NorthWestern Energy Group Inc (NWE) 2013 Q1 法說會逐字稿

Good day, everyone. Welcome to today's NorthWestern Energy Corporation first-quarter 2013 financial results conference call. Today's conference is being recorded. At this time, I'd like to turn the call over to Mr. Travis Mayer.

Thank you.

Good afternoon and welcome to NorthWestern Corporation's financial results conference call and webcast for the quarter ended March 31, 2013. NorthWestern's results have been released and the release is available on our website at www.northwesternenergy.com. We also filed our 10-Q after the market close yesterday.

Joining us on the call today are Bob Rowe, President and CEO; Brian Bird, Vice President and Chief Financial Officer; Kendall Kliewer, Vice President and Controller; Heather Grahame, Vice President and General Counsel; John Hines, Vice President of Energy Supply; and Dan Rausch, Treasurer.

This presentation contains forward-looking statements within the meaning of the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995. These statements are based upon our current expectations and speak only as of this date. Our actual results may differ materially and adversely from those expressed in our forward-looking statements as a result of various factors and uncertainties including those listed on our annual report on Form 10-K, recent and forthcoming 10-Qs, recent Form 8-Ks, and other filings with the SEC. We undertake no obligation to revise or publicly update our forward-looking statements for any reason.

Following our presentation, those who are joining us by teleconference will be able to ask questions. A replay of today's call will be available beginning at 5 PM Eastern time today through May 25, 2013. To access the replay dial 888-203-1112, then access code 2569194. Again, that is 888-203-1112, then access code 2569194. A replay of today's webcast will also be available up on our website.

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

Thank you, Travis.

First, just a word about the new voice at the start of the call. All of you I know enjoyed working with Dan when he was in that role and he's stepped into the Treasurer role. And I'm sure most of you have got to know Travis very well over the years, too, and we're delighted that he's agreed to step into the Investor Relations role. And I'm sure you are all looking forward to working even more closely with Travis and we're very pleased with the job he's doing for us in that role as well. So thank you, Travis, and Dan and Travis, congratulations to both of you.

We're very happy with our financial results for the quarter. Our operating income and net income both improved in the first quarter of 2013 as compared to the same period in '12. There are several drivers behind this that Brian will discuss in more detail in just a minute. However, I would like to cover a few of the highlights for the quarter before handing it over to Brian.

On our February call, we informed you that we placed our new Montana wind facility, Spion Kop, into commercial operations at the end of '12. With now more than a full quarter of successful operations with this 40-megawatt facility under our belt, we continue to experience a capacity factor actually in the mid-50s that significantly exceeds our expectations and is really benefiting our Montana electric customers. In South Dakota, we're in the final phases of testing our 60-megawatt natural gas peaking facility located in Aberdeen; and as you would hope for any large project, peaker is coming in on time and under budget. We expect to place the new asset into commercial operation during the second quarter in order to meet our summer peaking needs.

The first quarter of '13 was also the launch of the production phase of our multi-year distribution system infrastructure project, or DSIP, in Montana. We spent the last two years in our ramp-up phase laying the foundation for what will be a very capital-intensive, five-year period to improve the safety, reliability, and capacity of our electric and gas distribution systems in Montana and to generally reverse the trend of aging infrastructure.

As some of you certainly have heard, just earlier this week we received favorable news regarding our natural gas rate filing in Montana. As many of you know, we reached stipulations with intervenors in April to increase delivery rates by approximately $11.5 million, on a 9.8% ROE, and a stipulation also addressing allocated cost of service and rate design, which often is a contentious and always an important part of a Montana rate proceeding. Just Tuesday of this week, the Montana Public Service Commission voted 4-1 to approve the stipulations and direct the commission staff to prepare a final order approving the $11.5 million rate increase and the allocated cost of service rate design. As a result of having had interim rates in effect since April 1, and a final order on its way, we will record revenues consistent with the stipulation for the entire second quarter of this year.

We're also really excited to share with you news that we are now a three-time-in-a-row recipient of recognition from Forbes as one of America's 100 most trustworthy companies. And we've discussed this with you in the two previous years; and what I want to emphasize is the rigor of the analysis that goes into this and the fact that Forbes and its consultants evaluate a universe of 8,000 publicly traded companies. So, to be recognized as one of the 100 most trustworthy from among 8,000 companies, many of which truly are excellent, is really something that we are all proud of. And it's a credit to our Board, Management, but ultimately to all of our employees and says a lot about the transparency and the integrity that we do try to achieve.

And last, certainly not least, yesterday the Board of Directors declared a common stock dividend of $0.38 per share payable on June 30 to shareholders of record on June 14. Now, I'll hand it over to Brian to discuss our first-quarter results.

Thanks, Bob.

As Bob mentioned we are very pleased with our financial results this quarter. We reported consolidated net income of $37.9 million or $1.01 per diluted share for the quarter ended March 31, 2013, as compared with net income of $32 million or $0.88 per diluted share for the same quarter in 2012. This was a fairly straightforward quarter with relatively normal weather and no significant items that we would deem one-time in nature.

There were three primary drivers that are accounted for our improved performance year-over-year. First, higher margins from new gas, electric supply assets, colder weather, and stronger electric and gas transmission results. Second, higher operating expenses including DSIP expenses and other expenses that could be expected for a growing company, including higher supply production costs, higher property taxes, depreciation, and interest expense. As a result, pretax income was up $3 million or 7% on a year-over-year basis. And, finally, the third item -- income taxes were approximately $3 million better than the prior year based upon increased repairs deductions, and PTCs from the Spion Kop project. As a result, net income was approximately $6 million or 18% better than the same period last year.

Recognizing that was a very high level overview I'll break the results down a little further for those interested in the details. First of all, gross margin increased by $10.1 million as compared to the first quarter last year. Primary drivers there were an increase in natural gas production margin, primarily due to the acquisition of the Bear Paw assets in the third quarter of 2012. An increase due to the acquisition of the Spion Kop wind farm in the fourth quarter of 2012; an increase in natural gas and electric retail volumes due primarily to colder winter weather than last year, although as I mentioned earlier, very close to normal weather for this quarter. An increase in transmission capacity revenues due to higher demand to transmit energy for others across our lines due to favorable wholesale market pricing conditions. An increase in transportation and storage capacity revenues due to higher demand to transmit natural gas for others across our pipelines, and higher demand to store natural gas for others as a result of lower average natural gas prices. And a slight increase in DSM loss revenues and Montana property taxes recovered through our trackers.

These gross margin increases were partly offset by a $4.3 million lower Dave Gates Generating Station, or DGGS, revenue in the first quarter of 2013. More specifically, in the first quarter last year we recognized $2.7 million of revenue that had been deferred in prior periods based upon a final order and compliance filing with the Montana Public Service Commission. In addition, during the first quarter of 2013 we deferred an additional $1.6 million related to the FERC ALJ initial decision as compared to the same period in 2012.

Moving into the expense side, our operating general and administrative expenses increased by $3.2 million, primarily due to higher DSIP expenses, increased non-employee directors deferred compensation expense, largely due to increases in our stock price. And I should point out the impact of this increased expense is fully offset in our other income with no net impact to income. We also had increased production expense due to the Bear Paw natural gas and Spion Kop wind acquisitions, and increased insurance expense related to general liability matters. These expense increases were partly offset by reduced pension expense, with the expiration of our pension accounting order at the end of 2012.

Property and other taxes increased by $2.1 million due to higher valuations and plant additions. Depreciation expense increased by $2.8 million due mainly to plant additions. As a result, operating income -- as a result of gross margin and expense items already discussed, increased by $2 million for the first quarter last year. Below operating income, interest expense increased by $0.8 million, primarily due to higher debt outstanding, partially offset by higher capitalization of debt AFUDC.

Other income was $1.7 million higher than the first quarter last year, due to the non-employee directors deferred compensation offset discussed above and also higher capitalization of equity AFUDC. Finally, income tax expense declined by $3 million, resulting in an effective tax rate of 11.7% this year as compared to 20% for the same quarter in 2012. This decrease in tax expense is primarily a result of increased flow-through payers deductions and production tax credits from Spion Kop.

Our earnings for the quarter were $1.01 per diluted share. This represents a $0.13 increase from GAAP earnings in the first quarter last year and a $0.09 increase from what we would call adjusted EPS for the first quarter of 2012. You'll recall, first quarter last year we added $0.09 for unusually mild weather and we removed $0.05 for the release of the Dave Gates Generating Station deferred revenue.

Turning now to our earnings outlook for the remainder of 2013, for the full year we are reaffirming our 2013 fully diluted earnings per share to be in the range of $2.40 to $2.55 per share. Our primary assumptions for the guidance range include a consolidated income tax rate of approximately 12%. Also, scheduled routine maintenance at our Colstrip, Big Stone and Coyote generation plants during the second quarter of 2013, diluted shares outstanding of 38.1 million, and continued normal weather in our service territory for the remainder of 2013.

Now moving to the balance sheet, as of March 31, 2013 cash and equivalents was about $6.9 million compared with $9.8 million at December 31, 2012. The Company had $253.3 million available from its revolving credit facility at March 31, 2013. This is compared with $173.6 million at December 31, 2012. Total debt at March 31, 2013 was just under $1.1 billion. The Company has a debt-to-total-capitalization ratio of approximately 53% at March 31, 2013; and as we have consistently stated we continue to target a 50% to 55% debt-to-total-capitalization ratio.

As of March 31, we have received a total of $46.2 million from our equity distribution plan since we started the plan in 2012. $17.7 million of the proceeds were received in the first quarter of 2013. Our equity distribution plan extends to the end of 2014 and authorizes up to $100 million in total issuances.

All in all, I'm happy to report this is a very solid quarter for our utility and with that, I will turn it back over to Bob.

Thank you, Brian.

I'll start by telling you that we're meeting today from our operations center in Huron, South Dakota; just finished our board meeting, our annual meeting as we always do. We had an employee meeting first thing this morning and then a community leader and retiree event just shortly before this call. So, there's always a lot of activity around our board meetings and especially our annual meeting.

Coming fresh off the heels of the Montana natural gas decision that I mentioned at the top of the call, I'll start with a few notes on the regulatory front. We did spend two full days in the hearing room at the Montana Public Service Commission last week. I think we had a constructive hearing. The parties and the commissioners were all very engaged. Much of the contention that can happen during a rate case was really addressed, I think, very constructively by the parties in advance, thanks to the stipulations that were reached with almost all of the parties. We acknowledge concern around the sub-10% ROE that we agreed to in the context of our ability to attract capital. But we do believe that the resulting $11.5 million revenue increase represents a reasonable outcome all around and is in the long term interest of both our customers and our investors. We were authorized to implement interim rates effective April 1 and we know that final order is now in the process of being drafted. So as a result of that, we will be able to recognize a full quarter of the final rates as approved for the full second quarter.

Several of you have asked about our future rate filing plans. As we mentioned before, each year we perform an analysis in each of our jurisdictions. So, for example, Montana Gas, Montana Electric, South Dakota Gas, South Dakota Electric, Nebraska Gas -- to determine whether we need to file a rate case in any of those jurisdictions. Based on our analysis of 2012 actual results, with anticipated known and measurable adjustments, we currently do not believe that any additional general rate filings are necessary during the remainder of 2013. We've been able to manage our business in a manner that will provide adequate returns to investors while delaying the implications of raising rates to our customers.

We had anticipated filing a general electric case in South Dakota this year based on a 2012 test year. However, we don't believe a general rate case now will be necessary in South Dakota until '14. When we do file an electric rate case in South Dakota, we expect to request an environmental rider to recover future environmental-related expenses and capital costs associated with both Big Stone and Neal 4. Until such a rider is authorized, we'll continue to record AFUDC on our capital investments during construction.

Closing the loop on another important state regulatory item we've been describing on our earnings calls, and as we specifically discussed in the last quarter, we spent several years involved in protracted litigation surrounding the calculation of power prices in a purchase power agreement that we have with CELP. As you know, CELP is a qualifying facility under PURPA. We were pleased to tell you in February that we expected that the Montana Public Service Commission to review a series of filings that we made with it, and issue a final order consistent with a decision that was issued in our favor by an arbitration panel late last year. At the beginning of this month, in fact, we did receive the Montana PSC order that we had hoped for and that puts an end to a contract dispute that actually started in 2007. Both parties now look forward to a much more constructive relationship for the remaining life of the contract.

Moving to FERC and the Dave Gates Generating Station allocation issue we've been discussing now for several quarters -- unfortunately, there is no news since our last call, but for any of you that may not be as familiar with this matter, I will go ahead and provide just a little bit of additional background. And for many of you this is very familiar territory. FERC Administrative Law Judge issued an initial non-binding decision in September of '12 regarding allocation of costs of a new gas plant that we put into service in January of '11 to provide regulating reserves to both retail and FERC jurisdictional customers. And, again, we already had a positive order from the Montana Commission on this matter. The initial decision from the FERC ALJ resulted in an allocation to the federal jurisdictional customers that was only a fraction of the amount that we believed should have been allocated based on past practice. But as a result of the initial decision, we are continuing to defer revenue of approximately $700,000 per month.

Our brief, as well as others from the Montana Commission, the Montana Consumer Council, Bonneville Power Administration, and our trade organization, Edison Electric Institute, all in opposition to the ALJ's initial decision, is pending before the FERC along with briefs on the other side. We have no assurance of timing, as I have described to you before; but based on past experience we expect the FERC to consider the matter and issue a binding decision sometime during '13. Should note that we have as part of our filing requested oral argument in front of the commission. The FERC is not obligated to follow any of the findings from the ALJ's initial decision and can accept or reject the initial decision in whole or in part.

If the FERC upholds the decision, and a portion of costs are effectively disallowed, at that point, we would be required to assess DGGS for potential impairment. As you all know, if we disagree with the decision issued by the FERC, ultimately we may pursue full appellate rights through rehearing and appeal to the United States Circuit Court of Appeals, and that could extend the matter into 2015. So, again, no news to provide this quarter, but hopefully the background is helpful to anyone who has not followed the issue quite as closely.

Now, I'd like to turn the discussion to several of our growth opportunities. As I mentioned at the start of the call, the blades on the 40-megawatt Spion Kop wind facility have been spinning very successful for nearly five months now, and we are only a few weeks away, as well, from placing our Aberdeen natural gas peaking unit into service. We believe, as we've discussed previously, that the next likely large addition to our electric supply portfolio will be on the Montana side. That would be a natural gas generating asset to help replace power from a 200-megawatt contract with PPL Montana that expires a little over a year from now. As we continue to evolve towards a more vertically integrated utility in Montana, a natural gas combined cycle combustion turbine, or a CCCT, has been identified as the type of generation asset that can provide the flexibility to best serve our customers into the future.

The supply portfolio requirements that we are addressing include dispatchability, provision of ancillary services, base load power, and peaking power. While we continue to evaluate any opportunistic acquisitions, we're also moving forward in a deliberate way on development of the CCCT. To that end, we have had several meetings now with potential engineer and procurement and construction contractors, or EPCs; and we're currently conducting a siting study for a nominal 250-megawatt combined cycle plant in Montana. The siting study includes a review of the availability of electric and gas transmission, land, water, ease of permitting, and necessary infrastructure such as roads, railroads, and a skilled and dedicated workforce. And we're currently conducting specific onsite investigations of these issues.

We expect to complete a siting study in the third quarter of this year to be followed up quickly with the identification of specific technology to be deployed. Consistent with the timing set forth in our 2011 Montana biennial integrated resource plan, we anticipate a 2018 commercial operation for a new build option. And we'll continue to update you on progress as is appropriate. And then as a reminder, we'll also be filing our next Montana electric supply plan toward the end of this year with more detail about our future plans.

In South Dakota, we continue to move ahead on our environmental projects, on our jointly owned base load plants. When the final year of construction on the emission reduction project at our Neal plant, Neal 4 in Iowa, NorthWestern's share of the total project is estimated to be between $25 million and $30 million and that's expected to be completed by the end of this year. We received a good project update from the plant operator at our Big Stone plant several weeks ago for the air quality control system that is being installed there. Due to design and adhering improvements along with reduced contractor costs, the total project costs have been shaved down by about $85 million down to a total of $405 million.

As a result, our 23.4% share of this capital project is now estimated to cost between $95 million and $110 million. And this is $20 of good news for our customers, decreasing from our previous estimate of $115 million to $130 million. So, again, our estimated share is currently between $95 million and $110 million. And, again, good news for us and for our customers as it does help alleviate some of the upward pressure on rates while we continue to work to meet EPA and South Dakota requirements. Tomorrow, I will actually be participating in a groundbreaking ceremony at the plant with our partners at NBU and Otter Tail along with South Dakota's governor Dennis Daugaard.

Turning next to natural gas supply and our portfolio needs in Montana, we're currently able to serve approximately 10% of our total 20 Bcf annual retail natural gas needs in Montana with the gas acquisitions that we have made recently at Battle Creek and at Bear Paw. The investment in Battle Creek was authorized to be included in our rate base in November of last year. Based upon this decision, we've been collecting the cost of service for our more recent Bear Paw Basin acquisition, and that includes a return on our investment to our natural gas supply tracker on an interim basis. We expect to file an application with the Montana Commission to place Bear Paw into our natural gas rate base during 2013. These natural gas reserves have been performing very well and serving our customers as anticipated.

As we've said before, our desire would be to own approximately 50% of our retail natural gas needs to provide long term price stability to what history has shown to be a very volatile market. In February, I used the metaphor that we are kicking the tires and have gotten in for a test drive on future acquisitions. Unfortunately, I'm not able at this time to announce any specifics, but it is fair to say that we are moving at least past the test drive stage or at least it is one of those very, very long test drives where they stop for lunch, like on the Volkswagen commercials. However, like anything else we do, we want to make sure we are making thorough and thoughtful decisions that are going to be in the best interest of our customers and of our investors over the long term. We hope to provide you with further update by next quarter.

Turning to our distribution operations. As part of our commitment to maintaining a safe and reliable electric and natural gas system, we continue to evaluate the condition of our distribution assets to address aging infrastructure through our DSIP activities. The primary goals of our infrastructure investments are to reverse the trend in aging infrastructure, maintain reliability, proactively manage the system for safety, capacity, and to prepare our network for the adoption of new technologies as those make sense. Over the past two years, we've been in, again, the ramp-up stage of the DSIP plan and amortizing expenses associated with the preparatory work. The first quarter of 2013 marked what we would call the hard start of the remaining five years of the project, for the full production phase; and everyone truly hit the track as soon as the green flag dropped and people are working extraordinarily hard and successfully on a very exciting project.

During '11 and '12, we utilized an accounting order from the Montana Commission to defer about $16 million of expenses during our two-year phase-in, and the amortization of these expenses will be about $3.1 million annually over five years starting in '13. And this amortization is in addition to the approximately $11 million of expense that we expect to incur on DSIP in '13. In terms of our DSIP capital spend, we spent about $34 million in the ramp-up phase and plan to invest another $253 million of capital over the next five years. Based on our current plans, along with the Montana Commission's approval of the accounting order, we believe DSIP-related expenses and capital expenditures will be recovered in base rates through annual or biennial general rate cases.

Concerning our transmission operations, while progressing slowly we remain in the process related to the proposed upgrade to the Colstrip 500kV line. The project's liability, as we've discussed before, and timing, are dependent on other investments with the Bonneville Power Administration as planned further west on the 500kV. We're focusing our efforts on this project and working with BPA and their system plans. As of March 31, we've capitalized around $1.2 million of preliminary survey and investigative costs associated with this upgrade. We expect very little additional capital spend until a decision is made by BPA to move forward.

The investment potential for the Colstrip 500kV ranges from about $40 million to $70 million depending on how many of the other Colstrip owners might ultimately decide to participate in the project. The upgrade to the system could be completed by the end of '16. However, as I mentioned a moment ago, both liability and timing really do depend on actions on the BPA side.

In the meantime, we're continuing to focus on our transmission needs within our native service territories, and as we've discussed before, we have across our system 8000 miles approximately of electric transmission, 2000 miles of gas transmission. That is the core of our transmission operation and where we have always placed our primary focus. We have several upgrade and expansion projects in process that will serve to improve reliability and respond to growth and demand. Recent projects include the Jackrabbit, the Big Sky transmission, 161kV line upgrade which is currently under construction. First phase of that project came in, in time to shut down and be ready for ski season at Big Sky, so I was personally very, very happy about that. It's a great project.

And then also, the new Columbus to Chrome 100kV transmission line is in development to respond to infrastructure needs in Southeastern Montana. We expect to spend about $70 million on these two projects over the next five years. We're also in the third year of a project to replace conductors on our 100kV line in our South Dakota service territory. These projects are included in our maintenance CapEx as disclosed in our 2012 10-K, but they've been growing in significance over the past several years.

So, in summary, our operating income for the quarter improved by $2 million over the same quarter last year. Our net income for the quarter improved by nearly $6 million over the same quarter last year. We feel strongly that the stipulations in our Montana natural gas case represent an acceptable outcome both for the Company and for our customers, and we look forward to continuing our focus on maintaining and enhancing the core of our distribution and transmission systems, gas and electric, across our service territory through continued investments.

We are actively developing new electric and gas assets for the benefit of our customers. The addition of our new energy supply assets on both the electric and gas sides to date have proved to be great investments, benefiting both our customers and our investors. And, one more time, with three years of recognition as one of America's 100 most trustworthy companies out of 8000, we look forward to continuing to provide the transparency that all of our stakeholders deserve.

With that I will wrap up this part of the call and open it to your questions, which Brian will answer while I have a drink of water. Thank you and the line is open.

(Operator Instructions)

We'll go to Paul Ridzon with KeyBanc.

I was about to say the call was over. Sorry, Paul, go ahead.

Can you hear me?

Yes.

You changed the language around your effective tax rate, and gone to the bottom end. What's driven that?

I think when we put together our plan for last year, there was some things on the tax side that we weren't exactly sure of. That's why we had a broader range. We had a little more clarity as we got into the first quarter, and so we feel more comfortable at the bottom end of the range, and thus, approximately 12%

I think you said it, but I missed it -- what was the weather versus normal?

This year, our weather versus normal -- there's no adjustments. This weather we had in the first quarter is in line with what our normal weather should be. Now, Paul, remember last year we had a $0.09 add-back for weather because of unseasonably mild weather. But for this year, no adjustment either up or down for weather.

It felt colder, but that's just because we're all getting soft.

Then as the capacity factor at Spion Kop is exceeding expectations -- I guess volumetrically you're getting more PTCs. Is that part of the lower tax rate? And how does that get passed back to the customer? Is there a fuel [clause]?

Yes. The capacity factor certainly helps, but it is -- PTCs are driven by megawatt hours, and we're pretty much in line with what our expectations were in terms of PTCs in the first quarter -- wasn't materially different than our thoughts.

And then lastly, it sounds, Bob, from your comments that self-build is kind of where you're incrementally leaning towards versus the last call, on incremental capacity?

No, I wouldn't say versus the last call. We've identified, since the '11 plan, a gas plant in '18 is our likely project, and on the last call I described some of the steps we were taking at that time. We've continued to actually take additional steps that are appropriate for a plant that would come online in '18.

And John Hines, our Supply Vice President is here and, John, if you have anything to add to that, please do.

Yes. We've continued to look at a multi-pronged approach, but the gas combined cycle plant has a lot of valuation for our portfolio from a lot of different perspectives that Bob talked about, and so we're now taking affirmative steps to move forward on that path.

Understood. Thank you very much.

We'll go next to Michael Klein with Sidoti & Company.

Hi. Good afternoon.

Hey, Michael.

Just to follow up quickly on the tax rate, and I know it's early and you're not giving any guidance for 2014, but just to try and understand where the pieces are going to fall and what's hitting this year? And to what extent you can give some color around what to expect going forward? Maybe that's PTCs or the flow-through treatment or whatever else might be impacting that going forward?

I think a lot of the benefit we've seen in the reduction in our effective tax rate is because of the repairs tax deduction. As we continue to invest more in our Business, and primarily things like DSIP, we'll continue to see additional benefits from that. PTCs have helped, but over the long term, as we have said before, we do expect an upward trend in our tax rate, but we haven't given sufficient guidance on where that would go. I do think we have said that we would be trending up I think to around 20% by 2017 is the last guidance we gave associated with tax rate, but I think that's going to be a pretty gradual climb, if you will.

Is that helpful, Michael?

It is. It is. Do you still expect to get to that tax rate in that same time period, or is that maybe pushed out a little further, or it's too early to tell?

That's still our expectation today.

It is, okay. And can you just talk about what happened with the pension? You noted something in your prepared remarks, and it was a benefit year over year. Did it expire at the end of 2012? Can you just elaborate on that a little bit?

Yes. We had -- a while back, you might recall back in 2009, we made a significant contribution into our pension fund, approximately $92 million. And at the time, we worked with the Montana Public Service Commission, and we received from them an accounting order that spread that contribution over a number of years, and 2012 was the last year of spreading those expenses out.

And so, you're going from a $20 million-plus type -- yes, I think I would say the drop is about $20 million, excuse me, you're going from about a $30 million-plus pension expense down to around $10 million. And as a result, the reason for that is, on a going-forward basis, our pension expense is going to be what we spend, and our expectation of what we spend is going to be approximately $10 million in 2013. So, the higher spend in '12 is a result of the final year of that accounting order, and the lower spend in '12, or excuse me, in '13, is a result of our expectations of what we'll spend on a going-forward basis.

Okay. And last question, in terms of how the commission views natural gas acquisitions, and I know they've stated publicly that they are in favor of additional acquisitions with gas prices at the levels they're at today. Now, were those comments made by the new commission I guess following the recent elections, or were these comments that had been made previously?

The commissioners and staff have made a number of I think very positive comments over a period of time, including at the time of the last approval. In addition to that, I think discussions with, and stipulation with, the Montana Consumer Council have been very positive.

John, why don't you add some more insight there?

The old commission was the one obviously that ruled on the Bear Paw acquisition, but the -- or I'm sorry, Battle Creek -- but there were members of the old commission that are still on the commission that had positive statements. In addition, transactions that we're looking at will be consistent with a lot of the financial parameters that were set forth in the stipulation between the Consumer Council and NorthWestern.

Okay, great. That's helpful. Thank you.

Next we'll hear from Charles Fishman with Morningstar.

Just if you would clarify -- in South Dakota, if you received an environmental rider, would that preclude you from a general rate case in '14, or would you be applying for both at the same time?

Our anticipation is that we would make the request for a rider as part of a general rate case.

Okay.

And so the general rate case would effectively reset everything since we haven't had to go in on the electric side in South Dakota for a very long time. So, that would be the reset, and then the rider would go forward.

One thing I'd also add to that is -- one thing, even though we will not be requesting the rider during '13, we will continue to accrue AFUDC up until the time that a rider is approved.

Okay. That was it. Thank you.

We'll go next to Brian Russo with Ladenburg Thalmann.

Hi, good afternoon.

Hi, Brian.

Just a question on the equity distribution agreement -- what is the forecast for this year, or should we expect additional equity sales?

I think the same comment I gave back in February, Brian -- we may issue up to the full distribution of the program. We'll continue to monitor our equity needs during the year. I think we have stated numerous times now that based upon the assets that we have shown in our investor presentation -- you might remember those that are green, if you will, or high probability -- we'll be able to fund all of those assets with our equity dribble program and the cash flows from our Business. But as I stated in the past, we may -- and it depends to a degree on what we may do in the remainder of the year in terms of equity needs and capital needs.

Are gas reserve acquisitions -- is that considered green, meaning you can finance gas reserve acquisitions without additional equity?

I would say the answer to that is we could utilize the proceeds under existing equity program to finance our gas acquisition needs.

Okay. So, that existing equity program of the up to $100 million, $46 million have already been raised. Is that accurate?

Correct.

Okay. Just on the general rate case strategy, or the lack of need to file in '13, how should we look at the peaker plant that's coming online in the second quarter in South Dakota, and the regulatory or the lag associated with that? Where do you overcome that in terms of feeling comfortable not needing a rate case?

I really can't say much other than what I have said. Based on what we know for the remainder of this year, we don't anticipate a need to file until '14. And at that point, then we would deal with projects, including things like the peaker. But based on what we know now, there is no need to file this year.

One additional comment, too, is we do have trackers associated with any fuel costs or property taxes for that asset that would be picked up in cost of service during the year.

Okay. And assuming you build a gas plant for 2018, how do you bridge the gap from when the PPA rolloff in mid-2014? Do you recontract short-term PPAs -- is that the strategy?

As I noted earlier, there was a multi-path approach. We would continue to look at opportunistic acquisitions up to a certain point during that timeframe, and then we would have in a layered power purchase agreement declining over time through 2017/2018 sufficient to meet our needs. One thing to point out is that our portfolio need is significantly less than what it was when we had the PPL contracts originally. So, we're only looking at, with PPL contracts rolling off, that only accounts for around 23% of our total portfolio.

Okay. And lastly, I noticed in the Q you have some deferred DSM lost revenues. I think it's about $6.2 million. Can you update us on how you seek recovery of that, and when?

There's a hearing in June on our Montana electric tracker. The DSM lost revenues are part of that tracker, and will be subject to that hearing. We don't expect to see an order on it until probably at least the third quarter of 2013.

Okay. Thank you.

(Operator Instructions)

And we'll hear from Michael Bates with D.A. Davidson.

Good morning, guys, or good afternoon, rather. A couple of questions -- the first quarter was boosted by revenues tied to higher demand to transmit and store natural gas for third parties. Can you talk to us about whether you see that as a recurring revenue source? Were there any longer-term contracts signed, or will it be a one-time type of event?

No, Michael. This is more of a trend back to kind of pre-recessionary type levels. You might recall, both on the electric side and the gas side, numbers in these matters would have been higher in the '08 and '07 time period. We're starting to see a positive trend, really starting this year.

Okay. And I also wanted to ask about the potential acquisition of gas reserves. With regards to the Battle Creek and the Bear Paw acquisitions you made, was the tire-kicking phase for those transactions as lengthy as it's been for the assets that are currently under consideration?

I'll start, and then hand it off to John. I'm going to stay with this metaphor and just beat it to death. We spent a lot of time, actually several years, looking at a whole variety of car lots in many different towns up and down the freeway, and ultimately decided, more or less, where we wanted to shop and what kind of cars we were looking at. So, there was a pretty protracted phase before we focused in on specific assets.

John can give you more flavor on the specifics.

I guess I would only add one thing in that, you know, the size of transactions oftentimes equate to complexity, which takes -- translates into duration.

All right. That's helpful. Thank you very much.

We'll go next to Chris Ellinghaus with Williams Capital.

Hey, guys, how are you?

Hi, Chris. Thanks, good.

I'll presume -- I've got a whole laundry list of questions. I'll presume I'm towards the back end of the queue, so I'll ask a bunch.

First thing, Bob, going off of something you were talking about in the gas settlement, it certainly seemed like an overall fair kind of number, but can you talk about your argumentation before the commission, and maybe what the commission's attitude and response was on the ROE? Did you make it clear to them that a 10% ROE is kind of a floor for a lot of investors; it's a screening mechanism, and that that's potentially hurtful for raising equity capital? And can you just give us a little color on that?

Yes. We did explain that at some length in our pre-filed testimony. We were very concerned about that aspect of investor reaction in entering into the stipulation. We had that in mind. We were frank, I think, in explaining the likely concern to the commission.

The commissioners individually asked good questions from really all perspectives about the implications of the stipulation, and ultimately, we concluded that at this time, the overall revenue increase with the agreed upon ROE was an acceptable outcome. All parties gave something, and we were able to move forward on that basis. But we get it, in terms of concern that investors may have about that ROE on the gas side.

Hey, Chris, one thing I'd add to that -- on the gas side, you've probably noted that ROEs have trended down more than they have on the electric side, and I don't know if it's 25 basis points or the like. So, from our perspective on the electric side, a lot of ROEs are still in the appropriate range we believe in the 10% to 10.25%, depending on the assets.

Okay. I was going to ask you -- presuming that there's a Montana electric case in the not too distant future, can I presume that you'll go back to that issue because, particularly for some long-only investors, that is an important criteria, and it would be nice to see the electric side be a little bit different?

We, as Bob pointed out, certainly noted in my testimony, noted on the stand numerous times how important it is, and that 10% is certainly a perceived floor by investors, and I know so on the electric case there will be a certain -- it will be included in our testimony again, trust me.

Okay. Brian, can you talk about the weather impact this quarter? I'm just sort of looking through the drivers for the quarter. You know, obviously retail, electric and gas, and transportation and storage are things. Can you talk about transmission? Is that largely weather related? And I'm particularly surprised by the gas production incremental benefit for the quarter. Is that also somewhat weather and consumer-demand oriented?

I'll start with -- on the electric transmission side. A lot of that has to do with improvements in wholesale prices elsewhere. It's allowed us to draw more generation through our transmission system as a result, to meet the needs of higher wholesale prices, if you will.

On the production side, I think from that matter, we just drew upon more gas from our production facilities for the quarter. As a result, had a little bit higher margin than I thought; as you might also know, a little bit higher production costs as well.

And so can we presume that that significance in the quarter is really of a seasonal nature due to winter demand?

Say that again, Chris.

Well, it's a very big number, certainly much more than I would have expected, given that those assets are already recovered through the fuel clause. So, I'm just curious whether, because the first quarter is such a big gas quarter, whether the earnings from your production assets are extremely seasonal in nature?

Oh, yes, yes indeed.

Okay. And also, the repairs deduction was particularly beneficial. What was going on in terms of maintenance that might have led that to be so large?

Well, I think, as we pointed out, I think as we mentioned in our earlier comments, we just had higher investment, and you're starting to see that. As you know, we're ramping up, certainly in DSIP in the first quarter on a year-over-year basis, and that incremental investment -- and we've talked about repairs deductions in the past -- as we continue to invest more in our business, that repairs deductions will increase.

Okay. The pension benefit, was that on track for pretty much what you were expecting for the year, and is there any kind of seasonal nature to that at all?

No. It's in line with expectation.

Okay. And one last thing -- Bob, you were talking about the new gas plant for Montana. Can you just go through the thinking of waiting until '18 for a new asset, as opposed to trying to get that to line up a little closer with PPA expirations?

That's the point at which a plant as opposed to a market becomes the most cost-effective option, and John manages the planning and procurement process. So, you can again provide some more detail there.

Yes. Part of the issue is that we're looking at greenfield, as well as brownfield sites, and there would be infrastructure development necessary, as well as just the plant itself from both a -- potentially from an electric transmission side and a natural gas pipeline side. So, we think that that's a very realistic time frame, and we can stagger our purchases accordingly to meet that time frame.

In the '11 plan, '18 was identified as the point at which owned new generation was the most sensible alternative.

Correct.

Okay. And one more thing -- Travis, if you get a chance, would you give me a shout later?

I will do that, Chris.

Thanks a lot, guys. I appreciate it.

Thank you.

Our next question comes from Wells Fargo's Jonathan Reeder.

Good afternoon, gentlemen. Most of mine have been answered, but a couple timing questions. Bob, you mentioned on the FERC decision on the Dave Gates station as just being 2012. Does that mean you're no longer thinking Q2 -- that it could be kind of second half of the year?

I think that's fair, and I've tried to communicate the black-box nature of when a decision might be forthcoming. Everything that we know about the possible timing of the decision is simply based on how long it typically takes a matter to be decided once it is taken from the ALJ level up to the commission level. The factors here -- we've talked about these before -- complexity, the importance to the industry as indicated by the third-party filings from EI and BPA, for example -- the fact that we requested oral argument, things like that. But we have no insight into when a decision might be forthcoming other than past practice.

Okay. But I guess something in the past practice made you kind of alter the thought from Q2? I mean, is that all there is to it, really?

Really, yes. We're now into the year some stretch. I wouldn't read anything into what we're saying. We're telling you everything we know, and as I've tried to describe in terms of when a decision is forthcoming, that ain't much.

All right. Fair enough. And with the expected South Dakota electric rate case filing getting pushed back to 2014 from mid-year this year, should we assume that it's early in '14, or is that still kind of up to debate?

I think I'd probably say on that, John, is we'll do what we do with all of our jurisdictions. We do what we call a first look after we get our year-end results, and we start calculating known and measurables. So, we'll go as quickly as we can, and my expectation would be we'd be in the first half of '14.

The first -- the gating action is the assessment of whether or not a case needs to be filed.

Okay. And then, any clarity on when we might see a Montana electric case?

Same answer there as well.

Okay. And then just last question -- besides the tax rate, have any of the other assumptions materially changed since you established the $2.40 to $2.55 guidance range?

No. I think all I'd say on that is, obviously, we're pleased where the tax rate is in our range, but there is some timing in terms of expenses and things that drive things around. I would just say we're very comfortable with the range.

Okay. I appreciate the time, guys.

One other thing, back to the comments associated with timing on '14, I think we should be clear on the rate cases of two things. One on the South Dakota side -- we're really going to be ramping up spending on Big Stone coming in '14, and that's going to be a big driver to, I think, really push us over the edge, if you will. Then obviously in Montana on the electric side, DSIP with $50 million more of spend, if you will, is going to really drive that for next year. So, fairly certain in terms of what '14 is going to show for both Montana and South Dakota.

Right, yes. That's what I was kind of thinking as far as the DSIP on the Montana side. I appreciate that additional color, Brian.

Your final question will come from Andy Levi with Avon Capital.

Hi, good afternoon.

Hi, Andy.

I guess most of the questions were asked. The only one I have left is -- are there power plants actively being marketed in your area?

At times there have been plants shopped. We can't comment on anything beyond that, and that's all we know.

Okay. So, you can't let us know whether there's actual -- not obviously involving you, but whether there's any activity of plants that are -- I don't know if it's been made public or not made public, but that are being marketed?

No.

Okay. Thank you very much.

Thank you.

And we have no further questions in the queue.

All right. Well, thank you, everybody, for joining us, and we'll let Bob sign off here.

Again, thank you very much. We'll see many of you during the quarter -- look forward to talking to most of you next quarter. Take care.

Ladies and gentlemen, that does conclude today's conference. Thank you all for joining.