Good day, and welcome, everyone, to IDACORP's First Quarter 2013 Conference Call. Today's conference is being recorded and webcast live. A complete replay will also be available from the end of the day for a period of 12 months from the company's website at www.idacorpinc.com [Operator Instructions] At this time, I would like to turn the call over to the Director of Investor Relations, Mr. Lawrence Spencer. Please go ahead, sir.

Thank you, Lisa, and good afternoon, everyone. Welcome to our first quarter 2013 earnings release conference call. We issued our earnings release before the markets open today, and that document, along with our SEC Form 10-Q, is now posted to our website at www.idacorpinc.com. We will be using a few slides to supplement today's call, and these are also located on our website. We will refer to specific slide numbers as we work our way through today's presentation. Now moving to Slide 2. On the call today we have LaMont Keen, IDACORP's President and Chief Executive Officer; Darrel Anderson, Idaho Power's President and Chief Financial Officer; and Steve Keen, Idaho Power's Senior Vice President, Finance and Treasurer. We also have other individuals available to help answer your questions during the Q&A period. Before turning the presentation over to Darrell, I'll cover a few details with you. First, our Safe Harbor statement is on Slide 3. Our presentation today contains forward-looking statements. While these forward-looking statements represent our current judgment or opinion of what the future holds, these statements are subject to risks and uncertainties that may cause actual results to differ materially from statements made today. As a result, we caution you against placing undue reliance on these forward-looking statements. A discussion of factors and events that could cause future results to differ materially from those included in forward-looking statements can be found on Slide 3 and in our filings with the Securities and Exchange Commission, which we encourage you to review. On Slide 4, we present the quarterly financial results. As you can see, IDACORP's first quarter 2013 earnings per diluted share were $0.67, an increase of $0.17 per diluted share over last year's first quarter. We are maintaining our 2013 earnings guidance in the range of $3.20 to $3.35 per diluted share. I'll now turn the presentation over to Darrell to discuss the results in greater detail and to review our 2013 key operating financial metrics.

Thanks, Larry, and good afternoon, everyone. Before I get to the quarter-over-quarter reconciliation, I would like to put our first quarter results into perspective. This quarter's results represent our best first quarter performance in over a decade. The combination of strong energy sales, timely price changes related to the Langley Gulch power plant and diligent dividend cost management helped the company achieve the improved results. On Slide 5, we present the reconciliation of earnings from first quarter 2012 to the first quarter 2013. The table shows an increase in net income of $8.6 million from $24.9 million in the first quarter of 2012 to $33.5 million in the first quarter of 2013. The full reconciliation table is included in the Form 10-Q we filed this morning. Operating income increased $19.9 million over the first quarter of last year and was positively impacted by $13.7 million due largely to inclusion of the Langley Gulch power plant in rates beginning in July 2012. Higher sales volumes driven primarily by colder winter temperatures and the addition of over 5,000 new customers caused a significant increase in usage when compared to the prior year, an increase to operating income by $8 million. Heating degree days were up 26% over last year's first quarter and were 14% greater than normal. Overall, general business energy sales increased 5.3% quarter-over-quarter with period ended customers increasing 1.2% over the same timeframe, slightly outpacing the rate of growth we experienced in 2012. The $6 million decrease in allowance for funds used during construction, or AFUDC, was due to Langley Gulch going online in mid-2012, therefore, ceasing the accrual of AFUDC for that project. Changes in other nonoperating income and expenses are primarily from lower coal prices and volumes at Bridger Coal Company, which accounted for the majority of the…

Thanks, Darrel, and good afternoon, everyone. On Slide 8, we show IDACORP's quarterly operating cash flows and liquidity position at March 31. Cash flow from operations for the first quarter of 2013 was $50.6 million, an increase of $12.9 million over the first quarter of 2012. The increase is primarily due to Idaho Power not making a contribution to its defined benefit pension plan during the first 3 months of 2013, while $34 million of cash contributions were made in the first quarter of 2012. Changes in power cost deferral mechanisms from the first quarter last year to the first quarter of this year offset the increase by reducing cash flows by $24 million, while changes in working capital balance accounted for the majority of the remainder. IDACORP and Idaho Power currently have in place credit facilities of $125 million and $300 million, respectively. Commercial paper outstanding at IDACORP as of March 31 was $67.2 million compared to $69.2 million at December 31, 2012. Idaho Power has $16.6 million of commercial paper outstanding as of March 31 and none outstanding at December 31 of 2012. We also have $24.2 million of contingent bond purchase obligations at Idaho Power, which could potentially utilize available credit. As a result, at March 31, IDACORP and Idaho Power had $57.8 million and $259.2 million, respectively, in available liquidity under the credit facilities. Also, as of March 31, there were 3 million IDACORP common shares available for issuance under IDACORP's continuous equity program. No shares issued during the first quarter and none expected to be issued during 2013. Turning now to funding requirements. On April 8, 2013, Idaho Power issued $75 million of 2.5% first mortgage bond maturing in April of 2023 and $75 million or 4% first mortgage bonds maturing in April of 2043.…

Thanks, Steve, and good afternoon, everyone. I'm going to start today with an update on a number of improvements in Idaho economic conditions. One important example is the decline in state unemployment, as shown on Slide 9. According to preliminary Idaho Department of Labor data, the unemployment rate in Idaho Power service area was 6.0% at the end of March 2013. This decline is particularly striking considering that the figure peaked at 10.0% in early 2011. The agency also pointed out in April that Idaho job growth, primarily in services, was significantly stronger in 2011 and 2012 than initially forecast, and it picked up strength in 2012. I'm also pleased to report the 2012 was the latest in a series of 5 years of growth and progress, a trend that has continued into 2013. Even with the economy still in a position of recovery, our general business customer count increased by 5,854 from the first quarter of 2012 to the first quarter of 2013 compared with 4,087 and 2,467 in 2012 and 2011, respectively. We view this as a positive trend. Additionally, the housing market in Idaho Power service territory has improved when measured by foreclosure rates and the available supply and pricing of housing. Idaho Power continues to predict positive customer growth in its service territory for the foreseeable future. Our company has historically received and continues to receive inquiries from potential large load customers, seeking information about locating in Idaho Power service power territory. Notwithstanding these inquiries, based on instructions from the Oregon Public Utilities Commission, the load forecast for the upcoming 2013 Integrated Resource Plan, or IRP, excludes load growth from new but currently identified large load customers. It also uses a 20-year planning horizon for load growth rates. With these assumptions, the IRP includes a 1.1%…

[Operator Instructions] Our first question is from the line of Paul Ridzon.

I was just wondering, as we approach the end of your current rate settlement, how are you thinking about how you want to proceed after '14 and how are you thinking about the bank of ADITCs that you have?

Okay. Paul, this is Darrel. I'll answer that. But before I do that, I want to correct something that Steve said. I guess to kind of reaffirm the cash flow numbers that were on the slides are correct. Steve noted a couple of numbers, but we just want to reiterate the fact that the numbers on the cash flow statement on the slide is the correct number. So that would be cash from operations for the first quarter was $54 million, an increase of $16.3 million over the first quarter of 2012. So I just want to kind of clarify that for the folks. Now back to your question, Paul, regarding what are we looking at as we look forward to the expiration of our current agreement with the Idaho Commission. As I said in my notes, one of the things we're not planning at this juncture to file any general rate case in 2013. We are continuing to assess the business, where we're at with the business, and we will continue to do so through the balance of this year. one of the things we are spending a fair amount of time on is looking at some business optimization opportunities within our own business as we look towards 2015, which is when the deal expires at the end of '14. As Steve indicated, as we sit here today, we anticipate going into 2014 with all $45 million of ADITCs intact. And so again, depending on how 2014 shapes up, depending on how successful we are as we move through our business optimization which will then help us kind of decide what we're going to do beyond 2014. So I can't sit here today and tell you kind of where we're going to be, but I can tell you, we are looking at what is that plan for 2015 and beyond. That's a key area of focus for us as we sit here right now. But I can't -- I don't have anything specific I can share with you today other than we are looking at that.

And then the impact of rates was pretty marked this quarter, and we should get another quarter of that, and the impact of the straight rate structure given the higher summer rates, well, we should have another very strong quarter and then we will have lapped Langley in rates, is that correct?

That's right. And Langley went into effect on July 1. So we do have another quarter of -- when you do a comparability purposes with or without Langley results, that's correct. And as we did indicate, and I would just tell you, as it relates to the weather, as we did indicate, the forecast right now is for drier than normal. We don't know how that actually plays out with respect to load. But it does essentially provide an opportunity for additional sales.

How should we think about that in the context of not changing guidance? Is it just too early in the year?

For us, it's too early in the year. And other thing, I think, that's important to note is when we gave our original guidance, we had provided the guidance around less than $5 million of ADITCs. So in order for us to really move within our earnings band, we have to actually earn that amount, so whatever that ITC estimate we have internally, before we can even start increasing our earnings. And so obviously, we believe as we sat here until the end of the first quarter, we will be able to do that. The question is how much beyond that will we be able to do kind of -- as we sit here in the first quarter, it's really too early to tell. It's a great start to the year, we believe. But we'll have obviously more updates for you at the end of the second quarter.

How do you handicap the odds of being in a sharing view?

I don't have a handicap on that, today. I think that we have to see how the second and third quarter plays out.

Our next question is from the line of Michael Kline, Sidoti & Company. Michael Klein - Sidoti & Company, LLC: Looking at the tax line, do you expect the increase in flow-through tax adjustments to be a good proxy going forward? Or is this sort of a one-quarter event? How should we do you think about that?

One of the things I guess I would -- Michael, in my perspective on the first quarter, if you take a look at all of the things in which you have a chance to digest the quarter, it was arguably one of our most straightforward quarters that we've had in a long time. So you don't have any really kind of items in there like cap adjustments and other things. And so if you look at our effective tax rate as it sits today, that's probably indicative of where we would hope to be through the balance of the year. But it is a what I would call more normal period. Subject to any changes in rules around additional flow-through adjustments that could be positive or negative, I would say that, that number should stay fairly constant, again depending on what happens with tax rules and other things. Michael Klein - Sidoti & Company, LLC: Sure. Okay, that's helpful. And I guess to that point, just how much visibility do you have into the items that impacted tax line? Or is it sort of something that you don't have several quarters of visibility into it? Just curious in terms of planning and more or less just modeling.

Well, I think we have a pretty good handle as to what we can expect. I think the uncertainty, at times, in the past, has been around the level and the amount of additional flow-through adjustments that we are able to sustain depending on what the guidance is provided by the service and depending on what we spend money on and depending on whether it meets certain flow-through criteria or not. So we have a pretty good handle as to what it is, but what we don't -- can't necessarily predict very well is to what extent do guidelines change, rules change, those kind of things. Michael Klein - Sidoti & Company, LLC: Sure, okay. And as you stated, earnings right now are really the culmination of the past 5-plus years or so. And looking out over the next couple of years with the Boardman to Hemingway line not unexpected in service before 2018, how do you think about and how do you see, really, earnings playing out? Is it really just going to be a matter of getting cost recovery on some plain vanilla CapEx while the economy rebounds? Or how do you view that and think about that?

Well, I think if you take a look at what we've shared with you around what our CapEx spending is projected to be over the next 3 years, and we have what we share in the 10-Q, it's upwards of $700 million to $800 million over the next 3 years. And if you think about that in the context of what it is we are depreciating and the net rate base add that's there, that's a pretty good addition to rate base over that 3-year period. So while it may be fairly general base care and feeding of our system and it doesn't necessarily happen to be a Langley Gulch type of add, it is -- we would that's pretty substantial quality investment into our utility system that is -- it's not insignificant.

Michael, this is Steve. I'm just going to add there, the other part that you don't want to lose sight of is I do think one significant change with Langley beyond what it did in terms of our rate base is that we have capacity. And Darrel mentioned in his script, the things we're seeing going on in our service territory in the way of growth is that if you sell more kilowatt than you have the capacity to do that and it's not causing you to shift your costs dramatically when you pick up those new sales, that can have an improving effect on your bottom line as well. So partly, it may come through rate base, but I think we're hopeful, too, that our service economy is one that recovers. And if you get additional sales, that doesn't totally get picked up in a rate model. In fact, if you're not filing, that's really what you get in-between rate filings. And then as you do file, you get a reset. And those become part of your base. So I think as we look ahead, we're still making a determination as to the best course for us. But I think we feel good about the economy and we also look at what we're adding or planning to add to rate base, and we think that's significant as well.

And moving on to our next question from the line of Ashar Khan of Visium.

I just wanted to say you're running the business very well. I just feel as a shareholder if the board can look at increasing the dividends sooner and higher as we have a pretty stable, nice economic growth and you've performed exceptionally well. So I hope the board and the management can look at the review of the dividend sooner and larger this year.

Yes, this is LaMont. I appreciate the comment and we'll certainly factor that into our considerations. At this point, we're still on track to review the dividend again in September. And as management has indicated, it's our intention to recommend an increase of at least 10%. But at this point, we haven't made a determination of what that recommendation will actually be.

Our next question is from the line of Brian Russo, Ladenburg Thalmann. Brian J. Russo - Ladenburg Thalmann & Co. Inc., Research Division: I realize the mechanics of the PCA mitigate the majority of the hydro or exposure to below-normal hydro conditions. But I was just hoping to kind of drill into that a little further. Is a way to look at the $140 million increase, is that, say, 95% of x and then it's 5% of x that the company absorbs? Or is it that the $42 million of the PCA forecast, that is what the exposure is? Just trying to get a better feel for the sensitivity in this hydro season.

Yes, let me -- Brian, this is Darrel. I'll start, and then I'm going to probably flip it over to Greg Said. But one thing I guess I would add, if you take look at and if you try to kind of ballpark kind of what -- I think what you're trying to do is what's the impact of the low-water scenario on the company in light of the PCA that we filed. And one way to look at this is if you take a look at what we regenerated last year, we generated about 8 million megawatt hours last year. This year we've given you a range at this point of 5 million megawatt hours to 7 million megawatt hours. And if you take the midpoint of that, say, around 6-ish or so, you end up with about a 2 million megawatt hour change in the hydro scenario. And one way to look at that is you have to make your own assumption as to what the -- what are the market price or replacement resource would take that 2 million megawatt hours. But if you take somewhere around 5% of that number, you can kind of get a ballpark, estimated impact. But again, the assumptions around that are going to be around what's the market price for replacing energy or replacing energy we might already have capacity for and/or what you might have otherwise sold some of the excess energy might have been generated at a certain time. And though there's some variables, obviously, that go into play and into our calculation in some of our forecasted expenses for the future, but in essence, that can give you some, at least, a ballpark range of what the potential impact is depending on your assumptions. But having said all that, what I'll do is I'll ask Greg Said to speak a little bit to the PCA and some of the mechanics around that and how that might impact us.

As you've noted, the $140 million includes $42 million that's associated with forecasting. So when you're talking about the 95-5 split, that really exists for the entire $140 million. So there's a 95-5 component to the historical piece that occurred already to date. And there's also a 95-5 split that gets you to the $42 million forecast. So the 95-5 goes throughout the entire PCA determination and, at the end of the day, the $140 million represents the 95% that's the customer share. Brian J. Russo - Ladenburg Thalmann & Co. Inc., Research Division: Okay, great. That's very helpful. Can you remind us, in a period of dry and above normal temperatures, how does that impact your irrigation customer base or sales?

Well, this is Darrel. First and foremost, a lot of it kind of depends on what were they looking at early on in the planting season as to what they saw on the horizon as it relates to what it is that they're going to plant because that will then drive, whether it's early or late irrigation. But I will tell you, what we have seen, at least at this point, is early irrigation loads are starting to come on because of the way the weather is. So that's one thing. And then depending on the types of crops that they're planting will also drive how much irrigation will be required and when they turn it off. And so those are the things that when our customer folks are out talking our irrigation customers, that's some of the information they're trying to discern from them as they have those conversations with them, so to kind of understand what's going into the field. Brian J. Russo - Ladenburg Thalmann & Co. Inc., Research Division: Okay. Correct me if I'm wrong, but in 2012, irrigation sales spiked, I think, in the second quarter, maybe. And was that a function of dry and above normal weather?

We were -- I'm going to try and recall. I'm trying to look around here. I believe we were wet early and then it got dry. We were wet during the spring, and so that actually delayed some of the planting. And so therefore, it was a little later irrigation-wise, if I recall. I'm just looking around the room to get a confirmation to that.

It was hotter later on.

Right. But Warren do you want -- Warren Kline is here and do you want to comment on that Warren?

Yes. Of course as we remember, the summer, as the summer went on, we had a real hot spells, which should also increase the usage in irrigation to spike the need to put water to the crops. Brian J. Russo - Ladenburg Thalmann & Co. Inc., Research Division: Okay. So it's possible that a similar dynamic might play out in 2013? I guess we'll just have to wait and see, but it's kind of shaping up that way?

Right, right.

Yes. As we sit here today, it's sort of a very wet spring. But again, we hate to try to predict the weather. Brian J. Russo - Ladenburg Thalmann & Co. Inc., Research Division: Okay, got it. And the $8 million increase in sales volumes, is there any way you can break that down like what part of that was kind of the Langley Gulch contribution and what might have -- and then -- or can you break down what part of that margin was related to above normal weather?

What I'll point you to, Brian, I guess is -- the best thing I'd point you to is kind of just the overall change in revenues overall. We kind of laid that out in the 10-Q. We talked about what's the rate impact, what's the usage impact and what's the amount driven towards just customers. And so what we've talked about for the quarter, we estimate about $9.4 million of our increase is because of usage. Most of that usage is attributable to weather. And then we have about $2.6 million that's attributable to new customers, the over 5,000 new customers that we added in the first quarter. So that's probably one way to kind of look at it as it relates to our total revenue change. And we added about almost $26 million associated with just the rate change component. And then that's offset by an adjustment related to Hoku from last year. So that kind of gives you some sense as to how we -- the overall $35 million change in revenues in total. That's detailed on about Page 42 of our 10-Q.

Our next question is from the line of Sarah Akers of Wells Fargo.

I think you mentioned that the 13 IRP load growth forecasts won't include some of the new customers that you might be getting. And I know the preliminary IRP didn't suggest a need for new-generation capacity. But in addition to these new customers providing sales growth, might there be a need for additional generation resources in the next 3 to 5 years? Or is that probably still not the case with the supply-demand balance?

Sarah, this is Darrel. And I don't want to get in front of the IRP filing, which is coming up in June. And so what I will probably do is defer that until we file our IRP in June. But I will say that -- LaMont's comments around -- there's 2 things at play here. There's what's happening in, I call it, the eye test [ph]. The other one is what we see through the quantitative side of things. And when we start the IRP process, we start that back in 2012, late 2012, and that's when we start making certain assumptions. And so that's what's baked into the IRP as it relates to load. Now as things evolve, there's some things that might happen in the near-term that might be pluses or minuses in the way from what we're doing in the IRP. And what we're saying now is what we see out from the eye test [ph] perspective, is there's a lot of activity within our service territory. As I've told the group of economic development folks the other day is in my 17 years here, this is the first time I look out my office, I see 2 cranes on our skyline, which is a big deal for us here in Boise, and then I'm told there might be a third one popping up pretty soon. So those are some of the anecdotal things that are going on versus kind of what's happening with like our long-term 20-year load forecast. So it's kind of the near-term versus the 20-year look. And so that's why, in LaMont's comments there about what's happening in our region, there's a lot of positive things. But as we look long-term, that does average out over time, which is why the numbers that we have in the IRP, which is the 1.1% long-term growth rate is what we're using, and it's gets about 1.4% on peak. So again, we modify that every 2 years, and those are the assumptions we're using today. And 2 years from now, that might look different.

And so as we think about getting that IRP, I guess, pretty soon here, this summer, might that plan incorporate some of the things that you're seeing in the last 3 to 6 months in terms of that activity? Or will this plan incorporate the old forecast and then 2 years from now, that's when those -- these new customers will be incorporated? Or how does that work? How quickly can...

The plan that's being worked on that is to be published in June will rely primarily on the data that's going to be a little bit older than what we see happening today. And so there's -- just because the way the process works. And so you'll have -- kind of we will look at that, and as we assess what the recommendations are, we'll look at those. But then as we -- we'll restart that process up in about 12 months from now, and we'll start it all over again.

Perfect. And then should we think about the 1.2% customer growth rate, if I heard it correctly, as a good proxy for weather normalized sales growth in the quarter? Or did changes in usage push that up or down for...

I would say that's just the -- on a more normalized basis, that number would be less than 1.2%.

[Operator Instructions] And we have a question from the line of Paul Ridzon of KeyBanc.

Just your kind of bullish comments on growth. How are we thinking about the potential to adopt a sister next to Langley at this point?

Sorry, Paul, I didn't catch all that. Can you...

Your pretty positive commentary around the growth that you're seeing, when do you think you might be thinking about adding another generation resource?

I think that will be a consideration as we continue to evaluate our IRPs. And again, I don't want to comment in front of the filing of our June IRP at this point, but I think that will continue to be an option.

That concludes the question-and-answer session for today. Mr. Anderson, I will turn the conference back to you. Thank you.

We would like to kind of thank everybody for participating on our call this afternoon and your continued interest in our company. And have a great afternoon.

Thank you.

Thank you. That concludes today's conference. Thank you for your participation. Have a great day.