billion or an increase of $330 million over what was included in our 2013 10-K.

One thing I should point out, those numbers now, they still do not include obviously the $900 million hydro purchase. Nor does it include any potential future natural gas reserve acquisitions.

I think anytime we provide thoughts on what our future CapEx needs are, the first thought on people's minds might be -- what's the amount of equity necessary to finance that? The projects we show at the top of that page, 2014 through 2018, we do not expect to need any equity to finance the capital shown there.

However, if we were to do gas reserve acquisitions or anything else that doesn't show up on that chart at the top of the page, equity may be needed for anything above and beyond shown here. With that, I'll pass it back over to Bob.

Just a couple of closing remarks before we open it up to questions and discussion. As you heard from both Brian and me, we're in a very strong position to continue to invest in providing service to our customers. And planning and executing long-term.

We're incredibly excited about assuming operation of the Montana hydros, dedicating them to serve our customers at prices based on cost. And doing the work to analyze and ultimately optimize the entire Montana generation fleet for our customers.

Although this is a finance call, earnings call, I think it's important to close on more of a personal subject. The wisest public servant I have seen in a very long time is Chairman Bill Gallagher. Many of you have had the privilege to meet him or listen to him.

He is leaving office, leaving public service at the end of this year. He guided this entire process for the last year, and it was complicated and arduous, to a good outcome. Lots of people talk about doing the right thing for future generations. That absolutely was the thing that was first and foremost in his mind. If you had the opportunity to watch any of the hearings, you remember seeing his grandson in the balcony of the Supreme Court chambers at one point.

So I think all the work over the last year has led to a good outcome. And where we sit today is very much part of Chairman Bill Gallagher's legacy to the citizens of Montana that he was so passionate to serve. So I hope you'll keep him in your thoughts as he continues his journey.

And with that, we're open to questions.

Thank you. (Operator Instructions) Paul Ridzon, KeyBanc.

In the past, you've talked about exploring different options for Dave Gates, maybe dispatching it differently. That might change the revenue stream. Do you need to exhaust the legal process before you consider that?

No, not necessarily. We're obviously committed to pursuing the process in front of the FERC. And if necessary, beyond the FERC. But our -- the supply portfolio we have in Montana has changed fundamentally, and fundamentally for the good since Dave Gates came online.

So we are excited about analyzing and optimizing all elements of the fleet to understand how they can work together.

Okay. And I think it was about a year ago you added more nat gas. And you've indicated you're kicking tires. Are we -- where are we in the price stack? And how economic does it look at this point?

The challenge we have there, I certainly think there are acquisitions that would make tremendous long-term sense for our customers. Under the agreement that we have in place with the Montana Consumer Council, there's a forward price threshold.

And given where the forward prices are right now, it would be challenging to -- although, again, acquisitions that we think make an awful lot of sense. Challenging to get those under the forward price threshold. So that's something we have to spend time visiting with the Commission and staff and Consumer Council about over the coming months.

It would be a shame not to be able to execute on good opportunities when they are available.

Understood. And then kind of in your slide deck, I saw a reference to up to $400 million. And then on the formal guidance slide it said $400 million kind of firm. Kind of -- is that how we should be thinking about it?

Brian?

Yes. I think up to is still guidance, Paul. But I think, again, it's also the layer of our capital structure, if you will. So obviously the closer to $400 million the better from our perspective.

Right.

But I -- (multiple speakers)

And, Brian, we --

-- be very -- but, Paul, to be very clear, we're going to be very close to $400 million of equity, is our belief.

Thanks for that. That helps. And then lastly, Brian, when you went through some of the fourth quarter drivers, don't you also have a DSM give-back rolling off?

I don't think we're going to see much of an impact from a DSM perspective on a year over year basis, Paul.

I thought the Commission (inaudible) some back in the fourth quarter.

We think that -- I would tell you that that impact could be upwards of $1 million.

Okay. Thank you very much.

Andy Levi, Avon Capital.

Quite a run down. So I think you've answered most of my questions. Just one question kind of longer term. Just kind of thinking about, at some point, is there some type of, I don't know if you want to call it a cliff. But some type of tax cliff where the rate goes up real quick? And then I have a follow up from that.

No, I think from our perspective, we've given pretty decent guidance of where we think our tax rate's going to go. And again, the tax repairs benefit continues to help us on a going-forward basis. I don't see a cliff. I think the trajectory we provided today is helpful guidance.

So when you get to 18%, 19% or 20%, there's no big ramp up in taxes? Tax rate.

I don't anticipate a big ramp up in taxes.

Okay.

I do expect, Andy, that we'll continue to see upward movement. But I do not see big ramp ups.

Great. And then how does that play -- does it play -- affect rate base at all when you have -- when your taxes are so low? Kind of like a deferred tax? Or not at all?

(inaudible) at the end of the day, the benefits of lower taxes, to a great extent, help -- it's allowed us to stay out of rate cases. Lower taxes typically get passed on the benefit of our customers. (multiple speakers)

No, I understand that. But does it --

It does have an impact on rate base.

How does that work?

Like, it can impact rate base from a deferred tax perspective. That's one aspect. But it's also, the repairs expense itself has an impact from a deduction standpoint. So those are various methods in terms of how it could impact customers.

How does the repair -- is it one for one on the repair tax? Or is there some type of -- (multiple speakers)

We have what's called flow-through items, Andy. Those flow-through items are a dollar for dollar benefit to customers.

Okay, got it. And then --

And, Andy, and I should point that out. Those are captured in the next upcoming rate case, if you will.

Okay. And then on just the rate cases in general, just timing-wise. So obviously you've got the hydro plants in. And we got -- there's a rate increase for that. And then you've ramped up your CapEx. When should we expect you to file your next Montana rate case?

I think we gave very good guidance on what we're doing in South Dakota in 2015. If we had been planning to do any rate case in Montana in 2015, we'd be telling you that today.

Oh, no, no, I understand-- (multiple speakers). Go ahead, I'm sorry.

Brian?

Our expectation is each and every year we'll look at our needs in terms of whether we need to go in for a rate case or not. And we have no guidance today to tell you when our next rate case is. Having said that, as you've seen, we have quite a bit of capital spend from both a DSIP and a TSIP in our plan.

So there will be rate cases in the future. We certainly don't want to give any thoughts of when that could be because we don't know at this point in time if that's 2016 test year or 2017. We don't know that yet. And when we do know, we'll certainly want to give the Commission and investors an indication of that.

Yes, typically, we --

Okay.

-- we do an annual look across all jurisdictions, gas and electric, and make a decision. And the focus for the coming few months will be the South Dakota application. Some of the benefits that you discussed with Brian actually have allowed us, again, to continue to invest in our system while keeping base rates to our customers very stable.

And just remind me again, how long does it take from time of filing till final order for a Montana rate case?

I'd say it's typically a nine-month period for Montana.

Okay.

Just, again, credit to Chairman Gallagher and the Commission, one of the biggest proceedings the Commission has ever dealt with, they stayed right to that nine month clock and ran a very, very rigorous schedule. And that's (technical difficulty) thing to do. There's a lot for them.

And then my last question -- thank you. And then my last question, just kind of you mentioned on the rate basing of E&P and lower -- I guess if it's the lower gas prices, is it the lower oil and per se liquid prices that are affected by oil that changed the economics of the assets? Is that what we're thinking? Or is there something else in your comments.

(inaudible) what we're looking at is the very attractive low price of gas production assets right now. Which suggest it's a great time to do those transactions.

Right.

The one hand. On the other hand, the forward curve for gas purchased in the market is low enough that under the agreement we currently have in place of transactions that we think might be quite sensible, don't pass that screen.

That's because you can buy it cheaper? Is that how it works? Or --

Yes. It's the shape of the curve.

Shape and curve.

Yes.

Yes, okay. And then liquid prices and the price of oil, that has nothing to do with the economics, does it?

That's not what we're looking at. No.

Right. Right. Okay. Great. Thank you. See you soon.

Thanks, Andy.

Brian Russo, Ladenburg Thalmann.

Just curious, it's been a while since you filed an electric case in Montana. But can you self-implement rates?

If I understand the context of the question, no.

Okay. So just whenever you get the final order, that's when rates are adjusted?

We can request an interim rate increase, but we have to get approval of the Commission of that interim rate request.

Okay. Because I think you did that on a gas case a couple years ago. Correct?

Yes.

We have.

You have? Okay. Good. Secondly, on the interest rate swaps, they're quite a bit lower as indicated in the Q than the 4.25% cost of debt threshold. How -- does -- do you retain the difference? Or does that kind of get trued up in that December 2015 filing?

No, everything gets trued up. And obviously -- you said there's a big difference. But you have to add the credit spread, you have to add in the cost associated with that fee, associated with that.

So from our perspective, the 4.25% that was in the final order from the Commission with where we locked in plus credit spreads and fees will be, we believe, somewhere in the 4.20% to 4.25%. But things can happen in terms of spreads.

And if we're higher than 4.25%, we're going to get 4.25%. If we're less than 4.25%, we're going to provide that benefit to customers. That's our --

Okay, under --

-- that's our interpretation of the final order.

Okay, understood. And is there any tracking mechanism recovery method for TSIP or DSIP? Or it all has to be rolled up into base rates in a general rate case?

No. In Montana, there isn't a specific tracking mechanism. What we did, and we've discussed this, was obtain an accounting order from the Montana Commission for the first two -- for the expenses in the first two years of DSIP, since that was primarily expense. And that would've been lost without the accounting order there.

But actually quite a few states around the country have various kinds of specific infrastructure recovery. Trackers, riders for electric, gas and even for water. We don't have anything like that in Montana.

So would you file for an accounting order on the TSIP?

Certainly could. Again, it depends on whether the project has substantial expenses that might be out in front of the capital. That's not necessarily part of the plan, though, right now.

Got it. Okay. And what is that forward threshold that you've agreed to with the MCC? And can -- so I heard your comments correctly earlier, it seems like you guys can revisit that and look to adjust it down.

Yes. I'll tell you, by the time we're off the call, we can walk through -- we can give you the specific threshold. Essentially, the price is tied to -- in fact, I can give it to you right now.

The price is tied to the years in which the transaction has to be positive. So if you look at the 20 year levelized unit revenue requirement dollars per MCF, if that's, again, 20 year levelized, less than $4, the crossover has to be five years or less. Between $4 and five oh -- you -- $5 for the 20 year levelized, crossover has to be four years or less. $5 to $6, three years or less.

So as you see, is the price per MCF levelized goes up. The benefit to customers has to be more imminent. And, again, the unusual thing is the curve right now is kind of rollercoaster shaped, which makes for a bit of a squeamish ride.

But, again, we are looking at the price of assets and think it can be pretty compelling right now.

Okay. And in terms of the 2015 implied dividend, will that take place at the February board meeting? And will it just be one dividend increase? Or are you going to look to do multiple dividend increases throughout the year?

I'll speak to that first, and maybe hand it off to Brian. One of the policies we are very clear about is our dividend range. We, as you know, we've tended to stay closer to the 60% to 70%. But the Board reviews and acts on the dividend on a quarterly basis. Brian?

I'd say, and I totally agree with what Bob said. I think the thing that -- to take into consideration on a quarterly dividend perspective, it would be our expectation that we would pay a 60% payout in February.

And based upon our thoughts for our guidance in -- for 2015 at the time we come to February. So I think on a quarterly basis you'll see that increase in quarterly dividend in February.

Okay, great. Thank you very much.

David Arcaro, Sidoti.

Just a couple of quick questions. How can we think about TSIP, AFUDC, versus going straight into service? Will it be similar to the DSIP program in that regard?

Should be very much the same, David.

Got you. And can you remind me, is that going to be across all states, all jurisdictions and in both gas and electric?

The overall infrastructure approach would be, yes, both gas and electric. And all jurisdictions. The DSIP focus was specifically in Montana because of the size and complexity of the system and the level of need at that time.

In terms of TSIP, most of our transmission assets are in Montana and the focus is there. We're talking about T and D but also I would remind folks that we have substantial substation assets. And again, as part of an overall utility approach to asset management, substations and other assets will be very much a part.

Okay. And then on the South Dakota rate case that you mentioned, when would you expect to get new rates implemented? And are those included in your 2015 outlook?

Brian?

Yes. They -- we have a -- they are included in our South Dakota -- excuse me. They are included in our 2015 guidance. We do have a half-year benefit associated with that. And the assumption would be with a filing at the end of 2014, we would have the ability to have rates in effect for the third and fourth quarters of 2015. And no, I won't tell you how much I have in there associated with that rate base.

Got it. And on that, do you expect to recover anything on Big Stone? Or would you have to get that into service before -- would you have to go back for another case later on to recover those costs? (multiple speakers)

-- those types of costs typically -- that are known and measureable, David, we're able to capture in the rate case. And so that's something that obviously we'd be talking to staff about. But our expectation is the -- one of the reasons, obviously, going at this point in time, too, is our expectation is within 2015 we will be effectively done with Neal. But certainly with Big Stone as well.

And South Dakota does have an environmental rider that would be available for those expenses. We had been out for so long, we believe the appropriate thing was to file a general case.

Obviously, we've been keeping the Commission and staff informed of the Big Stone project from project conception right up to the present time.

I see. Thanks. And one more quick question on the CapEx outlook. What caused such a big increase in the maintenance CapEx for 2016 through 2018 versus your 2013 10-K outlook?

I think in addition we did talk about TSIP to a great degree. But there are some transmission projects included in our maintenance CapEx as well. Is a big driver. But it's -- that's a big part of the driver. But I can't give you a breakout of those on the call today.

But I think about -- we've got various projects right now relatively large transmission projects in the queue right now that have an impact and that are not captured in TSIP. And I think that's the primary driver for the increase.

It's worth noting with the transmission projects that these are jurisdictional projects to serve our existing customers. These are not merchant or speculative projects. But designed to meet current and future needs on our system.

And to add to that, David, if we were to file our CapEx plan, if you will, if it was time to do our 10-K, I'd expect this to be very similar to what we're going to file in our 10-K in terms of our plans. I don't expect much changes between now and February in terms of our plans going forward.

All right, great. Thanks so much.

Jonathan Reeder, Wells Fargo.

Most of my questions have been answered. But one question on the upcoming PSE elections in Montana. Any reason to expect a shift in the regulatory attitude in 2015? Particularly since Gallagher will no longer be serving?

As it was clear from my comments, I think that Chairman Gallagher has been a tremendous public servant. And it's just a great loss, I think, to the state of Montana.

Whatever the makeup is of the Commission, we intend to be as transparent as we can. To try to inform, work with the Commission and the staff on our plans to meet the needs of our customers. And to be really kind of straight down the middle.

So we're looking forward. In fact, honestly, the Commission and staff has been so appropriately focused on the hydro project for the last year, we have an awful lot that we're eager to go and discuss in open meetings with the Commission and staff over the coming months.

And that will be -- would be the same regardless. So, again, Chairman Gallagher's departure is a real loss, but we look forward to working with whomever takes his place.

Is there, I guess, any historical precedent on the, I guess, the district he represents five. Does it always go Republican? Or is there any way to kind of speculate on that?

Not for me, there isn't. (laughter)

Okay. And then last, one project that you guys haven't touched on in a while, I didn't know if there was anything kind of new to update on that would be the 500 KV upgrade to the coal strip transmission line. Where does that stand?

I'll turn it over to Mike Cashell, our VP or Transmission. Mike?

Yes. The one thing I'd say about that is that there are no customers in our transmission queue that are awaiting for that capacity. And in fact, Bonneville recently announced that they've stopped their environmental assessment of that because of the transmission queue situation on their system. So I would say that right now it's not moving forward.

And I'd add to that, it is not included in our plans in the five years that we've just shown you. And matter of fact, Mike's so busy working on other transmission projects, they dwarf the $40 million odd that we had associated with the -- our share of that 500 KV upgrade. So I hope that help -- answers your question, Jonathan.

It does. Thank you very much.

(Operator Instructions) And with no further questions in queue, I'll turn the conference back over to management for any closing remarks.

Okay. Well, thank you all very much for our good discussion and for your interest. We're eagerly looking forward to visiting with many of you at the EI Financial Conference in Dallas. And probably others of you in New York City at the end of the year. Look forward to seeing you soon.

And ladies and gentlemen, that does conclude today's conference. We do thank you for your participation. You may now disconnect. Have a great rest of your day.