NorthWestern Energy Group Inc (NWE) 2011 Q1 法說會逐字稿

Ladies and gentlemen, thank you for standing by. Welcome to the NorthWestern Corporation First Quarter 2011 Financial Results Conference Call. (Operator Instructions) As a reminder, this call is being recorded. I would now like to turn the conference over to our host, Mr. Dan Rausch. Please go ahead.

Good afternoon, and welcome to NorthWestern Corporation's March 31, 2011, First Quarter Financial Results Conference Call and Webcast. NorthWestern's results have been released, and that release is available on our website at www.northwesternenergy.com. We also filed our 10-Q after the market closed yesterday.

Joining us today on the call are Bob Rowe, President and CEO; Brian Bird, Chief Financial Officer; Kendall Kliewer, Controller; and Heather Grahme, General Counsel.

This presentation contains forward-looking statements within the meaning of the Safe Harbor provision 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 in our annual report on Form 10-K, our 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 the presentation today, those of us joining by teleconference will be able to ask questions. A replay of today's call will be available beginning at 5.00 Eastern time today through May 24, 2011. To access the replay, dial 800-475-6701, access code 199056. The number again is 800-475-6701, with the access code 199056. A replay of today's webcast will also be available on our website.

And with that, I'll turn it over to President and CEO Bob Rowe.

Thank you, Dan. We're joining you today from our office in Grand Island, Nebraska, where we had our Board meeting and our annual shareholders' meeting as well. As I think a number of you know, we've moved most of our Board meetings into our service territory -- it's just a great opportunity to visit with our local employees, customers, and community leaders. As one of the shareholders who attended the annual meeting in person this morning said, we're very lucky to serve a group of states that are as economically sound as are South Dakota, Nebraska, and Montana.

We're pleased with our first quarter results. Net income improved to $32.6 million for the first quarter of '11, compared with $28.7 million in '10. The Board of Directors declared a common stock dividend of $0.36 per share, payable June 30 of '11, to common shareholders of record as of June 15.

In January, as most of you know, Moody's upgraded our senior secured debt from A3 to A2 and our senior unsecured bank credit facility from Ba to Ba1. In March, we received an accounting order from the Montana Public Service Commission to defer and amortize related O&M expense on our distribution system infrastructure project, or DSIP, for 2011 and 2012 over a five-year period beginning in 2013. And this really gives us the necessary green light to start the $287 million improvements to our system and defer the expenses that we incur in '11 and '12 as part of the first phase of an accelerated multiyear distribution infrastructure improvement plan.

Finally, we recently signed an asset purchase agreement to develop a 40-megawatt wind project in central Montana. The construction of that wind project is contingent on the Montana Commission approving the project for inclusion in our rate base. And as of yesterday, we settled the remaining several issues in our outstanding Montana rate case.

Before I turn the call over to Brian Bird, I do want to take just a minute to remember our Vice-President of Wholesale Operations, Dave Gates. Many of you had the opportunity to visit with Dave over the years and some of you know that he was tragically killed in a private plan crash on March 19. The Board of Directors has renamed the Mill Creek Generating Station, to which Dave was so instrumental, as the Dave Gates Generating Station at Mill Creek, and we're all going to very much miss Dave's leadership, his wisdom, his humor, and, most particularly, his friendship.

Now I'll turn the call over to Brian to discuss our 2011 results in more detail. Brian?

Thanks, Bob. As Bob said earlier, we reported net income of $32.6 million, or diluted EPS of $0.89 a share, during the first quarter of 2011, compared to net income of $28.7 million, $0.79 a share, in the first quarter of 2010. So our earnings increased $0.10 per diluted share, or 12.6%. We had a nice improvement on a year-over-year basis and we provided a table which gives a full reconciliation of that improvement in our press release.

At a high level, we would attribute the $3.9 million improvement to net income to the following -- first, from a gross margin perspective, that improved $14.9 million year over year, primarily due to the Dave Gates Generating Station coming on line on January 1, 2011.

In addition, colder winter weather in our service territory, the expiration in December 2010 of a power sales agreement related to the Colstrip Unit 4, and a rate increase in our Montana electric and transmission business.

That was offset by an increase of $13.9 million in our operating expenses, due primarily to costs at the Dave Gates Generation Station; increased labor costs, due primarily to compensation increases, and more time spent by employees on maintenance projects, which are expensed, rather than capital projects. We also had increased operating maintenance costs elsewhere in the business and an increase in property taxes and depreciation expenses.

And finally, our income tax expense decreased approximately $3 million, primarily due to the regulatory flow-through treatment of state-accelerated depreciation deductions.

Now let me take a moment to talk about our earnings outlook for the rest of 2011. We are reaffirming our 2011 guidance with a range of $2.25 to $2.40 per fully diluted share. The primary drivers and assumptions for the year are included in our press release.

For the first quarter, we would back out about $0.07 a share for favorable weather and add back a couple of cents for a favorable arbitration decision and a favorable reclamation settlement, both of which occurred in 2010. As a result, our adjusted earnings for the quarter was about $0.84 a share. After reviewing the first quarter results and considering our projections for the remainder of 2011, we are reaffirming our guidance of $2.25 to $2.40 per diluted share.

Now, moving on to the balance sheet. As of March 31, 2011, our total net liquidity was approximately $170 million, including $7.2 million of cash and $163.5 million of revolving credit facility availability.

Total debt at March 31, 2011, was $997.7 million, compared with $1.68 billion at December 30, 2010. The Company has a long-term debt-to-total capitalization ratio of approximately 54% at March 31, 2011. As we note in our 2010 10-K, we plan to maintain a 50% to 55% debt-to-total capital ratio.

Cash provided by operating activities totaled $122 million for the three months ended March 31, 2011, as compared with $106 million during the three months ended March 31, 2010. This increase in operating cash flows is primarily related to the timing and the collection of our supply costs and increased net income.

Cash used in investing activities decreased by approximately $20 million as compared with the first quarter of 2010, due primarily to additions related to the Dave Gage Generation Station project in the prior year.

Cash used in financing activities totaled approximately $83 million in the first quarter of 2011, as compared with approximately $45 million during the three months ended March 31, 2010. The difference is primarily $37 million more in debt pay-down in the first quarter of 2011 compared with the first quarter of 2010.

A recent development I'd like to point out is that we have recently entered into a commercial paper program to issue up to $250 million of commercial paper to provide an additional financing source to fund short-term liquidity needs at much lower costs.

And finally, as you can see, our balance sheet and cash flows remain strong.

Regarding equity, we get a lot of questions on whether we have to raise equity to fund projects shown on our investor presentations. Bob will talk more about the update to each project, but I want to address the source of funds. In our investor presentations, we attempt to give a meaningful probability to our future investment CapEx. And because we have signed a recent agreement to file a proposed $85 million to $90 million wind project with the MPSC, we are getting questions about whether we need to raise equity in aggregate for our projects.

All we'll say at the time is the timing and decisions associated with our regulatory filings will dictate if, and, or when we need to raise equity. And as a result, it is unlikely we would need to raise equity in 2011. I remind you, our evaluation includes a strong desire to maintain a debt ratio in the 50% to 55% target range.

And finally, we will attempt to match any equity raise with earnings streams of a growth project as much as practical.

With that, I'll turn it back over to Bob.

Thank you, Brian. I'll start with a regulatory update for the various filings that we expect over the remainder of the year. The key news today is that just yesterday, we were able to reach a settlement with the Montana commission on the dispute of several issues coming out of our rate case. You'll recall that the rate case was a 2008 test year filed in the fall of '09.

And in that order, the commission had first approved two important stipulations, one concerning revenue requirements, one concerning allocated costs of service, but then went on to adopt a modified decoupling mechanism which they referred to a modified lock revenue adjustment mechanism, an inclining block rate structure for electric customers. And it lowered the authorized ROE on the electric side from the stipulated 10.25% down to 10%.

And that had the effect of reducing the electric revenue increase from $7.7 million down to $6.4 million. So we had gone to court with the consumer council and other interveners in that case and then worked very hard to achieve a timely and constructive settlement with the commission.

I should note that during the first quarter, we recognized revenue and implemented rates that were consistent with the Montana commission's final order. Again, that was a lower ROE on the electric side of 10%. But, again, appealed that decision.

So yesterday the commission voted to accept a settlement offer made by us and the other parties, which would remove the modified loss revenue adjustment mechanism, remove the inclining block rate structure, and reinstate a 10.25% ROE, as contained in the stipulation.

In addition to that, then we agreed to a $650,000 reduction of electric rates as compared to the original stipulation. So basically, for the year we are splitting the difference between the two positions. We're very happy to have reached the settlement and look forward to moving ahead on many fronts.

As I mentioned earlier, we received an accounting order from the Montana commission basically giving us the green light to proceed with the phase-in, or ramp-up, of our distribution system infrastructure plan, which for the rest of the call I will refer to as DSIP. And this is part of our commitment to maintain the highest level of reliability and system performance while we continue to evaluate the condition of our distribution assets in order to address aging infrastructure through our asset management process. This is something that we are taking really a uniquely transparent and forward-looking approach to among utilities.

We're currently projecting capital expenditures for this infrastructure investment in Montana to be approximately $287 million over a seven-year time span, beginning in 2011. And importantly, these are amounts in addition to our base distribution budget. About 80% of this incremental CapEx is related to our Montana electric system, and about 20% is related to our Montana gas system.

We received the accounting order from the Montana commission in March to defer and amortize incremental operating and maintenance expenses for '11 and '12 estimated to be $16.9 million; and that would be, then, amortized over a five-year period beginning in '13. Our request did not cover capital but it was only the expense items which might otherwise be lost. And our estimated capital costs for the DSIP over just the next two years is about $33 million.

Some of you will recall that we used a similar method to account for our $93 million pension expenditure in late '10 with great success and there, again, with good support from the Montana commission.

So we're evaluating both the form and the timing of our next DSIP-related filing with the Montana commission. The key is to be as transparent as possible about our plans.

Now I'll move to the former Mill Creek Generating Station which, as I mentioned, is now the Dave Gates Generating Station, or the DGGS. The plant was place in service as it achieved commercial operation on January 1. We received an interim order from the Federal Energy Regulatory Commission in October and from the Montana commission in November approving rates based on the estimated construction costs. These rates became effective on January 1 subject to refund, of course, and replaced the current contracted costs that we are incurring for ancillary services.

The plant came in on time, it was under budget, and it is performing exactly as planned. In fact, our engineers are delighted with the way it is integrating into our system.

In March we made a compliance filing with the Montana commission reflecting the actual construction costs, and that will be used to conduct a cost review and to establish final rates. As a result of the lower-than-estimated construction costs, the lower debt rate, and the estimated impact of bonus appreciation -- from a customer perspective, all good things -- we expect the final revenue requirement approved by the Montana commission will be lower than the interim amounts approved and the difference, again, would be subject to refund.

Total project costs through the end of March were about $183 million. We anticipate the Montana review process will take about nine months, but a procedural schedule has not yet been established by the commission.

On the federal side, the Company is in active settlement discussions with the FERC staff and with our large customers who receive service under Schedule 3 of the Open Access Transmission tariffs. The large customers had intervened in the federal proceeding focused on cost allocation. We expect the settlement discussion on the federal side will also take approximately nine months.

Now I'll provide you with an update on some additional filings we expect to make in 2011. First, in the area of renewable electric supply, we've entered into a purchase agreement for a 40 megawatt wind project in Judith Basin County in Montana to be developed and constructed by Compass Wind, LLC. The project is known as Spion Kop, and NorthWestern had previously announced that it had entered into a memorandum of understanding to purchase a 24-megawatt wind project in central Montana from Compass. And what we've done is increase the size of the Spion Kop project up to 40 megawatts from the previous 24.

The purchase price for the project is $1,947 per kW. For each kW, the total nameplate capacity included in the project, and this is equal to $77.8 million. Total cost of the project will be higher because we will need to interconnect the project into our own distribution system and that will require a substation and some additional equipment. So all in, we estimate the total project will cost between $85 million and $90 million. And again, this is a project intended to be added to our fleet of rate-based supply in Montana and, very importantly, the project is conditioned on preapproval by the Montana commission to include it in our Montana rate base.

As part of this condition, we will submit our application to the commission for preapproval by the end of May of this year. If the Montana commission fails to grant approval of the project on or before April 1 of '12, then either party may terminate the agreement.

It should also be noted that the previously announced 24 megawatt MOU with Invenergy has been terminated. Therefore, we have a total of 40 megawatts of wind generation proposed in Montana and that does consist of the Spion Kop project alone.

With respect to natural gas reserves, in '10 we purchased a majority interest in producing wells and a gathering system known as the Battle Creek Field. At present, this $12.4 million purchase price and the cost of natural gas produced, including a return on our investment, are included in our natural gas supply tracker, and this is pending completion of a filing with the Montana commission specifically concerning Battle Creek.

So as a result of inclusion of the tracker, we are already recovering our costs and earning a return. In the second quarter of '11, we plan to make a filing with the Montana commission seeking approval to add our interest in the Battle Creek field and the gathering system into our regulated rates. Again, we expect this will be a Battle Creek-specific case.

We continue to explore investments to improve the natural gas reserves to be rate-based for the benefit of our customers over the years to come. I've said this before, I'm going to say it again -- we have no interest in becoming an E&P company. We're interested in proven reserves at attractive prices to give our customers long-term resource price stability.

Now let's turn to some anticipated filings with the South Dakota PUC. First, we plan to file for a small rate increase related to natural gas in the second quarter of '11. Consistent with our desire for transparent communications, we plan to brief the commission staff prior to the filing. We maintain the no-surprises approach.

Next, as we've been discussing for over a year now, we will need to address emissions reductions at the Big Stone Power Plant in northeastern South Dakota. We have a 23.4% interest in Big Stone; that is a 454 megawatt coal-fired plant. The estimated capital expenditures for the best available retrofitting technology, BART -- this is based on the Department of Environment and Natural Resources proposal -- are in the range of $500 million to $550 million. With [AAPPC] and overhead, our share would be in the range of $130 million to $150 million. Obviously, we're actively evaluating all of those costs.

It's important to note that the South Dakota commission has previously allowed the recovery of the costs of environmental improvements and have done so on a timely basis. Here again, we're keeping the South Dakota commission informed of developments as we continue our analysis. We plan to prepare an environmental rider filing to address cost recovery some time later in this year.

The plant operator is Otter Tail, and Otter Tail continues to evaluate the engineering solution that would be most effective to address the emissions issues. It appears that it will be late in the third quarter or perhaps early in the fourth quarter before Otter Tail has proposed a definitive plan for review by the department.

Once the final action and costs are determined, we'll prepare the filing for the environmental rider to go before the South Dakota commission.

Similarly, but on a smaller scale, we are the co-owners of a plant, Neal # 4, in northwest Iowa. And there again, we're working with the co-owners to investigate installing a scrubber. This would occur in the '13 to '15 timeframe. Overall project scope would be similar to what I described for Big Stone. Mid-American is the plant operator in this case and has experience retrofitting some of their other plants. The definitive plan is anticipated later this year as well. Once the final actions and costs are determined, we will, again, prepare a filing for an environmental rider to go before the South Dakota commission.

Capital expenditures are currently estimated to be around $220 million. In the case of Neal 4, we are only an 8.6% owner, about 55 megawatts out of a 655-megawatt facility, so our capital portion is likely to be right around $20 million.

Finally, on the regulatory front, previously we had discussed the possibility of a Nebraska rate case in '11. As we've analyzed our 2010 earnings, we don't believe a rate increase is required yet for our Nebraska gas business.

Now, turning to an update on some of the other projects we've been discussing over the months -- first in South Dakota, related to electric supply. We previously mentioned that we were doing preliminary engineering for a [peaking] facility near Aberdeen of about 50 megawatts, and that would replace an agreement that expires March 31, '12. The cost of the peaker plant at that site would be around $70 million, could go into service in '13. We don't anticipate a regulatory filing on the peaker this year but this investment has evolved to the point where we now consider it more likely than not to occur.

Turning to the transmission side of the business, in Montana we operate, as you know, an extensive transmission network, particularly in Montana. And based on that experience, have focused on three transmission projects oriented towards exporting. An upgrade of our existing 500 kV Colstrip system, the Montana Collector, and the Mountain States Transmission Intertie, or MSTI.

First I'll say a few words about Collector and MSTI. As we've noted previously, we extended our open seasons processes related to both Collector and MSTI at least to the end of this year. And the reasons for the extension include siting delays and pending litigation by Jefferson County against the Montana Department of Environmental Quality, some market confusion around California and the West, and lack of clear federal policy around renewables. We do continue to move forward with the necessary steps in this project.

Since the last quarter, the Montana DEQ has appealed the Jefferson County District Court ruling, appealed to the state supreme court, and we've now joined that appeal. No timeline has been set related to the appeal on the siting matter.

I'll say just a couple of words about development in the California market. In March, the California State General Assembly voted 55 to 19 to raise California's renewable energy target to 33% by 2020. That would be then, of course, one of the stricter standards in the world. The California State Senate had passed the mandate back in February and did include all power providers.

The bill does not require utilities to reach this new high target at any cost. Indeed, the state PUC must approve renewable energy contracts and utilities may be granted exemptions if the price of energy or the difficulty of moving that energy onto the state's grid makes the cost excessive. And interestingly, as a footnote, as a result of that both the California PUC's Division of Ratepayer Advocates and the independent consumer watchdog [TURN] did support the bill.

An important aspect of the new law is that it does not require renewable energy to be generated within the state of California in order to be eligible for the RPS program. So eligible energy may be generated in other states or, for that matter, Mexico and Canada, provided that the energy can supply end-use customers within California. So there's a need for a [pact].

This is a positive development for renewable developers interested in providing resources into the state of California, but at this point it's too early to determine the effect on any of our transmission projects specifically.

Concerning federal policy, although there continues to be real activity at the FERC level, there's been relatively little development concerning renewables or energy policy more broadly. And as all of you know, the focus in Washington, and probably the focus of some of us, is much more on gas tanks than light bulbs.

In turning to state legislative activities, the Montana Legislature passed a bill on eminent domain that is of interest to us. House Bill 198 would clarify public utilities' power of eminent domain, including any company that issued a certificate under the Major Facilities Siting Act. And this was a bill to restore some clarity to Montana law that was somewhat confused as the result of a district court decisions not involving a NorthWestern project but involving a merchant project -- the Montana-Alberta Transmission Link. So House Bill 198 passed the legislature and has gone on to the governor's desk for signing.

The governor has issued an amendatory veto on the bill requiring that it sunsets in 2013, so that has now been returned to the legislature. All I can say here is that stay tuned -- the legislature adjourns over the next few days and we will then know the final status of that piece of legislation.

We supported the bill as passed by the legislature because it adds clarification on our transmission, but also very importantly, on our underlying distribution business so that we're able to make the system enhancements that we need according to eminent domain law as we have understood it for decades and decades.

Though we've experienced delays in the transmission projects -- we've talked about those consistently over the last several years -- I think the challenges we've encountered are really quite consistent with most, probably all, other major transmission projects around the country and probably most major linear facility projects as well. So despite the delays, we do continue to move towards a record of decision for the projects. And it's important to note we have capitalized costs totaling only about $17 million in aggregate to date.

Now I'll move to the proposed upgrade to the Colstrip 500 kV line. And here the Colstrip transmission system, CTS owners for short, have reached an understanding on the concepts that need to be incorporated into the Colstrip transmission agreement and into their individual tariffs to accommodate the upgrade. And the CTS owners met with the FERC staff just a few weeks ago in March, and the FERC staff verbally affirmed that the process discussed by the CTS owners was on track. The FERC staff suggested that changes do not need to be included in the prospective CTS owners OATT -- again, the open access transmission tariffs.

I assume the other CTS owners will participate in the upgrade. The total expected cost for the upgrade is expected to be around $125 million. Our capital cost on the project is estimated to be around $38 million, and that is assuming that all of the current Colstrip Transmission System participants agree to participate in the upgrade.

We've capitalized about $2.5 million of this project so far. We expect to spend about $1 million in planning costs in '11. Commencement of construction could occur as soon as the study work is complete, and then the upgrade to the system could be completed by the end of '13.

Concerning transmission opportunities out of South Dakota. Recently, we've explained that the FERC gave MISO authority for a cost allocation tariff for certain projects that have been identified as having regional reliability, capacity constraint relief, and other attributes and values to the regional MISO footprint. As you know, whereas the West, the market we face out of Montana, is a nonorganized market, in the Midwest it's an organized market that does have the ability to exercise in joint planning and cost allocation. So in essence, the MISO-identified MVP, or multi-valued project, would cost-allocate the full revenue requirement across the footprint of MISO.

NorthWestern is not currently a MISO member. However, our South Dakota territory is embedded within the MISO geographic footprint. We continue to advance our analysis in proposing a project or projects within the MISO, and in fact there are several 345 kV projects in or adjacent to our service territory that we could elect to participate in through a joint venture.

So those words that you wait to hear every quarter -- in summary, we're pleased with our performance for the first quarter of '11. We increased our net income by $3.9 million, or $0.10 a share, over '10. And our Board of Directors has declared a common stock dividend of $0.36 per share.

Moody's has, again, upgraded our debt.

In March, we received an accounting order from the Montana commission to defer an amortized -- the related O&M expenses for '11 and '12 for our DSIP over a five-year period beginning in '13. And yesterday, we finally closed the books on the Montana rate case, [hoiya faxa], hoiya faxa.

Finally, we recently signed an asset purchase agreement to develop a 40-megawatt wind project in central Montana and we'll be preparing a filing in the very near term.

With that, I'll conclude my remarks and open it up for your questions. Thank you all.

Linda, we'll take questions now from the--

(Operator Instructions) Chris Ellinghaus.

Hey, guys; how are you?

Hey, Chris.

A couple of questions here. Brian, when you said $0.07 for favorable weather, was that versus normal, or is that versus last year?

Really both.

Okay. So last year you consider fairly normal? Okay. And you also -- when you were talking about your adjusted number, you talked about a couple of other adjustments other than weather. Could you just go through that again?

Yes. We show our bridge, if you will, from quarter to quarter. And on there you see one line item called reclamation settlement redeemed during 2010.

Right.

And that was a favorable benefit in '10; thus, unfavorable versus '11, correct? So we can back that out. And then, in insurance reserves, as we've noted in the Q, a portion of that insurance reserves is associated with an adjustment associated with an arbitration settlement. And that was about a cent as well. So we backed out about a penny for each of those two items.

Okay. I don't think, Bob -- when you were talking about the reliability enhancement capital spend in Montana, you were talking about the deferral order, but I don't recall you mentioning what your plan was for filing in terms of actual capital recovery.

Sure. We haven't made a final decision. And the range of options at one end would be a request for preapproval analogous to Mill Creek. At the other end, it would be something that looks probably more like one of our regular supply plan filings. And our view at this point is that the accountant order was key in terms of a formal action by the commission. So given that, our focus will be, at the very least, a filing that provides the commission as much information as possible, gives them an opportunity to comment, and ensures that they fully understand what we're about.

Now, if we don't seek a preapproval, then one would expect regular rate cases, for example, on an every-other-year basis. But the specific nature of the filing is the next thing that we'll turn to there.

Okay. And Brian, in -- you were mentioning that you didn't think that 2011 required equity and that you would try to time equity to fit with growth revenues. It looks to us like you're increasingly likely to do some equity in 2012, but right now you do not have a lot of big capital growth projects coming on line in 2012. Can you just comment on the dispersion between those two issues?

I think, Chris, all I'd say is there's quite a few projects, and I think -- hopefully the folks on the call follow our investor presentations close enough to know that. And for those projects that are green, if you want, our potential projects, I mean, those are kind of the high probability -- we don't anticipate equity associated with that.

And to comment on '12 is difficult because we have to have clarity in terms of some of these yellow projects, as whether we're going to move forward or not. And so that's why we feel comfortable in terms of where things are in terms of the regulatory approval process timeline. We can speak confidently about 2011 but it's difficult to talk about 2012 at this point in time.

Beyond that, as a number of you have recognized, our capital projects -- first of all, we try to be as transparent as can to all of you about what those projects are and what the gating factors are. They are all projects we think are valuable to our customers in our service territory. But there is a real element of discretion in whether or not we go forward with them. The revenues associated, and how quickly we advance on a combination of projects would really determine when we need to go out for more equity.

Okay, great. Thanks a lot, guys.

Paul Ridzon.

Bob, you said you're not currently a member of ISO. Should we read anything into that currently?

MISO. No, it's just a question of what the value is in relation to the price. Again, we work very closely with other MISO members and the lead interstate project sponsors clearly would be MISO members.

So you're not contemplating joining MISO.

We continue to look at it; I probably wouldn't want to say anything more than that.

And where does HB 198 sit? It's back to the house, back to the legislature? Any read on what's going to happen?

Sure. As I said, it ain't over till it's over. We will have a final answer over the next several days.

Okay. And then, Brian, just a little confused about backing out the reclamation settlement received in 2010. That was a 2010 event so it wouldn't really impact '11, would it, or was there some flow-over?

The issue is we're explaining kind of a year-over-year change, right -- '11 versus '10. And '11 was negative versus '10 because in '10 we had a favorable outcome. And so we're trying to show you on our bridge that there's a $0.10 favorable change between the $0.79 for the first quarter of '10 versus the $0.89 in '11.

So to kind of normalize that, if you will, we're saying that $0.07 of that change was associated with weather, which was favorable. If you back that out, you also need to add back two items that were, one would argue, unfavorable on a kind of comparison year over year for 2011.

And I wouldn't call $0.84 an ongoing '11 number because backing out that $0.01 for reclamation would inappropriate, wouldn't it?

I think from our perspective, we were looking at the differences -- I can understand your point. If you looked at an ongoing basis, we didn't have that, but I was comparing it with the variances year over year.

I've got it; okay. I just misunderstood what your nomenclature was. Thank you very much.

(Operator Instructions) Brian Russo.

Hi, good afternoon.

Hi, Brian.

Bob, you mentioned some activity at the legislature. Could you just update us on SP 330? I think that's the proposed bill to give utilities a three-year exemption to the RPS.

We'll give you an update before the call is over.

Okay. I guess the reason why I ask is renewable generation -- 40-plus megawatts that you've proposed -- you've got a high-to-medium probability of development success on that. And I'm just wondering if that Senate bill at all gives the commission leeway of not approving those wind projects without the utility facing any penalties. Just wanted to get a bit of feel for the likelihood of the wind project coming to fruition and being added to rate base.

What I can say about -- first of all, the commission does have some authority under current law to grant a waiver. What we have put forward is a wind project that went through an extensive RFP-type process and proved to be the most cost-effective project available in terms of its match with our system needs. So if the commission is inclined to approve any wind project, we would suggest that this is the best one available.

So I guess the 40-plus megawatts enables you to hit the RPS standard? Can you remind us what that RPS standard is?

Sure -- it's 15% in '15. And with that and a number of small QF projects, we will be right on target. So we're comfortable being able to meet the RPS.

Okay. And the Gate Mill Creek costs coming in under budget. Can you just tell us what the adjustment to kind of the finalized rate base of that is?

Say it again, Brian -- I'm sorry.

The Mill Creek Station -- you said it came under budget so the revenue requirement will be lower than previously outlined. What's the adjustment to rate base?

It's about $183 million is the number that the final rate base will come in at.

And that's -- first, what was the original?

I think it was $203 million.

Okay. And then, just on the DSIP. If approved, when could we start to see the margin impact from that? Is this, like, a post-2013-type of earning asset?

Yes, that's (inaudible).

Okay, thank you very much.

Your answer is that the veto on 330 occurred on March 20 -- April 20, pardon me. It's still snowing out here so it feels like February, actually.

Oh, it was vetoed so it's dead?

Yes.

Okay, thank you.

Jonathan Reeder.

Good afternoon, gentlemen.

Hey, Jonathan.

Real quick, to clarify -- so the off-ramp from the renewable legislation, you said that did get vetoed by the governor?

Yes, that got vetoed. Again, under current law there is a provision allowing the commission to waive the requirement, and 330 was kind of an enhancement on that.

So I guess, what is the current provision? How does that differ than, I guess, what that legislation tried to enhance?

The current provision, again, is based on customer impact primarily, and 330 would have added some clarity. But again, we can manage through it with current law.

Okay. And then, in the release you kind of mentioned hydro was impacting off-system transmission sales and you expect that to continue in Q2. Can you quantify what the consolidated impact would be from that?

We don't have that number handy, Jonathan, to provide what impact it would be in the second quarter. I can't tell you what our numbers were associated with that from the prior year or what's in our plan at this point in time.

I mean, just directionally, is it any sort of magnitude where, I guess, weather, the weather benefit in Q1, would offset it -- or would be more than offsetting, perhaps?

I don't think I would -- put it in this context -- I don't think the impact in the second quarter from that activity would be as large as the weather impact we had in the first quarter.

Okay, that's fair enough. And then, just one last question on the MSTI and collector open season. Have you seen any sort of increased activity in the month since California increased their RPS standard? Any increased dialog from the utilities in California to maybe get some wind shipped out there?

Sure. Two comments. First, in terms of our Q -- and this isn't driven by the recent California action -- we've shifted from a larger group of parties with general expressions of interest to a smaller group of parties who are actually moving to sign agreements.

The general sense is that there continues to be interest in California in projects from out of state. So I know that a number of the developers in Montana are having conversations with an out-of-state party about particular projects. But beyond that, I really can't say much.

Okay. Do I understand you correctly, though, that I guess the developers that you are still in contact with are, I guess, more the serious developers where you think there's a greater likelihood that their projects would get built?

I think that's a fair statement, yes.

Okay. Thanks for the additional insight.

Thank you.

James Bellessa.

Good afternoon.

Good afternoon.

Hey, Jim.

Several of my questions were asked and answered, but I want to follow up on some of the assumptions around the guidance. And you talked about the Battle Creek Field -- you're trying to rate-base that investment, but at the same time you're getting, if I understood right, some of that gas cost included in the natural gas tracker that you have. And so your ownership is not being held back, the earnings, that much -- is that correct? You're just waiting for rate-basing of what did you put into it -- the $11 million, $12 million or something like that?

Yes, Jim, I would look at it as just over $12 million; close to $12.8, actually. And if you think of the normal kind of earnings calculation on that, the expectation is between $600,000 and $700,000 of earnings assisted with that on an annual basis. You're correct -- right now it's flowing through the tracker, that earnings component.

Okay. And then, you indicate that there is a small benefit, possibly, from additional bonus tax depreciation related to a small business jobs act of 2010. Can you explain that, please?

Yes. If you remember, in the fourth quarter of last year we booked a bonus benefit -- it's really the flow-through from a Montana state tax perspective. That was all booked in the fourth quarter of 2010 for all of 2010. In 2011, we're booking that benefit on a quarter-by-quarter basis. So one of the reasons the increase versus the prior year was so much was there was no bonus associated in the first quarter of 2010, whereas there were $2.6 million of bonus associated the first quarter of 2011. So that's the big reason for the improvement year over year.

And that's shown in your bridge of earnings on that front page -- is that correct? It was $0.07 of accelerated depreciation, 2.6, $0.07? Is that what--?

Correct. The remaining benefit is associated with incremental repairs tax, repairs deductions, on a year-over-year basis.

And is there, then, additional accelerated depreciation benefits in the additional quarters of this year? You had a benefit in the first quarter, and is there expected additional benefits in the other three quarters?

Indeed, Jim, there will be.

And then an offset, you say, is going to be scheduled maintenance at the Big Stone plant. Can you tell us about the timing of that shutdown?

Yes, we typically have that works done in the second quarter of the year.

Thank you very much.

Thanks, Jim.

There are no other questions in queue.

Okay. Well, thank you all very much and we'll visit with all of you again next quarter if not before.

Linda, can you re-read the playback instructions then?

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