Northwestern Energy Group Inc (NWE) Q3 2014 Earnings Report, Transcript and Summary

Good day, and welcome to the 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 the release is available on our website at www.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 are 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 expects, anticipates, intends, plans, 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 PM Eastern Time today and can be found on our website at www.northwesternenergy.com under the Our Company, Investor Relations, Presentations and Webcasts link. To access the audio replay of the call, dial (888)-203-1112, then access code 2111100. Again, that’s (888)-203-1112, access code 2111100. I’ll now turn it over to 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 hydroelectric facilities we are proposing to acquire to our Montana customers. I am 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 a 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 of $0.40 per share payable on December 31st 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 five 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, '14 versus '13, 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 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 the 127.4 million through the nine months this year versus 121.1 million through the nine months 2013. That’s primarily -- 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 is approximately 40% to 45% of our earnings for the year and a big driver was the strong first quarter that we had in those results. Below low operating income, we did have again higher interest expense. As I will point out in a minute, that higher interest expense is really associated with hydro bridge facility that we have in place. We also had lower other income. But again because of the benefit, the tax benefit that Bob mentioned earlier, that more than offset 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%, and again taking into consideration other 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 from 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, we’ll go 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 on 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 cooler South Dakota and most are 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 to offset the decrease was an improvement in electric transmission capacity we call OASIS revenue and that’s primarily due to [releasing] (ph) more power and the fact that [MAT Line] (ph) has come online now has certainly helped in that regard. We have 2.8 million improvement in natural gas production. As you recall, we added our gas production in December of last year and that’s certainly helped in 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 to the other quarters in the year. And lastly, when you include other, ultimately represents, gets down to 700,000 decrease in gross margin on a year-over-year basis. 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. The decrease in operating expenses, and I talked about those first and foremost, operating and general and administrative expenses were actually down 4.4 million or just over 6%, but property and other taxes and depreciation/depletion actually increased. Property taxes are up about 1.8 million and depreciation/depletion up 2.4 million, netting again to the slightly decreased operating expense 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 a non-employee directors deferred compensation. You are probably aware that that has offset in other income and thus doesn’t have an impact on our pretax 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 just 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’re making -- have made changes to our customer information system and we expected to see improvements in credit 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. 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 with math, you might note that the 2.8 million improvement in gas production margin from the previous page and the 2.6 million increase in expense and the 1.2 million increase in depletion associated with natural gas production assets, quickly do the math, that’s a loss, if you will, or at least a 1 million worse performance if you go 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 volumetric activity associated in the third quarter. That is certainly more than made up for in the first and fourth quarter as I explained quite a bit about that in the second quarter on our last call.

Brian, everyone on this call has quit by now.

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, our interest expenses were up 1.7 million and interest expense quarter-over-quarter of about 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 other 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 previously unrecognized tax benefits. The release have been 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 are 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 have more clarity around 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, probably on the middle of the page, an effective tax rate of minus 12.4%. When you adjust that 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, you get, at the end of the day you get down to a positive 12.3% tax rate at non-GAAP adjusted net income. And as a result of that, your tax level from our perspective is the primary driver, while we changed our guidance from the 14% to 16% down to the 12% to 14% tax rates. The other thing I would point out on this page and certainly [bolded] (sic) 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 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 have NOLs available to us into 2017 even with the hydro to reduce cash taxes. Moving forward to page 11 on the balance sheet, quickly I'd point out there, since the end of the year to 2013 so through nine months this year, $160 million improvement of PP&Es. We continue to invest in the business an increase of 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 now to 55.2%, so some improvement there as well. Moving forward to page 12, our cash flow from -- cash provided by operating activities improved nine months '14 versus the nine months 2013 by 34 million and that’s primarily related to improvement in working capital. And I guess what I would point out there is the improvement we’ve seen in bad debt, certainly in the third quarter this year has 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 by 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 the $0.38 on adjusted EPS perspective. We would compare that to an adjusted diluted EPS in 2013 of $0.39, so again it’s been 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 would 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 a adjusted diluted EPS basis compared to the prior year’s level of $1.75, so slight improvement there. Lastly, we talked about guidance. We reaffirm our guidance from $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 of '14. That’s about $0.07 to $0.22 higher than the adjusted $0.75 from 2013 and our expectation why we’re going to able to do that, we believe we’re going to be able to do that primarily due to customer and loan growth, full quarter of Bear Paw South earnings contributions are going to be the biggest drivers. Cost control and our 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 is an increase and no G&A expect to see an increase in other income as well. We've showed those movements and back 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, as mentioned, non-employee deferred comp and then the tax benefits. Take those adjustments, you get to the 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 the 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 DSO revenue adjustments, actually on adjusted basis, gross margin was up about 3.2 million or 2%, just over 2%. If you go all the way down to pretax, there is other adjustments certainly that happened. And from that regard, going from a $5.7 million difference or 11.8 million of pretax for three months ended September 30, 2014 versus the three months ended September 30, 2013, that large negative variance gets as a vast improvement down to a $2.1 million variance at the pretax level after these adjustments. And then when you take into consideration on the net income basis, we do have, as we partly pointed out earlier, a quite a wide band between the 30.2 million GAAP net income down to 15.6 million from the prior year. when you do back out the tax adjustments 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 of $0.38 for the three months '14 versus $0.39 for the three months ended September 2013. So 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, thank gas production, thanks gas rate increase, the volumetric improvement. That $27.5 million or 5.6% improvement is a decent improvement certainly on gross margin for the nine-month periods year-over-year. Take that down to pretax. Again, with the adjustments pointed out, $4.2 million improvement or 5.6%. And lastly net income for the nine-month period, a $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 the remainder of the year, we’re 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 resulted in FERC decision regarding the Dave Gates Generating Station, it takes into consideration the new tax range I discussed earlier and takes into consideration diluted shares of 39.3 million. Last thing I’d point 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 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 a public announcement in September of 2013 the $900 million acquisition of 11 base load facilities representing a total of 633 megawatts in addition to one storage reservoir and that was an acquisition from PPL Montana. That was the combination of several years of very, very hard work. On September 26th of this year after a yearlong process, the 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%, net 48% equity and that would result in an associated first year annual retail revenue requirement of approximately $117 million. The commission authorized issuance in an 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 that we do in December of 2015 to reflect post closing adjustments at the convenience of the Kerr project from NorthWestern to the Confederated Salish and Kootenai tribes and their energy keepers private 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 from detracting of revenue credits on a portfolio basis to our electric supply cost trackers. 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 26th 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 financing the FERC. Since 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 days to 60 days from the date of filing. Upon receipt of the FERC approval, we plan to close into a permanent financing of up to 450 million of long-term debt and up to $400 million of equity and $50 million of cash. 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 5th, we entered into forward-looking and to forward starting interest rates 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'll give you the URL for the webpage when we are updating information about the project. Very importantly, from an operational perspective, John Hines, our Vice President for Supply, would confirmed and reported to the Board over the last several days, we are ready to go and that's a big undertaking with HR 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, we're really very, very eager to take over operation. Of course, much attention has been focused on the hydro project. There's not a 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. We’ll have the details of that filing yet, but it would be based on a 12-month past year ending September 30, 2014. Notably our South Dakota customers that 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 was driven by our ongoing, the three and a half decades of investments in the South Dakota network, particularly our more recent construction of the Aberdeen Generating Station and our significant compliance expenditures at Big Stone. Dave Gates Generating Station in April of 2014, the FERC issued a decision, as most of you recall, to allocate only a fraction of the DGGS cost to the FERC 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 that'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 have deferred 27.3 million of revenue through September 30th, consistent with the FERC's decision. If we’re unsuccessful on rehearing, we have the right to appeal to the U.S. 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. I mentioned the Big Stone Air Quality project, the plan to Big Stone is subject to best available retrofit technology of BART requirements to meet the Regional Haze Rule, the so called bypass. 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. It 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 brainchild our distribution operations is doing with that project. Our employees are reporting that they are seeing the results and the customers are certainly seeing the results. We are taking the same kind of the systematic long-term approach to all of our infrastructure. And consistent with that, our transmission team has been developing Transmission System Infrastructure Project. Ultimately we will be taking an integrated approach to all of our assets. And as part of an integrated utility, 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. And again, this is all is 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’ve 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 spent and invested approximately of $100 million so far in that project. We're still actively looking at possibility to have them expensed for our customers and could conceivably invest another $100 million there. Also, we’re certainly 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 $1.26 to $1.275 and using $2.68 as a starting point, we’ve provided 2015 preliminary EPS guidance range of $2.95 to $3.30 per diluted share and a 2013 preliminary EPS midpoint of $3.13 a share. I am 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 suffice it to say that a lion's share of the improvement is essentially 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 and apply a 60% targeted dividend payout range, our preliminary target dividend range of $1.77 to $1.98 with a midpoint of preliminary target dividend of $1.88 per share. I 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 assumptions are off to left there. They’re very similar to the assumptions that we have for our 2014 guidance other than the tax rate items of 15% to 19% of tax on a pretax income and then a diluted average shares of 49.1 million the low end of our guidance and 47.5 million in 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 issuance price 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 $50, 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 will 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 now 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. And matter of fact, in 2009 through 2013, our capital expenditures have cumulatively outpaced depreciation 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. The 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 that’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 showed what as we reported in the 2013 10-K, as we've pointed out in the past, what 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’s now -- 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 of 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 cash 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 show here. With that, I’ll pass it back over 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 at the Montana hydro, dedicated and 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’s 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 a part of Chairman, Bill Gallagher legacy to the citizens of Montana that he was so passionate to serve. So I hope you keep him in your thoughts as he continues his journey. And with that, we're open to questions.

Thank you. (Operator Instructions) And we’ll take our first question from Paul Ridzon with KeyBanc. Paul Ridzon – KeyBanc Capital Markets: In the past you have 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 the supply portfolio we have in Montana has changed fundamentally and fundamentally for the good since Dave Gates came online. So we’re excited about analyzing and optimizing all elements of the fleet to understand how they can work together. Paul Ridzon – KeyBanc Capital Markets: I think it was about a year ago you added more net gas and you have indicated you’re kicking tires. I mean where are we in the price deck and how economic does it look at this point?

The challenge we have there, 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 Counsel, there is a forward price threshold. And given where the forward prices are right now, it would be challenging to, although again acquisitions make an awful lot of sense, kind of 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 counsel about over the coming months. It would be a shame not to be able to execute on good opportunities when they are available. Paul Ridzon – KeyBanc Capital Markets: 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 says 400 million kind of firm. Is that how we should be thinking about it?

Brian?

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 close to the 400 million, the better from our perspective. Paul, to be very clear, we’re going to be very close to 400 million of equity is our belief. Paul Ridzon – KeyBanc Capital Markets: And then lastly, Brian, when you went through some of the fourth quarter drivers, don’t you also have a DSM get 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. Paul Ridzon – KeyBanc Capital Markets: I thought the commission called some back in the fourth quarter.

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

And we’ll take our next question from Andy Levi with 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 like 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 at where we think our tax rate is going to go. And again, the tax repairs benefit continues to help us on a going forward basis. So I don’t see a cliff. I think the trajectory we've provided today is helpful guidance.

So, when you get to like 18, 19, or 20, there is no like big ramp up in taxes, tax rate?

I don’t anticipate a big ramp up in taxes. I do expect, Andy, that we continue to see upward movement, but I do not see big ramp ups.

And then does the play affect rate base at all, I mean when your taxes are so low, kind of like a deferred tax or not at all?

At the end of the day, the benefits of lower tax has to a great extent helped -- allowed us to stay out of rate cases. The lower taxes typically get passed on to the benefit of our customers. It does have an impact on rate base.

How does that work?

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

How does the repair -- is it one for one on the repair tax or is there some type of….

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

Okay, got it. And then…

Hey Andy, and then to put 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, obviously you've got the hydro plans in and there is 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 when we get very good guidance on what we’re doing in South Dakota in 2015 that we’ve been planning to do any rate case in Montana in 2015, we'd be telling you that today. 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 the DSIP and the TSIP in our plan. So there will be rate cases in the future. We certainly don’t want to give any thoughts on when that could be, because we don’t know at this point in time if that’s 2016, next year or '17, 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.

Typically we do an annual look across all jurisdiction with 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.

Just remind me again how long does it take from kind of filing to a final order for a Montana rate case?

It's typically a nine-month period for Montana.

Just again, credit to Chairman Gallagher and the commission, one of the biggest proceedings the commission has ever dealt with, they write to that nine-month clock and ran a very, very rigorous schedule and that's not an easy thing to do, says a lot for them.

And then my last question, you mentioned on the rate base of E&P and lower -- I guess perhaps the lower gas prices, is it lower oil and per se liquid prices that are affected by oil that changed the economics of the assets of what we’re thinking or there is something else in your comments?

But what we’re looking at is the attractive, very attractive low price of gas production assets right now, which suggests it's a great time to do those transactions on the one hand. On the other hand, the forward curve for gas purchased in the market is well enough that under the agreement we currently have in place of transactions that we think it might be quite sensible don’t pass that screen.

That’s because you can buy it cheaper, is that how works or?

Yes, it’s the shape of the curve.

And then like liquid prices and the price -- or that has nothing to do with the economic, does it?

Well, that’s not what we’re looking at now.

And we will take our next question from Brian Russo with Ladenburg Thalmann. Please go ahead. Brian Russo - Ladenburg Thalmann & Company: Just curious, it’s been a while since you've filed an electric case in Montana. But could you self-implement rates?

If I understand the context of the question, no. Brian Russo - Ladenburg Thalmann & Company: Okay. So 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. Brian Russo - Ladenburg Thalmann & Company: Okay. Because I think you did the gas case a couple of years ago, correct?

Yes, we have. Brian Russo - Ladenburg Thalmann & Company: You have. Okay, good. Secondly, on the interest rate swaps, they’re quite a bit lower as indicated in the Q than the 4% to 5% cost of debt threshold. Do you retain the difference or does that kind of get trued up in that December '16 filing?

Everything gets trued up. And obviously when you say there's a big difference, but you have to add the credit spread, you have to add in the cost associated with fees associated with that. So, from our perspective, the four in a quarter that was in the final order from the commission, with where we locked in plus credit spreads and fees, we'll be we believe somewhere in the 4.20% to 4.25%. But things could 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 based on our interpretation of the final order. Brian Russo - Ladenburg Thalmann & Company: Understood. And is there any like 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 obtaining an accounting order from Montana Commission for the first two for the expenses in the first two years of DSIPs and so that was primarily expensed and that would have been lost without the accounting order there. But actually quite a few states around the country have various kinds of specific infrastructure recovery trackers, writers for electric gas and even for water. We don’t have anything like that in Montana. Brian Russo - Ladenburg Thalmann & Company: And 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 the front of the capital. That’s not necessarily part of the plan though right now. Brian Russo - Ladenburg Thalmann & Company: And what if that’s over thresholds that you’ve agreed to with the MCC? And can – with your comments directly earlier, it seems like you guys can revisit that and look to adjust it down?

Yes, I'll 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 that 20-year levelized unit revenue requirement dollars per MCF, that’s again 20-year levelized, less than $4 of the crossover has to be five years or less, between $4 and $5 for the 20 year levelized crossover has to be 40 there is less $5 to $6 three years or less. So as you see, 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 a roller coaster shape, which makes for a bit of a squeamish ride. But again, we are looking at the price of assets and think it’s going to be pretty compelling right now. Brian Russo - Ladenburg Thalmann & Company: And in terms of the 2015 implied dividend, will that take place at the February Board meeting and really just be one dividend increase or you're 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’re 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’s taken into consideration on a quarterly dividend perspective, it would be our expectation that we repay a 60% payout in February. And based upon our thoughts for our guidance 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.

And we’ll take our next question from David Arcaro with Sidoti. David Arcaro – Sidoti & Company: 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. David Arcaro – Sidoti & Company: And can you remind me is that going to be across all states, all jurisdictions and then both gas and electric?

The overall infrastructure approach would be just both gas and electric and all jurisdictions. The DSIP focus was specifically in Montana because of [indiscernible] 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&D that also would remind folks that we have a substantial substation assets so they get as part of an overall utility approach to asset management substations and other assets will be very much a part. David Arcaro – Sidoti & Company: 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?

They are included in our South Dakota -- excuse me, they’re 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. No, I won’t tell you how much I have in there associated with that rate base. David Arcaro – Sidoti & Company: 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?

Those types of costs typically that are known and measurable, David, we’re able to capture in the rate case. And so that's something that obviously we’ll be talking to staff about. But our expectation is that 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, I 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. David Arcaro – Sidoti & Company: And one more quick question on the CapEx outlook. What caused such a big increase in the maintenance CapEx for 2016 through '18 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 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. 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 that are designed to meet current and future needs on our system.

And I'd just add to that, David, if we were to file our CapEx plan, if you will, if there was time to do our 10-K, I 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 filings going forward.

And we’ll take our next question from Jonathan Reeder with Wells Fargo.

Most of my questions have been answered. But one question on the upcoming PSC elections in Montana. Any reason to expect a shift in the regulatory attitude in '15 particularly since Gallagher will no longer be serving?

As 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 commissions and staff has been so focused, appropriately focused on the hydro project for the last year, we had an awful lot that we’re eager to go in and discuss in open meetings with the commission and staff over the coming months and that will be the same regardless. So again, Chairman Gallagher's departure is a real loss, but we look forward to working with whomever takes this place.

Is there any historical person on the district he represents? Does he always go Republican or is there any way to kind of speculate on that?

Not for me there isn’t.

Okay. And then last -- one project that you haven’t touched on in a while, didn't know if there was anything, any update on that would be the 500kv upgrade into the coal strip transition mine, where does that stand?

I’ll turn it over to Mike Cashell, our VP of Transmission. Mike?

Yeah. The one thing I would say about that is that there are no customers in our transmission queue that are waiting for that capacity. And in fact Bonneville recently announced that they had 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 then I'd add to that, it is not included in our plans in the five years that we've just shown you, as a matter of fact, Mike's still busy working on other transmission projects. They work 40 million odd that we had is associated with our share of that 500kv upgrade. So, I hope that helped answer your question, Jon.

It does. Thank you very much.

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

Well, thank you all very much for a good discussion and for your interest. We’re eagerly looking forward to visiting with many of you at the EEI Financial Conference in Dallas and probably others of you in New York City at the end of the year. Hope 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.