Good day, and welcome, everyone to IDACORP's First Quarter 2012 Conference Call. Today's call 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 on the company's website at www.idacorpinc.com. [Operator Instructions] At this time, I'd like to turn the call over to the Director of Investor Relations, Mr. Lawrence Spencer. Please go ahead, sir.

Thank you, Deanna, and good afternoon, everyone. Welcome to our First Quarter 2012 Earnings Release Conference Call. We issued our earnings release before the markets opened today, and that document, along with our SEC Form 10-Q, is now posted to our IDACORP website at www.idacorpinc.com. We will be using a few slides to supplement today's call, and these are also located on our IDACORP website. We'll 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 President and Chief Executive Officer; Darrel Anderson, Idaho Power 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 questions during the Q&A period. Before turning the presentation over to Darrel, I'll cover a few details with you. First, our Safe Harbor statement is on Slide 3. Our presentation today contains forward looking statements, and it's important to note that the company's future results could differ materially from those discussed. While these forward-looking statements represent our current judgment on what the future holds, these statements are also subject to risks and uncertainties that may cause actual results to differ materially from statements being made today. As a result, we caution you against placing undue reliance on these forward-looking statements, which reflect our opinion only as of today. A discussion of factors that could cause future results to differ materially can be found in Slide 3 and in our filings with the Securities and Exchange Commission, which we encourage you to review. Referring to Slide 4, I'll briefly discuss the financial results from today's earnings press release. First quarter 2012 net income attributable to IDACORP was $24.9 million, $4.8 million less than last year's first quarter. Idaho Power's first quarter 2012 net income was $25.8 million, $4 million less than the first quarter of 2011. Notably, the first quarter of 2011 included the use of $3 million more in additional accumulated deferred investment tax credits than the first quarter this year. Importantly, as indicated in today's earnings press release, based on these results, we are reaffirming our current full year 2012 IDACORP earnings guidance in the range from $3 to $3.15 per diluted share. I'll now turn the presentation over to Darrel to discuss other key drivers for the first quarter and review our key operating and financial metrics.

Thanks, Larry, and good afternoon. We're changing the order of today's call a little bit from previous calls. I will begin by reviewing the results for the quarter and update you on key operating and financial metrics. Steve Keen will then discuss our liquidity and financing activities for 2012, and LaMont Keen will wrap things up by providing an update on our Langley Gulch natural gas-fired facility and other business-related matters. We will then stand for your questions. On Slide 5, we present a reconciliation of net income attributable to IDACORP from the first quarter 2011 to the same period in 2012. This reflects a decrease in net income of $4.8 million. The full reconciliation table is included in the Form 10-Q we filed this morning. Operating income was positively impacted by $5.1 million due to base rate changes, pension expense recovery and changes in power supply costs, net of the related power costs and fixed cost adjustment mechanisms. However, warmer-than-normal temperatures during the first quarter 2012 compared to 2011 contributed to a $2.8 million decline in operating revenues from last year's first quarter. Heating degree days were 10% lower than last year and 13% less than normal, which contributed to the reduction in operating revenues for the quarter. Operations and maintenance expenses increased $7.8 million over first quarter 2011. The increases were attributable to increased pension expense of $3 million concurrent with increased recovery of deferred pension costs in rates, labor and related expenses of $2.3 million and $2.4 million in expenses primarily related to our Smart Grid program. The quarter included a smaller amount of additional accumulated deferred investment tax credits, or ADITC, versus last year of approximately $3 million which directly reduced earnings. Offsetting these reductions were increased earnings of Bridger Coal Company of $3.4 million and…

Thanks, Darrel. I will begin with a discussion on cash flows for the quarter, discuss briefly our liquidity position then conclude with our recent financing actions and a look ahead at future financing needs. Slide 9 includes a portion of this information. IDACORP's cash flow from operations for the first quarter of 2012 was $37.7 million, a decrease of $55.5 million from first quarter 2011. The reduction was largely due to $34 million in pension plan contributions in the first quarter of this year whereas no contributions were made in the first quarter last year. Also, IDACORP had net income tax payments of $0.2 million this year compared with net refunds of nearly $13 million in last year's first quarter. And finally, changes in regulatory assets associated with the Idaho and Oregon power cost adjustment mechanisms reduced cash flows by $22 million. IDACORP and Idaho Power currently have $125 million and $300 million in credit facilities, respectively, which are available until the termination date on October 26, 2016. Commercial paper outstanding at IDACORP as of March 31, 2012, was $61.5 million compared to $54.2 million at December 31, 2011. Idaho Power had $1.5 million of commercial paper outstanding as of March 31, 2012, and non-outstanding at the end of 2011. Modest cash balances at both IDACORP and Idaho Power leave us with $69.4 million and $301.5 million, respectively, in available liquidity. Also, as of March 31, 2012, there were 3 million IDACORP common shares available for issuance under our continuous equity program, with none issued during the first quarter of this year. On April 13, 2012, Idaho Power issued $150 million in principal amount of first mortgage bonds equally divided in 2 tranches of 10- and 30-year bonds. The 10-year bonds were issued with a 2.95% coupon rate, and the…

Thanks, Steve, and good afternoon everyone. In early April, we conducted a successful first fire of the 300-megawatt natural gas-fired Langley Gulch power plant. This began the final phase of testing for our newest power generation resource. On Slide 10, we present some details about the Langley Gulch plant. We have requested recovery of the $60 million annual Langley Gulch revenue requirement in the Idaho jurisdiction to be effective July 1 to coincide with the power plant's in-service date and the $3 million annual increase required in the Oregon jurisdiction with a lesser effective date though the Oregon commission schedule provides for the new rates effective March 2013. We anticipate the plant will be ready to serve customers this summer when demand on Idaho Power's system is at its highest. Our 2 major transmission projects, the 1,150-mile Gateway West and the 300-mile Boardman to Hemingway project continue to move forward. We are working with the Federal Rapid Response Transmission Team created last year to expedite environmental reviews and permitting, consolidate decision-making and streamlining and consolidate the myriad of legal, regulatory and other hurdles that inevitably arise from these proceedings. With regard to a separate regulatory matter, in March, Idaho Power filed an application with the IPUC, seeking a temporary stay of its obligation to enter into new power purchase agreements with Public Utility Regulatory Policies Act, or PURPA, power producers. And while the IPUC denied Idaho Power's request for a stay in a March 22 order, the IPUC initiated interim protection for our customers. The IPUC provided that it would individually evaluate all contracts for PURPA projects over 100 kilowatts entered into by Idaho Power and presented to the IPUC for approval. The IPUC noted that Federal Energy Regulatory Commission regulations require that the purchase price under PURPA contracts be…

[Operator Instructions] And the first question will come from the line of Paul Ridzon, KeyBanc.

Could you touch a little more on the seasonality of rates? Is this a volumetric phenomenon with higher rates, or is there some rate design with higher summer rates that's going to multiply volumes up?

Paul, this is Darrel. I'll start it off and we'll see where it goes from here. But remember, we have seasonal rates in place that kick into effect in June, July and August. They go for that 3-month period during our heavy low period. And so there -- it's a 3-tiered structure which basically goes the higher -- the more usage you have, the higher the rate it ends up being. And so there is a volumetric component to it as well as a price component to it. And so if you look historically over the last 2 years, arguably that the third quarter has historically been our largest earnings quarter when you go back and look at history because if it where seasonal use hits for us and then obviously the shoulder periods, which generally this first quarter is one of those periods, and then you take a look at depends on what happens in the second quarter because we could see the effect of those higher rates in June with our irrigation load and cooling load coming on in June depending on what happens with the weather.

And just I wanted to maybe clarify what you said about Hoku. You don't expect any earnings impact in '12?

Well, what we said is we've attempted to protect the company's benefit under that agreement. And so what we have disclosed really is what we expect to be the amount of revenue we would recognize in the current year. If they don't pay then yes, we could be impacted. But under the assumption that they continue to pay under the agreement, we protected the company in the extension of the agreement. What we did was share with you the quantification of what the revenue impact is expected to be.

And worse case you could, I guess, dip into ADITCs if necessary?

That's correct.

And the next question comes from the line of Brian Russo, Ladenburg Thalmann.

Could you just remind us of your dividend policy, please?

Sure. LaMont will talk to you about that, Brian.

Certainly. And again, it's laid out in the 10-Q on Page 51, similar as it was into our 10-K for the year, that the board established a dividend policy of 50% to 60% payout over a time frame going forward, with the usual qualifying factors with regard to timing of that and other economic and regulatory considerations we would have on our system. So we are proceeding with that. We increased the dividend in January. The board reviews that on an ongoing basis, and the expectation is over time, we will progress toward the goal that the board set.

Any possibility of a second increase in 2012? Or is this kind of like an annual increase type of profile?

The board hasn't set anything that says whether it's going to be viewed more than once or only annually. So I have to say it's their discretion, and it's viewed on an ongoing basis. As I said last quarter, it's probably not unreasonable to anticipate some kind of at least an annual review with regard to that since we've established the policy. But they're not bound by that. They can look at it at a period of time. And the thing I'd note now, as you notice, we have rate requests in Idaho and Oregon for a considerable amount that the regulator's going to be deciding upon over the next 2 or 3 months. Obviously, I think at this point it's prudent to verify that those things are approved as requested or nearly so. So having that behind us sometime later in the year, then it's the board discretion whether they wait till first of next year to do something.

Okay. Understood. And remind me, what is the ADITC balance, the total balance on the books?

I think, Brian, it was probably -- it was a $70 million plus maybe, I don't know that number off the top of my head, but it's $70 million plus in that range. And as you know, under our current agreement, we have up to $45 million available to us over this 3-year period.

Okay. And they don't expire, right?

Brian, this is Steve. They don't expire but there is an amortization of that amount on an annual basis. So they do decline a little bit regardless of whether we use any additional amounts or not. But it's a fairly long amortization period over the life of the plant, so it's have a slow run.

And could you give us an idea of what your year end '12 rate base will look like? Or at least year end '11 rate base, actual?

Brian, we don't actually have that. I mean I think the -- we make some reference, I'm trying to think, we have some disclosures in the 10-Q about our overarching rate base in Idaho and where we talked about -- on Page 52 of the Q, we talk a little bit about what our Idaho jurisdictional rate base was. At the end of December, which was 2 points -- in that case, $2.36 billion. But I don't have any further break of that handy with us today.

Okay. But you said $2.36 billion as of December 2011?

Right, and that's Idaho jurisdictional component.

Okay. And then lastly, I think the Boardman-Hemingway line is supposed to be operational in 2016. Is that timeline still realistic?

Brian, I'm going to have Vern Porter who leads our transmission effort there and he spends a lot of time with this area. We'll have Vern just talk a little bit about what's coming up with respect to Boardman to Hemingway.

Thanks, Darrel. Well as we laid out in the Q, the 2011 Integrated Resource Plan calls for a 2016 in-service date, and it would bring some immediate reliability relief to us benefits. But the actual date is actually going to depend on permitting and regulatory approvals, of course, and also the needs of our partners. We announced earlier this year that we're partnering with PacifiCorp and Bonneville Power on the permitting of this project. And so as we move forward into the 2013 integrated resource planning and we'll be taking a close look at that in-service date and having further discussions with our partners, and if there's a change, we'll get that information posted and we'll let you know.

Okay. I guess if the transmission line gets delayed, will you run into reliability problems in 2016?

No, we won't. We will -- in our integrated resource planning, we'll take that into account and take necessary measures to ensure we have reliability.

Right. So if there's no transmission line, would you need to build a CCGT?

Brian, this is Darrel. I think one of the things to think about is, again, as we gear up for this next IRP, we'll be looking at all those alternatives. And as you know, I mean, we can look at a number of different options. We -- in order to meet those needs, one of those could be a new peaker plant, could be a combined cycle plant. As you know, we did build Langley such that it's expandable out there. The footprint there is such that we could expand it. And we would just look at a lot of different options as, again, as far as IRP if we don't believe we can hit that 2016 date. And so there will be a number of options on the table. But we, again, we will just have to evaluate each of those and see which is the more appropriate path.

And the next question comes from the line of Sarah Akers, Wells Fargo.

Question on the $5.4 million of pretax revenues that Hoku's drive -- or that you would expect to collect from Hoku in 2012. Has that -- has any of that been received so far? Does anyone have a news?

Sarah, we're reluctant to comment too much on individual customer activity. But I will say to date, they are receiving service, and the only way they would continue to receive [ph] service is as long as they're current on their payment.

Okay. And then if they were no longer receiving service, would there be any offsets in the form of lower costs?

Well, I think that there would be possibly modest cost. We'd have to kind of look at it in the context of the entire portfolio of total requirements of our system. So today we look at those -- when we look at Hoku and everybody else, we plan as if -- we look at it from a system perspective. So depending on -- LaMont talked about some of the new loads that are coming on already. And so as those loads come on and if that load doesn't either come on or accelerate, we have to balance all of that as we look forward to the client prospects. So the actual -- identifying that cost is somewhat difficult.

Okay. And then lastly on Hoku, it looks like the Commission on April 23 approved a notice of termination for service. Can you comment on kind of what the status of that is?

Yes. I think that -- they actually -- they received a notice because they were -- they hadn't paid and they have then subsequently paid.

[Operator Instructions] And that concludes the question-and-answer session for today. Mr. Keen, I will turn the conference back over to you.

Well actually, this is Darrel, and I just want to remind everyone that first of all, our annual shareholder meeting is coming up on May 17 and we will be webcasting that live. We thank you all for participating on our call today, and have a great day.

Thank you.

And that concludes today's conference. Thank you for your participation.