NorthWestern Energy Group Inc (NWE) 2011 Q2 法說會逐字稿

Ladies and gentlemen, thank you for standing by and welcome to the NorthWestern Corporation Second Quarter 2011 Financial Results Conference Call. (OPERATOR INSTRUCTIONS) As a reminder, today's teleconference is being recorded. At this time, I will turn the conference call over to your host, Mr. Dan Rausch. Please go ahead, sir.

Good afternoon, and welcome to NorthWestern Corporation's June 30, 2011, Second 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 Grahame, General Counsel.

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 in 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 the presentation today, those joining us by teleconference will be able to ask questions. A replay of today's call will be available beginning at 5.00 p.m. Eastern time today through August 27, 2011. To access the replay, dial 800-475-6701, and then access code 209282. The replay number again is 800-475-6701, and then code 209282. A replay of today's webcast is also available on our website for a period of time.

I'll now turn it over to President and CEO Bob Rowe.

Thank you, Dan. Today we're calling you from our Missoula Division office. As you know, every quarter we are visiting with you from somewhere else around our service territory. And we're not just moving around for reasons of personal security, but it does give us a chance to visit with community leaders, customers, and employees. Last night we had a very lively meeting with community leaders here in Missoula who are enthusiastic about our role in western Montana and our contributions to the community. This morning we had a great meeting with our employees. Missoula is the largest office, kind of the hub, in our western Montana operations, with about 100 employees reporting up into Missoula.

Net income declined to $11 million for the second quarter of this year; that's compared with $11.7 million for the second quarter of last year. Brian will discuss that in more detail in just a few minutes. I will say, though, that although our earnings for the quarter were indeed slightly less than the prior year, we do still intend to achieve our earnings guidance for 2011 and as you know, due to the seasonality of the business, the second quarter typically has the least impact on our earnings for the entire year.

Moving to nonfinancial activities for the second quarter, in June we upsized our revolving credit facility from $250 million to $300 million and extended the maturity date and significantly lowered the facility costs.

In May, we announced that we filed an application to adjust our rates for natural gas service in South Dakota. Also in May, we filed for preapproval with the Montana Public Service Commission to purchase and operate the yet-to-be constructed 40 megawatt Spion Kop wind project, which would be located in central Montana.

In addition, yesterday the Board of Directors declared a common stock dividend of $0.36 per share, payable on September 30 to common shareholders of record as of September 15.

Finally, during the quarter we announced the appointment of two new members to the executive management team following the death of Dave Gates in March. Mike Cashell has been promoted from Chief Transmission Officer to Vice President for Transmission and Mike is here joining the call as well today. And John Hines has been promoted from Chief Energy Supply Officer to Vice President for Supply.

In both natural gas and electricity, our key operational areas are supply, transmission, and distribution, and we now have executives responsible for each of those areas. So these appointments maintain the alignment of the operational areas at the executive level and they provide the high visibility and focus necessary to provide our customers the very best service possible and to grow the Company well into the future.

Now I'll turn it over to Brian Bird to discuss our 2011 financial results in more detail. Brian?

Thanks, Bob. As Bob said, we reported net income of $11 million, or, on a diluted EPS basis, $0.30 per share, during the second quarter of 2011, compared to net income of $11.7 million, $0.32 per share, in the second quarter of 2010.

Gross margin increased by approximately $9.3 million during the second quarter of '11 compared with the same period of 2010. The primary drivers are the Dave Gates Generating Station, or DGGS, revenues from Montana retail customers were higher; an increase in electric and natural gas retail volumes due primarily to colder spring weather and customer growth; an increase in Montana electric transmission and distribution rates; and the expiration of a December 2010 power sales agreement related to the Colstrip Unit 4.

These increases were offset by a reduction in transmission revenues due to strong hydro conditions and also a decrease in property tax tracker margin.

Our operating, general, and administrative expenses increased by approximately $12.4 million during the second quarter of 2011 compared with the same period of 2010. However, that is in line with what we expected.

In fact, two items representing $4 million of that increase were $2.6 million in insurance recoveries that occurred in the second quarter of 2010, but of course did not occur in the same quarter of 2011. Also, $1.4 million of scheduled maintenance costs in 2011 that were not scheduled in 2010.

Above and beyond that, the remaining increase in costs were increases in labor and operating expenses that were largely anticipated.

Finally, we recorded an income tax benefit for the second quarter of $516,000, significantly contributing to our earnings. The income tax benefit was primarily caused by three items. We conducted an analysis of the Montana net operating loss carry-forward balance that yielded an earnings benefit of $1.6 million for the second quarter. Essentially, we were able to utilize a greater amount of state NOLs than we had originally expected.

In addition, we had a benefit due to repairs tax deduction for the second quarter of approximately $1.5 million.

And finally, we were able to reduce our tax expense due to bonus depreciation taken in the second quarter of 2011 that was not yet available in the second quarter of 2010. That provided a benefit in 2011 of $700,000.

Due to the recording of the items I just mentioned, the year-to-date 2011 effective tax rate is approximately 17%, and we now expect our overall tax rate for all of 2011 to be between 18% and 22%.

Now let's talk about our earnings outlook for the rest of 2011. After reviewing our year-to-date results and looking to the last six months of the year, we are reaffirming our estimate for fully diluted earnings per share in 2011 with a range of $2.25 to $2.40 per fully diluted share.

The quarter, though slightly lower than last year, was in line with our expectations. Margin was a bit lower than expected, but that was offset by lower property and income taxes than expected. For instance, the strong hydro conditions caused by heavy snow pack west of our transmission system and the resulting displacement of thermal generation caused a $2.6 million reduction to our expected transmission margins. In fact, the Northwest River Forecast Center projects that the Columbia Basin runoff this year will exceed runoff in all but two of the last 40 years.

Our year-to-date fully diluted EPS through June 30, 2011, is $1.19. Based upon results for the first half of the year, we plan to back out about $0.07 a share for the tax benefits related to the state NOLs. We would back out about $0.07 a share for colder weather's effect on our electric and natural gas distribution business, but we'd also add back $0.05 for lost transmission revenues related to the strong hydro to date and for the remainder of the year.

As a result of these adjustments, our adjusted earnings through June 30, 2011, were about $1.10 per share. And as Bob pointed out earlier, due to the seasonality of our business the second quarter typically has the least impact on our annual earnings. In fact, over the last three years the first half of the year represents approximately 47% of our net income for the year.

Now, regarding expenses, we expect general and administrative expenses for the rest of 2011 to decline from the second quarter levels due to higher capitalized operating labor costs due to higher levels of capital spend in the second half of the year, plus expense contingency measures instituted as a result of the lower transmission margin expectations I noted earlier.

I also noted, from our guidance perspective, again, we expect overall tax rate for 2011 to now be between 18% and 22%. And of course, we expect normal weather in our service territories for the remainder of 2011.

Now, moving on to the balance sheet. As of June 30, 2011, our total net liquidity was $214.3 million, including $4.5 million of cash and approximately $210 million of revolving credit facility availability.

Total debt at June 30, 2011, was approximately $1 billion, compared with approximately $1.1 billion at December 30, 2010. The Company has a long-term debt-to-total capitalization ratio of approximately 54.4% at June 30, 2011. And as we note in our 2010 10-K, we plan to maintain a 50% to 55% debt-to-total-capital ratio.

Regarding the cash flow statement, cash provided by operating activities increased approximately $31 million for the six months ended June 30, 2011, versus the same period the prior year. This increase in operating cash flows is primarily related to a decrease in contributions to our qualified pension plans of $10 million as compared with the same period in 2010, and improvements in the collection of our supply costs.

Cash used in investing activities decreased by approximately $45 million as compared with the first six months of 2010, due primarily to additions related to the DGGS project in the prior year.

And cash used in financing activities increased by approximately $79 million during the six months ended June 30, 2011, as compared to the same period for 2010. The cash used in financing activities was primarily used to pay down our debt and to pay our dividend.

I'd like to remind investors that during the first quarter of 2011, we entered into a commercial paper program to issue up to $250 million to provide an additional financing source to fund short-term liquidity needs at a much lower cost. At June 30, 2011, we had about $90 million outstanding under that program. That commercial paper program, along with the extension of our revolving credit facility at much improved terms, will decrease our short-term borrowing costs in the future.

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

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

Thank you, Brian. I'll start with a regulatory update for the filings we've made to date and those we expect to make during the remainder of the year. Starting with renewable supply in Montana, we entered into an agreement to purchase a 40 megawatt wind project in Judith Basin County, Montana, to be developed and constructed by Compass Wind, LLC. This is an $86 million project known as the Spion Kop wind project, and those of you with historical or geographical bents can go out and look up the origin of the name, Spion Kop. This will provide a 25-year levelized cost to ratepayers at approximately $54 a megawatt hour.

On May 31, we filed for preapproval with the Montana commission to include Spion Kop in NorthWestern's rate base. The hearing has been set for December 14. Construction would commence upon a favorable ruling, with commercial operation projected to begin by the end of 2012. If the Montana commission fails to grant approval for the project on or before April 1, 2012, then either party may terminate the agreement.

Moving toward distribution operations, as we discussed last quarter, we've now received from the Montana commission an accounting order to start our distribution system infrastructure plan, or the DSIP. We're currently projecting capital expenditures for this infrastructure investment in Montana to be approximately $287 million over a seven-year time beginning in 2011. In fact, our distribution team is well under way with early-stage implementation.

We received an accounting order from the commission in March to defer and amortize incremental operating and maintenance expenses for 2011 and 2012 estimated to be around $16.9 million. The deferral would be over a five-year period beginning in 2013. DSIP operating expenses are in addition to our base operations, so capitalizing these expenses will not reduce the amount of our operating expenses in distribution. Again, these are amounts in addition to our base budget.

Our estimated total capital cost for DSIP over the next two years is about $33 million, and again, this is in addition to our base budget expenditures, and those are estimated to be about $140 million per year in the next several years.

Turning to the Dave Gates Generating Station, the DGGS was placed in service when it achieved commercial operation on January 1. We received orders from the FERC in October last year and the Montana commission in November approving interim rates based on the estimated construction costs. These rates became effective beginning on January 1 of '11 subject to refund and replaced the former contracted costs for ancillary services now provided by DGGS. The plant came in on time, under budget, and is performing as planned at the time.

In March of '11, we made a compliance filing with the Montana commission reflecting the actual construction costs that will be used to conduct a cost review and to establish the final rates. As a result of the lower-than-estimated construction costs, the lower debt rates, and the estimated impact of bonus depreciation, we expect the final revenue requirement approved by the commission will be lower than the interim amount approved, with the difference refunded to customers. Total project costs through June 30 of '11 were approximately $183 million. The Montana commission has set a hearing for November 9 of this year on the matter.

Turning to the FERC, we've been in settlement discussions with FERC staff and other customers taking service from the DGGS. Primary issue there is related to cost allocation between wholesale and retail customers. The settlement discussions have not been successful so far and FERC has established a procedural schedule with a hearing set for January 23 of '12 and an initial decision for May 4 of '12.

In South Dakota during the second quarter of this year, we filed for a relatively small rate increase related to our natural gas operations. We're requesting an increase to $4.1 million annually due to increased operations and maintenance costs and to complete our remediation of old manufactured gas plant, or MGP, sites in South Dakota. Approximately $1.4 million of the requested increase does concern the manufactured gas plant remediation costs. In the event MGP costs are lower than estimated, the difference would, of course, be subject to refund to customers.

Now I'll cover some additional filings we expect to make for balance of the year.

Concerning natural gas reserves. In 2010, as you know, we purchased a majority interest in producing wells and a gathering system called the Battle Creek Field. In the interim, the $12.4 million purchase price in the cost of the natural gas produced included a return on our investment are included in our natural gas supply tracker. So as a result, we are already recovering our costs, or (inaudible) return.

In the third quarter of this year, we plan to prepare a filing with the Montana commission seeking approval to add our interest in the Battle Creek Field and the gathering system into our regulated rate base. We also continue to explore investments in natural gas reserves to be rate-based for the service of our customers.

Turning to some anticipated filings -- in South Dakota, with the South Dakota PUC, as we've discussing for some time, we do need to address emissions reductions at the Big Stone Power Plant in northeastern South Dakota. We have a 23.4% interest in Big Stone, and that is a 454 megawatt coal-fired power plant. Estimated capital expenditures for the best available retrofit technology based on the Department of Environmental and Natural Resources proposal are approximately $500 million to $550 million. With AFUDC and overheads, our share of these costs would be between $130 million and $150 million.

The South Dakota PUC has previously allowed recovery of the costs for environmental improvements on a timely basis. We're keeping the commission informed of developments as we continue our analysis. The plant's operator, Otter Tail, continues to evaluate the engineering solution most effective to address the emissions issue. We're working very closely and constructively with the partners there.

It appears that it'll be probably the late third quarter or early fourth quarter before Otter Tail proposes a definitive plan for partner approval. Once the final actions and costs are proposed, we'll prepare the filing for cost recovery to go before the South Dakota commission.

Similarly, in the South Dakota service territory, the owners of coal plant Neal No. 4 located in northwest Iowa are investigating installing a scrubber in the 2013 to 2015 timeframe. This would have an overall project scope similar to the Big Stone Scrubber. Mid-America is the operator and has experienced retrofitting several of their other operational plants. The definitive plan is anticipated later in 2011.

Once the final action and cost's proposed, we'll prepare them to go before the South Dakota commission to seek cost recovery there. Capital expenditures are currently estimated to be approximately $220 million. There, we are only an 8.6% owner, which would be about 55 megawatts of the 655 megawatt facility. So our capital portion is likely to be around $20 million.

Finally on the regulatory front, in Nebraska we no longer anticipate requesting any revenue rate increase in 2011. Our analysis of 2010 earnings for Nebraska natural gas concluded that a rate increase was not necessary for that business at this time.

Turning to other projects that we've been discussing in prior quarters, in South Dakota, concerning electric supply, we've mentioned that we are doing preliminary engineering for a peaking facility near Aberdeen of about 60 megawatts, and that would be to replace an agreement that expires on June 30 of '12. Cost of the peaker plant would be around $70 million. It's expected to go into service by the end of 2012. We're continuing to work on that project.

In Montana we obtain, as you know, a significant portion of our electric supply from our purchase agreements that will expire by the end of 2014. Over time, we intend to transfer relatively more of our energy supply from PPAs to rate-based options, the goal being to provide reasonable and stable supply sources and rates for our customers for decades to come. Accordingly, we're evaluating opportunities to buy or build supply over the next several years.

Turning to transmission, first in Montana. As you know, we have three transmission projects -- the upgrade to the existing Colstrip 500 kV, the Montana collector, and the Mountain States Transmission Intertie, or MSTI.

Turning first to MSTI, as we have noted previously, we have extended our open seasons processes, actually both for collector and for MSTI, at least through the end of this year. And the reasons for the extension include siting delays pending litigation by Jefferson County, Montana, against the Montana Department of Environmental Quality; market confusion in California under load centers and lack of clear federal policy related to renewables.

There is progress to report. The Montana DEQ and NorthWestern have appealed the Jefferson County ruling to the Montana Supreme Court. A briefing on that case is complete and the court is holding an oral argument on August 2 of 2011 and we expect that this judicial matter will be resolved no later than the end of this year. So although we experience delays with MSTI, we continue to see real opportunity for the project and advance towards a record of decision in the siting process.

From a regional planning perspective, we have successfully completed the Phase 2 Path rating process for MSTI with the Western Electricity Coordinating Council, WECC -- and kudos to our team for the great work through the WECC process. So this process established a path rating for MSTI of 1500 megawatts southbound and 1150 megawatts northbound. And we've recently completed a 30-day comment period and we expect final approval from WECC in the third quarter.

We've capitalized costs on the two projects, the collector and MSTI, so far of $18.6 million and that, in fact, is all for MSTI.

Turning now to the proposed upgrade to the Colstrip 500 kV line -- again, good progress to report there. In June, the Bonneville Power Administration released the results of their network open season and proposed two transmission line upgrades, one in Washington; and secondly, the Colstrip upgrade project in Montana. As you know, BPA owns and operates the western portion of the line and BPA'a announcement made clear that it needed to coordinate with NorthWestern Energy's work on the planned upgrade on the Colstrip project. So it is assumed that the other Colstrip transmission system owners will participate in the upgrade along with NorthWestern.

The total expected cost of the Colstrip transmission system upgrade will be approximately $125 million. Our capital cost on the project is estimated to be about $38 million. This is assuming that all of the partners participate proportionately in that project. We've capitalized about $2.5 million on this project so far; we expect to spend about $1 million in planning costs in 2011. The upgrade to the system could be completed by the end of '13; however, timing will need to be coordinated with BPA's portion of the upgrade, as noted, to the west.

Concerning transmission opportunities in South Dakota, recently we reported that FERC gave the Midwest independent transmission system operator, 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 value to the regional MISO footprint. In essence, MISO identified a range of multi-value, or MVP, projects, and will allocate costs of the full revenue requirement to the entire MISO footprint.

NorthWestern is not currently a MISO member. However, our South Dakota territory is embedded within the MISO footprint. We continue to advance our analysis in proposing a project or participating in projects in the MISO area in either several 345 kV projects in or adjacent to our service territory in which we could elect to become a joint venture participant.

So in summary, we're on track to meet our original guidance in the range of $2.25 to $2.40 per fully diluted share. Yesterday, the Board declared a common stock dividend of $0.36, payable at the end of September. In June, we upsized our revolving credit facility, extending the maturity date into 2016 and reducing costs. In May, we filed for approval with the Montana commission on the 40 megawatt Spion Kop project in central Montana. And finally, we've announced that we filed an application to adjust our natural gas rates in South Dakota.

With that, I'll conclude the narrative portion of the call and open it up to your questions.

(OPERATOR INSTRUCTIONS) Chris Ellinghaus, Williams Capital.

Hey, guys, how are you?

Hey, Chris.

Was wholesale margin not much of an impact in the quarter, given what hydro conditions were?

Well, wholesale sales from the South Dakota perspective?

Well, from South Dakota or from Montana, it doesn't matter. But it seemed like, certainly in Montana, revenues had fallen off a cliff, but you didn't mention wholesale margin as a material impact for the quarter.

It's pretty small.

Okay. Could you characterize what kind of benefit weather was for the quarter?

Weather wasn't a huge impact in terms of the gas and the electric side of the business. It was a big impact, though, on the transmission capacity issue that we talked about and that's -- we deem the high hydro associated with unusual weather patterns. So I would say that's about $0.04 for the quarter, right there.

Okay. Can you walk us through the Montana property tax issue? And how the tracker's working and why that was a material impact for the quarter?

The tracker itself was the -- down mainly because property taxes, themselves, were down was the major driver. And I think when -- we reallocated that as a result of the reduction in property taxes for the quarter.

Okay. Well, when you look at your walk-through table and you've sort of got a negative driver from the tracker but a positive on property and other taxes, what's that spread?

The spread there -- on a six-months basis, property taxes are up about -- or, a favorable variance about $2.1 million; and a negative basis from a tracker, $3.3 million. That's mainly the adjustment from a full-year perspective. If you're just gone -- for just the quarter itself?

Yes.

The benefit was a $4.4 million from property taxes, and then the tracker brought margin down to $2.5 million. What happened is during the second quarter, we got working with the department, the Department of Revenue in Montana, we had a better idea in terms of what our evaluation from property taxes were going to be. And as a result of that, we reduced our estimate for the year and had it reduced -- effectively reduced, [call it] the first and second quarter estimate as the result of an adjustment.

Okay. So that's more of a true-up issue?

Correct.

Okay. Bob, can you talk a little bit about what you see in South Dakota in terms of the commission's attitude towards wind?

The state of South Dakota is very interested in seeing the resource developed, generally. At the commission my sense is that they do support development of a resource portfolio, certainly supportive of development of the South Dakota economy. They are appropriately sensitive to cost impacts.

Okay. So they're -- my impression is they're not in a big hurry to do any renewables?

We're making our -- I can't speak to other utilities; we're making our resource decisions based on what we need, and our current identified need is for the peaker at Aberdeen that we discussed.

Okay. All right; thanks a lot.

Thank you.

Thanks, Chris.

Brian Russo, Ladenburg Thalmann.

Hi, good afternoon.

Hi, Brian.

Could you just maybe talk about some of the major issues or items of discussion in Montana with this wind farm filing? I think you mentioned a mid-$50 per megawatt hour price to the customer. How does that compare to market rates? I would imagine that's going to be a big driver. And then, any other items that you think are going to be discussed or scrutinized by the commission in this review process.

The important thing -- I think all of you know this -- is that this is a case for preapproval. We don't go forward until we receive a decision one way or the other from the commission. The case has just been filed. There are interventions pending. We expect the interventions to raise questions about the project or about particular aspects of the project, about the process. It's too early, though, really to say what issues actually get adjudicated by the commission.

The price that we managed to obtain for this project is very, very good. And I would contrast that price in the mid-50s with the much higher price for qualifying facilities, for example. So we're pleased with the price, we're pleased with the project. We'll know what issues interveners raise as the case develops. Interveners do include other parties that might have had an interest in advancing a particular project, and that's just the nature of this kind of case.

Okay, but it's clearly much higher than wholesale power in your region; correct?

Potentially. Obviously, has the advantages of, first of all, helping us meet our renewable portfolio standard. But it's a price that comes in really close to where our overall portfolio is and is a price that provides long-term certainty as opposed to market prices that will be fluctuating up and down. So again, I would highlight the long-term nature of the price and the resource.

Would you say the desire to own more steel in the ground and rely less on PPAs would be an item in the decision-making process?

It certainly is a factor. And again, the state of Montana has been quite clear, the legislature, the commission, that they want to move away from market risk to a significant extent. So that is an advantage. And again, long-term price stability associated with this resource as opposed to market prices, which can move in both directions.

Anything new at the legislature level on the RPS standard, or is there less of an appetite for renewables in Montana than there was previously?

No. The legislatures have gone home in all of our states. There were a number of bills introduced, ultimately no significant changes to the law. A couple of bills that passed ultimately ended up being vetoed. So I would say -- again, there were proposals to increase, proposals to decrease the RPS, but ultimately we ended up pretty much where we started.

I think actually the result was a really good discussion around the legislature about renewables and about energy policy. Generally what I would say in speaking to policy-makers is, give us a clear set of goals, consistent goals. Certainly the tools, such as preapproval, to achieve those goals. But then, let the details of supply planning or operations, for that matter, be left to the professionals whose job that is every day.

Okay. And just to confirm -- the commission has the ability that if they decide to vote against this wind farm and you fall short of the 15% in 2015, they can grant waivers so that the utility isn't fined? Is that correct?

That is correct.

Okay. And then also the bonus depreciation you guys booked in the second quarter -- what would be kind of the impact to the rate base in, I guess, your next Montana rate case?

I don't have the answer to that in terms of dollars, Brian. Obviously, what we're doing from a rate case perspective, that's going to be a benefit to us. And matter of fact, it might actually allow you to not have to go in for a rate increase because of the benefit bonus you're receiving today. But I put it to you this way -- any lag that we're receiving from higher expenses on a year-over-year basis is being somewhat offset by bonus depreciation.

Okay. And then, the CS -- the 500 kV upgrade -- it seems to me that this is a reliability-driven project that has now been endorsed by the BPA?

I think it's -- reliability also is the opportunity to develop resources in Montana to export in (inaudible) those resources out. Characteristics that are complementary to the wind regime in the Northwest. So certainly a reliability component, but BPA was responding to identified demands on its system.

Okay. And how many megawatts of PPAs are expiring in 2014? I assume that's the contract you have with PPL on Colstrip?

It is. And Brian, we're racking our brains. I don't recall the number of megawatts it is at '14 -- we're going to look it up quick.

Okay. Thank you very much, guys.

Thanks, Brian.

Paul Ridzon, KeyBanc.

Hey Brian, on the state tax issue, should those two items be a wash by the end of the year? Is that how we should think about it?

When you say those two items --

The Montana property tax and the Montana property tax tracker?

Oh, that's a great question. I thought you were talking about income tax; my apologies. On the property tax perspective, if in fact property taxes were flat on a year-over-year basis, you should have no increase in property taxes and you really should have no increase in a year-over-year basis in margin -- if they're flat year over year.

Do you expect them to be flat?

Yes, they're going to be relatively flat.

Okay. Previously, you've alluded to the fact that you didn't perceive the need for equity in '11. Do you still think that holds?

In '11? We see no need for equity in 2011.

Kind of given where we are with the bonds depreciation, do you think that might be true for '12 as well?

It's too early to tell right at this point in time.

I guess there's a lot of projects up in the air right now; okay.

That's exactly right. We told you when we had more clarity from a regulatory front, we'd be able to speak to that.

I think that's it; thank you.

Thanks, Paul. And by the way, just a question that Brian Russo asked before -- 275 megawatts is the contract that we have through '14; that'll be done at the end of 2014. I hope that helps.

Michael Klein, Sidoti.

Hi, guys.

Hi, Michael.

A quick question -- can you just go over the items that you backed out? I believe there was $0.07 related to NOLs and $0.02 for cold weather. Can you just go through that again?

Sure. And I just want to remind folks, this is based upon kind of where we are on a year-to-date basis, not on the quarter. And the numbers that I talked about, we would back out -- in other words, the $0.07 for the tax benefits associated with state NOLs. So that's a favorable benefit on a year-to-date basis. Our expectation is that's a one-time item; we back that out. So that's $0.07.

We also back out $0.07 for colder weather's impact on our gas and electric business -- and to be frank, that's primarily gas -- benefited from the first quarter.

And then we would add back $0.05. Remember, the first two we're backing out; this one, we're adding back. And this is adding back $0.05 for lost transmission revenues related to the strong hydro and the fact that that is such a significant impact on our transmission business, the high hydro that we had in the Pacific Northwest.

Does that help, Michael?

That does, thanks. And how much are you looking to spend on natural gas reserves, assuming Battle Creek goes into rates? Have you guys had a number?

No. We've had, in our infamous page that we've talked about -- it's page 16 that we have shown investors. There's a range there that's zero to $200 million in terms of investment that we would have on the natural gas reserves. Excuse me -- it was $100 to $200 million. And so I think we've always said if there is a favorable response from the commission, that that's a great way to hedge for customers to provide stability in terms of gas reserves, which we truly believe it is. But if we get support from the commission in that regard, we would certainly want to invest more of that to provide additional protection for customers.

Okay. Have you guys had any additional conversations about future acquisitions or are you waiting until Battle Creek goes through before you proceed any further?

We've had conversations; can't really comment beyond that. Certainly clarity from the commission on the Battle Creek proceeding will be helpful. But we continue to look at the market for sensible opportunities.

Okay. And as it relates to MSTI -- I know you guys aren't too optimistic. But it seems like you're a little more upbeat about it now. Is that just me reading too much into it or --?

Well, I wouldn't agree that we're not optimistic. We think it's a good project. As we've been discussing for a very long time, it's difficult to get a project like this built in like a quick timeline. It's hard to overstate the value of the WECC process. One outcome of the WECC process is some more flexibility around siting -- for example, it will potentially allow us to look more closely at what's referred to as the northern route, spacing -- moving a future MSTI line closer to the existing 500 kV for a significant part of its route. We're very pleased with the consultations that BLM is doing at the local level.

And some other actually fairly positive activity on the ground that's led to some almost bottoms-up discussions around siting alternatives at the local level. So I'd say these things are always very difficult but there are some reasons to be really fairly pleased with some of the things that are happening at the siting level.

Okay, great. And lastly, just in California, kind of as it relates to that, what percent of renewables have to come from in state? With their new, I guess, updated mandate.

We're welcoming Mike Cashell to this call in his new role.

Of the 33%, the latest numbers that we understand have to come from in state are 25%.

25% of the total?

No, I'm sorry -- it's 75% of the total; 33% has to come from in-state resources; 25 can come from out-of-state resources.

Okay, great. All right, thanks, guys.

Jonathan Reeder, Wells Fargo Securities.

Good afternoon, gentlemen. Could you clarify -- with the guidance range you provided -- is that on the adjusted basis, Brian, that you walked through, or does that just include all the items?

Yes, what we did there, Jonathan, is we gave you those as items that we would adjust from our original guidance. And our guidance would be our adjusted guidance. So the guidance --

Based on the 110, you see that growing still within the 225 to 240 range?

Right. Our adjust guidance, or our adjusted earnings for year to date is $1.10. And with what we expect for the remainder of the year, we expect to be in the range of $2.25 to $2.40.

Okay. And then could you provide, I guess, some clarity from the Analysts' Day? You talked about the drag from OG&A going into the year being a lot higher -- I think it was $0.25 to $0.35. It looks like first half, we might have already exceeded that range just a bit. So I guess in the directional commentary for the remainder of the year, do you expect, I guess, the OG&A to actually be down, or just not as elevated where we're still going to exceed kind of the range from Analysts Day.

I think what I would say to that, it's not going to be -- it's going to be down from the second quarter levels. It's going to be a bit higher than I think than our original guidance we provided to you there. But from a second quarter perspective, the main reason -- there's two main reasons why we expect to have expenses be lower in the third and fourth quarter than they were in the second quarter level.

The first and foremost is, from a capital spend perspective, we've only spent about 33% of our capital in the first half of the year. We have -- 66% will be spent in the second half. We'll be capitalizing more of those labor and operating costs in the second half than we did in the first. So that's the first reason.

The second reason is as a result of primarily due to the transmission revenues that we talked about, particularly Oasis revenues, we've put in place contingency, certain spending, primarily in the non-operating areas, but contingencies throughout the business, to try and offset that loss in margins. And that's going to help us as well in the second half.

The key point there is we're focusing on some valuable but discretionary -- savings, not operational.

Okay. And then, just remind us, Bob, in the OG&A, there was nothing regarding your increased kind of maintenance spend in Montana because that's all deferred, right? The increase?

Yes, on that score, we did -- we had higher spend. We were building the higher spend in our maintenance and we had higher labor as well just because, with your normal wage increases, than we would have had on year-over-year basis. DSIP is going to be on top of that. And the spending on top of that is going to be captured in the regulatory asset.

But I do want to be clear that on a year-over-year basis, ignoring DSIP, our expenses are higher on the operating expense side and the labor side. Does that make sense?

It does. Thanks for the additional clarity.

Thanks, Jon.

Chris Ellinghaus.

The 275 number that you quoted on Colstrip, is that the remaining amount? I seem to recall that the contract's already started to step down and it was originally maybe closer to 325 megawatts -- is that right?

Chris, I'm going to let Kendall Kliewer, our Controller -- he's the one that's looking up these megawatts. I'm going to let him speak to that.

Chris, that's the remaining amount in 2011. I don't have handy what it steps down to by 2014.

Okay. Bob, you were saying why build to replace PPAs. Are there assets currently available on the market in Montana, and have you had any material discussions with anybody so far?

I think I'll decline to comment on that.

Okay. Can you talk about the wind development in Montana of late? Has there been more activity?

The way I would characterize activity is that the -- I think of it as the large end of the funnel with project concepts. Fewer high-concept projects at the big end of the funnel. At the smaller end of the funnel, more projects actually converting into reality. I think Mike can speak to our queue there. Mike, why don't you do that?

Yes, that's essentially right, Bob. I'd say that we really have a transition from projects that are beginning their connection process to those that are actually getting to signed interconnection agreements. So therefore the queue numbers are transitioning from those that are just beginning to those that have actual arrangements to interconnect.

Have things picked up in the last 12 months?

I think for certain developers the answer is yes. And in part that's reflected in the BPA announcement.

Okay. All right, thank you very much.

Thank you.

Paul Ridzon.

Brian, did you say 47% is typically your H1 earnings allocation?

Yes, over the last three years. What we did is we looked at the last three years and you take the first two quarters and they represent, on an average basis, 47% of the total year. The second quarter -- as you folks know that follow the Company, the first and fourth quarter are our two largest quarters and they typically are relatively the same. The third quarter, we get a bit of electric peak, of course, because of the summer months, and the second quarter is our lowest quarter in general because it's just a shoulder for both -- winter and summer peaks. There's just not a lot of activity that goes on that second quarter.

So you'd expect with that kind of profile that your first half is going to be less than 50% in general. And what we did is we went back and looked over the last three years, and that averaged approximately 47% in the first half.

And that's on an adjusted basis?

That's a good question and that is not on an adjusted basis. That's based on gas, Paul.

Okay. And what was the standard deviation on that 47%?

Good question, Mr. Ridzon. I do not have the answer to that.

Okay. Bob, obviously we've seen a lot of M&A activity in the sector. Do you think that the history in Montana kind of makes it a nonstarter? I mean, could we work through this if the opportunity were there?

No comment.

Okay, thank you.

Thank you. Good try, though.

(OPERATOR INSTRUCTIONS) Brian Russo.

Hi. Just want to be clear on the South Dakota peaker. The contract capacity contract, I think it's with Mid-Am, expires at the end of 2012 so that will not be renewed. Therefore you are developing the South Dakota peaker plant which will be operational in '13? Is that the way to look at it, or is it still in some sort of limbo status where you're waiting to hear back from the capacity contract provider and then subsequently would need preapproval from South Dakota?

There isn't a preapproval process in South Dakota. We're moving ahead with project development. Your characterization of the situation there, though, is correct other than that.

Okay. So I guess you'd have to start spending later this year?

That's correct. We will spend less than half of that total spend this year, Brian. I'd also point out we do want to try and get it done by the end of '12 for depreciation purposes.

Okay; thank you very much.

Thank you. At this time, we have no additional questions in queue. Please continue.

I have one response and -- Chris Ellinghaus, we're still trying to get you your answer on megawatts. We went from 275 megawatts -- that contract goes down to 200 megawatts in '12. By the end of '14, all of those megawatts are gone from a PPL perspective.

Okay. If there's nothing else, thank you again for joining us this quarter. Look forward to visiting with most of you again next quarter and many of you before. That concludes the call.

Operator; Thank you. Ladies and gentlemen, this conference will be available for replay after 5.00 p.m. Central Time today through August 27, 2011, at midnight. You may access the AT&T Teleconference Replay System at any time by dialing 800-475-6701 and entering the access code of 209282. Once again, that telephone number is 800-475-6701, using the access code of 209282.

That does conclude your conference call for today. We do thank you for your participation and for using AT&T's Executive Teleconference. You may now disconnect.