IDACORP, Inc. (IDA) Q4 2012 Earnings Report, Transcript and Summary

Good day, and welcome, everyone, to IDACORP's Fourth 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 would like to turn the call over to the Director of Investor Relations, Mr. Lawrence Spencer. Please go ahead, sir.

Thank you, Tahisha, and good afternoon, everyone. Welcome to our fourth 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-K, 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'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'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 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 statements 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 the factors and events that could cause future results to differ materially from those included in the 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. Second, on Slide 4, we present the quarterly and year-to-date financial results. As you can see, IDACORP's fourth quarter 2012 earnings per diluted share were $0.33, which was $0.15 per diluted share more than last year's fourth quarter. On an annual basis, IDACORP's 2012 earnings per diluted share were $3.37 compared to $3.36 per diluted share in 2011. I'll now turn the presentation over to Darrel to discuss our results in greater detail and review our 2013 key operating and financial metrics.

Thanks, Larry, and welcome. I'll start today with a reconciliation of our earnings from 2011 to 2012. On Slide 5, we present a reconciliation of net income attributable to IDACORP from 2011 to 2012. The schedule reflects an increase in net income of $2.1 million from $166.7 million to $168.8 million. A full reconciliation table is included in the Form 10-K we filed this morning. Operating income increased $86.3 million over last year and was positively impacted by $65.2 million due to more timely recovery of revenue requirements through rates due to increases related to the Langley Gulch power plant and certain of our regulatory adjustment mechanisms. Higher sales volume driven, primarily by a warmer common dryer spring in 2012 that caused significant increases in irrigation usage when compared to the prior year, increased operating income by $16.1 million. Cooling degree days were up 18.4% over last year and were more than 35% greater than normal. On July 12, 2012, Idaho Power reached a new system peak of 3,245 megawatts. The previous peak has been set on June 30, 2008. Precipitation during 2012, on the other hand, was very close to normal. Both factors influenced our general business customer usage, especially in the third quarter, when rates were higher under our tiered and seasonal rate structure for our residential and small commercial customers. Irrigation usage per customer increased due to agriculture growing conditions including warmer temperatures that allowed our earlier planting of crops and due to lower relative springtime precipitation. Payroll-related expenses decreased income by $6.8 million. Changes in depreciation, property tax and others coupled with the change in the allowance for funds used during construction lowered operating income by $13.2 million. As a result of the impact on 2012 earnings of the rate and sales volume increases, Idaho Power recorded $21.8 million of sharing benefits during the year related to the settlement agreement approved by the Idaho Public Utilities Commission in December 2011. The agreement provides for sharing with customers of a portion of 2012 Idaho jurisdictional earnings exceeding specified levels of return on year-end equity. Of the total, $14.6 million was reported as additional pension expense, which will benefit Idaho customers by reducing the amount of deferred pension expense that will need to be collected from customers in the future, and $7.2 million was the provision against current revenues to be refunded to customers through a future rate reduction. In 2011, Idaho Power recorded a total share and benefit of $47.4 million, of which $20.3 million related to additional pension expense and $27.1 million was recorded as a provision against revenues to be refunded to customers under similar agreements. The net impact between the 2 years for the change in sharing to be refunded to customers was $19.9 million. Steve Keen will provide further information on sharing when I finish my comment. Finally, as shown in the table other income tax expense was up $22.1 million over last year primarily due to higher pretax earnings, offset partially from the ongoing slow through benefit of the recent tax method changes. The year-over-year decrease from the tax method changes along with other minor net decreases reduced net income an additional $56.6 million. On Slide 6, we present our 2013 key operating and financial metrics. Consistent with 2012, we are working diligently to manage operating expenses and expect that 2013 spend to be in the range of what we spent last year. Capital expenditures are expected to be slightly above our 2012 spend levels, and Steve will discuss these items in a little more detail later. You may recall that our 2012 earnings per share guidance provided last February was in the range of $3 to $3.15 per diluted share. That included an assumption of using less than $5 million of additional accumulated deferred investment tax credit in 2012. This year, we are initiating our earnings guidance with an earnings per share range of $3.20 to $3.35, and once again, are expecting to use less than $5 million of additional tax credits. As we have noted before, Idaho Power's results are seasonal, largely reflective of weather conditions primarily temperatures and our tiered rate structure. In 2009, a new power cost adjustment mechanism and year-round tiered rate structures became effective in Idaho. Thus quarterly and annual results from years 2009 forward reflect those mechanisms, and we fully expect the seasonality we saw in those years will be present during 2013. The 2013 estimated hydroelectric generation of 6 million to 8 million megawatt-hours shown on slide is based on current reservoir levels and forecasted weather conditions as of today. This was down from last February's estimated range of 7.5 million to 9.5 million megawatt-hours for estimated 2012 hydroelectric generation. Before I hand off the presentation to Steve, I'd like to discuss a couple of topics of interest for 2013. The first relates to our filing last week of an update to the 2011 Integrated Resource Plan, which included 2012 load forecast data to be used in the 2013 Integrated Resource Plan. We estimate that the average load growth over the next 20 years will be 1.1% annually with a projected median peak hour load growth of 1.4% over the same time period. I'd like to point out how the Integrated Resource Plan is geared more to the long-term at supply and demand rather than the near-term and is updated every 2 years to take into account changing assumptions. Based on these load growth assumptions and assuming the temporary suspension of approximately 400 megawatts of demand response program, the preliminary 2013 IRP forecast that the first resource capacity deficit will not occur until the summer of 2016. You might recall our prior 2011 IRP had included the ramp-up of 82 megawatts of load from the Hoku polysilicon facility in Eastern Idaho and the inclusion of an unspecified special contract customer. These load expectations are now excluded from this new IRP forecast despite the ongoing inquiries of potential new customers and expansion requests from existing customers. Further, what takes place in terms of load growth over the short term is more a function of current economic activity that is taking place in the service territory. We are currently seeing meaningful economic activity throughout our service territory that LaMont will comment on later. However, as there remains considerable uncertainty as to the timing and phase of economic recovery both nationally and in Idaho Power's service territory, Idaho Power's load predictions for each biennial IRP are subject to considerable claims. Also included in the update was a summary of our recently completed coal study. The study concluded that the Jim Bridger plant in Wyoming and the North Valmy Generation Station in Nevada should continue to be included in our resource portfolio and that planned investments and environmental controls are supported based on information we have available today. We will, of course, continue to monitor environmental regulations as they develop and assess the economics of our plant as the Idaho Power concluded in its study. In wrapping up the discussion around the IRP related items, we expect that the 2013 IRP will be available in June of this year. The second item is a brief update on our transmission project. Idaho Power continues to make progress on both major projects. We expect to receive a final environmental impact statement on the Gateway West project sometime during 2013 and a draft environmental impact statement on the Boarman to Hemingway line during the summer of this year. With that, I will now turn this presentation over to Steve to discuss our liquidity position, capital requirements and other topics.

Thanks, Darrel, and good afternoon, everyone. On Slide 7, we show IDACORP's annual cash flows and liquidity position at December 31. Cash flow from operations for 2012 was $249 million, a decrease of $61 million from 2011. The reduction was primarily due to $26 million more in pension plan contributions this year compared to 2011 and $14 million more in cash outflows related to income tax payments. Changes in the timing of actual collections from our power cost adjustment mechanisms also reduced cash flows. While the cash benefits relating to our recent tax method changes were primarily recognized in prior years, bonus depreciation continued to be available during 2012 and it's currently in place for 2013. IDACORP finished 2012 with a federal net operating loss carryforward of $156 million, federal general business tax credit carryforward of $107 million and a $38 million Idaho investment tax credit carryforward. These amounts are expected to provide future cash flows. IDACORP and Idaho Power currently have in place credit facilities of $125 million and $300 million, respectively. Commercial paper outstanding at IDACORP as of year end was $69.7 million compared to $54.2 million at December 31, 2011. Idaho Power had no commercial paper outstanding as of December 31, 2012 or 2011. We also have a $24.2 million amount of contingent bond purchase obligations at Idaho Power, which could potentially utilize available credit. As a result, at December 31, 2012, IDACORP and Idaho Power had $55.3 million and $275.8 million, respectively, in available liquidity under the credit facility. Also as of December 31, 2012, there were 3 million IDACORP common shares available for issuance under IDACORP continuous equity program with no shares issued during 2012 and none expected to be issued during 2015. Recall that last year, we also seized original issuance of IDACORP common stock for IDACORP's dividend reinvestment and stock purchase plan and Idaho Power's employee savings plan. Now as shown on Slide 8, Idaho Power's capital spending requirements over the next 3 years are forecasted to increase over the levels forecasted in 2012. We're expecting to spend between $245 million to $255 million in 2013. For the years 2014 to 2015, Idaho Power's estimate of ongoing capital expenditures was expected to be in the range of $570 million and $580 million. The combined figures for 2013 through 2015 are in the range of $815 million to $835 million. That is an increase of roughly $100 million from our 3-year projection made at the same time last year. Turning now to funding requirements, we have a 4.25% series $70 million first mortgage bond maturing in October this year, and it is likely we will refinance this maturity sometime during 2013. We have $150 million of remaining first mortgage bond capacity on our current shelf registration, which expires in May of 2013. You will likely see us establishing a new shelf registration so that we can maintain access to the capital markets if needed. Beyond this, we do not currently plan to issue additional long-term debt or common equity. However, as we have stated before, we will continue to monitor the capital markets with an opportunistic approach to managing future financing needs. For 2012, we earned above a 10% return on year end equity in the Idaho jurisdiction and therefore, we are again able to share benefits with our Idaho customers. Laid out in slide 9, based on year-end Idaho jurisdictional earnings, we recorded sharing benefits to be returned to our Idaho customers in the amount of $7.2 million for earnings that occurred between a 10% and a 10.5% return based on year-end equity. We also recorded an additional $14.6 million of sharing benefits for 2012 earnings that were above the 10.5% level. The $14.6 million of benefits will be used to lower Idaho customers' portion of pension related obligation, as agreed to in our settlement arrangement. This additional pension funding triggers an equal amount of pension expense that was recorded in operating expense in 2012. As pointed out in today's earnings press release, we expect to amortize less than $5 million of additional accumulated deferred investment tax credits in 2013. The full $45 million of tax credits originally allocated under the Idaho settlement arrangement remained available for potential use in years 2013 and 2014. Now I'll turn the discussion over to LaMont, who will update you on the state and service area economy and recap our 2012 dividend actions.

Thanks, Steve, and good afternoon, everyone. Last year marked our fifth consecutive year of solid earnings performance and growth. As a company, we provided security to our customers and owners during unsettled market conditions by accomplishing earnings, regulatory and operational successes. As indicated on Slide 10, the state's economy continued its upward trend in the fourth quarter and that momentum appears to be continuing in 2013. Idaho seasonally adjusted unemployment rate dropped in December to 6.6%, the lowest rate in nearly 4 years. Exports last year were up 3.5% over 2011 and set a new record at $6.1 billion. In Boise, 2 big downtown construction projects, the $70 million multi-acre jump, multipurpose center and the 253,000 square foot $76 million 18-story office and retail tower with Zions Bank as the anchor business are well underway. These 2 projects will bring jobs and maintain the vibrancy of the downtown core. In the growing Boise suburb of Meridian, the new headquarters for fast-growing, international home fragrance company, Scentsy, continue to expand. Ultimately, the company has stated that it will have a 50-acre campus with the 157,000 square foot office tower, 159,000 square foot distribution center and 105,000 square foot warehouse, driving jobs, tax space and energy use. In the Eastern and Southern parts of Idaho Power service area, there was also expansion in a variety of industries. In the Southern region, the most significant economic development success by far was the Chobani Yogurt Plant built in Twin Falls. From groundbreaking to the first cup of yogurt, the plant was constructed in 326 days and now already employs more than 400 people. In the Eastern region, Allstate Insurance's customer contact center appears on track to add 120 additional people during the first quarter of this year, and the company recently announced that it will be opening a new roadside services center and hiring approximately 225 additional employees who will handle roadside emergency calls for customers throughout the United States. Atco Structures & Logistics, a modular housing manufacturer, added 150 employees. And the Convergys contact center ramped up by 180 employees. Additionally, grocery chain, WinCo, has announced that it will open a new 88,000 square-foot store in March 2013 and plans to hire 200 employees. I will now conclude my remarks by discussing our dividend policy and dividends, another area of growth. As shown on Slide 11, in January 2012, the IDACORP Board of Directors approved an increase in the 2012 regular quarterly cash dividend on IDACORP common stock to $0.33 per share from $0.30 per share, representing a 10% increase. In September 2012, the Board approved the second increase of 15.2% to $0.38 per share. At the new quarterly rate, the annual dividend is $1.52 per share. Our total improvement in dividend payout from 2011 on an annualized basis is nearly 27%. Our payout ratio continues to move closer to the Board of Directors' long-term target of between 50% and 60% of sustainable IDACORP earnings. To that end, based on IDACORP's current estimates for earnings and cash flow, and assuming IDACORP meets those estimates, IDACORP's management continues to anticipate recommending to the Board of Directors an additional increase to the quarterly dividend in September of 2013 of at least 10%. And now I and other members of the management team will be happy to take your questions.

[Operator Instructions] Your first question comes from the line of Brian Russo from Ladenburg Thalmann. Brian J. Russo - Ladenburg Thalmann & Co. Inc., Research Division: Just the midpoint of your 2013 guidance. What kind of low growth assumption is embedded in that?

Brian, this is Darrel. That number is just slightly less than 1%. Brian J. Russo - Ladenburg Thalmann & Co. Inc., Research Division: And is there any way you could split up the '14 and '15 CapEx outlook by year? Or should we just assume 50-50?

Yes, the number really is because we kind of look at all of our projects and so we put them together because sometimes they will move from '14 then to '15 or from '15 back into '14. We try to manage the total spend as we look at that so there's some flexibility in how we manage the spend in each of those years. And we actually do the same thing for '13, but we figured because it is the proxy year, we'll go ahead and we'll give you our range for 2013. But we manage that capital spend on an ongoing basis, month-to-month, as we kind of see what's happening. And with some things you can do that, with some things you can't. So we kind of put '14 and '15 together. The best thing to probably look at is if there was a major project in either one of those that would overshadow one, we would have to be able to tell you about that. But really, when you look at our schedule there, it's a lot of guarantying of the systems, some major -- no Langley Gulch projects are in those numbers today. So that's why we kind of keep those together. It allows us the flexibility in how we manage our business. Brian J. Russo - Ladenburg Thalmann & Co. Inc., Research Division: Okay. And I apologize for not reviewing the IRP draft, but the deficit that you mentioned in 2016, how many megawatts of deficit is that and how do you plan on bridging the gap between that time period and when the B2H line would be up and running?

That number is 84 megawatts. Brian J. Russo - Ladenburg Thalmann & Co. Inc., Research Division: Okay. Okay, so that's manageable without any new build?

It's manageable. And again, that's 2016. And as I said in my comments, the assumption is that we're using the 1% on an annual basis and 1.4% on peak. Those things will move around and we'll have our '13 IRP and then we'll have our 2015 IRP and we'll continue to look at how things are moving along. Brian J. Russo - Ladenburg Thalmann & Co. Inc., Research Division: Okay. And then could you just convey your thoughts on the expiration of the current rate structure 9.5% year end out of your jurisdictional Shareholder equity in '14? Can we expect you to file for an extension of the existing plan or can we expect you to file a general rate case in '14 for the rates in '15?

Brian, this is Darrel again. We're looking at all of those options as we sit here today. Again, we're in the year 2 of that particular 3-year agreement. And obviously, we're early into year 2 of that deal. And so we are going to continue to look at what our options are as to first of all, how many credits will we ultimately utilize between this year and next year? How many might otherwise be available for us to look to through 2015? So we're going to be weighing potential extension. We'll be looking at general rate cases. We'll be looking at other ways that we can balance the impact to the customers and the needs of our owners. And the other thing too, I think -- and LaMont talked about this a little bit in some detail, about some of the growth that's taking place in our service territory and some of it will be dependent on how much growth occurs because that will also be a factor because there is that possibility that you can grow yourself such that you don't have to do anything. And we are seeing positive signs. We have an IRP whose assumptions are set early in or mid to late 2012 and as things move around. That could have an impact not only on the next IRP, but also as it relates to what we might file for. Just to give you -- I want to share this. Some of you guys have been to Boise. But I've been with Idaho Power for 17 years now and as I look out my window, this is the first time ever, at least in my 17-year career, that I see 2 cranes on the skyline. And for those who have been to Boise they know that that's a big deal for us and so there's -- to me, that's a nice sign of what is happening in our region. And again, we'll see what happens on the West Coast and what kind of things happen in California, in Oregon, in Washington. But we are looking to be geared up to meet those needs should they come. And so that's something we'll continue to work with the state on and the economic development activities. But one of the things we're here to provide energy services, and that's what we want to be able to do. And so while we go through this period of '14 and '15, we're going to look at all those things that are there -- excuse me, in '13 and '14 to put us in a position to make some decisions of what we'll do in 2015 and beyond. Brian J. Russo - Ladenburg Thalmann & Co. Inc., Research Division: Okay, so just technically or procedurally, you either have to file for an extension of this existing case or you have to give advance notice of filing a general rate case. Is that how we should look at it?

Yes. Brian, I'm going to have Greg Said, who heads up our regulatory side, talk to you a little bit about what our process might look like as we sit here today versus what steps we would take going forward.

Yes, you've stated it correctly. In order to file a general rate case, we do have to notify the public of our intent to file a case. That comes 60 days before we file a general. Any attempts to extend existing stipulations would not require a 60-day notification necessarily, but would require some sort of notification to the public of our intent to engage with other interested parties to examine the possibility for such extension.

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

Can you repeat what you said about the 400 megawatts of demand response, and specifically, kind how that relates to the 2016 projected deficit? Is that 400 megawatts, if I heard it correctly, already embedded in the supply demand analysis there or a certain level was suspended with whatever amount that was -- or might be suspended, will that be available to meet the '16 deficit?

Yes, Sarah, this is Darrel. I'm going to have Mark Stokes, who leads our IRP process. He's with us this afternoon. So I'm going to let him talk a little bit about what's in the IRP and how we're looking at the demand response program as it relates to IRP. So I'll let Mark kind of talk to that right now.

This is Mark. For our 2013 IRP, the 400 megawatts demand response that you're referencing, we're not including that in our load and resource balance, in that 84-megawatt deficit. And the main reason for that is that there's some uncertainty of what those programs will look like going forward, how they'll operate and be set up. And we're working through those issues both with the Idaho Commission and the Oregon Commission in separate dockets outside of the IRP itself. So depending on the outcome of those cases, what those programs look like going forward, we'll determine the amount and size of those programs and really how they fit into the rest of our operations.

Looking at it, how do they dispatch? What's the price in which they patch at in those particular program? And how do those programs compared to other resource options that we have? So that's why we ask for the suspension of the program so we have time to evaluate those programs in light of all the other resources that might otherwise be available.

Okay, so those demand response programs are one option to meet that deficit, but you're going to compare them with other options as well?

That's right.

Got it. And then separately, given the environmental CapEx that you have through 2015 or so, curious if you've had any discussions with the regulators regarding any kind of writer tight mechanism for recovery of the mandated environmental spend or if that something you think they'd be open to and that you might think about pursuing?

We have -- as you know, Sarah, we do have free approval available to us if we wanted to go and ask for pre-approval on certain projects. And we want to elect early do that on one project at this point, which is Langley Gulch. We haven't necessarily approached them specifically on environmental writers related to CapEx expenditures. We're continuing to assess that the level of CapEx that we have. And as you see, we have -- we do have a table in the 10-K, I believe, on and around Page 16 that kind of details at least for the next 3 years what the anticipated environmental CapEx spend is expected to be. It's not significant in the total of our total spend right now, at least over the next 3 years. And so that's something we will continue to look at options that we have if those numbers experience growth significantly greater than where they are right now. And they do -- we do anticipate in some of the outer years as you -- if you take a look at some of the discussions we have around the CapEx programs around our environmental equipment under the Bridger disclosure out in 2021, in some of those years you'll see some increased potential expenditures out there. Now we'll have to take a look what our options are.

Your next question comes from the line of Michael Klein from Sidoti & Company. Michael Klein - Sidoti & Company, LLC: What's your outlook for irrigation sales for 2013?

Michael, this is Darrel. What I'll do is I'll start it and I might flip it over to someone else here. But the first and foremost, irrigation sales are a really difficult area to predict because right now the ag community is evaluating what is that they're going to plant, how much are they're going to plant. And obviously, and our demand, which is one of the reasons we initiated our demand reduction filings and we did is because in those cases, the ag community need to understand what potential might be out there for any demand reduction programs that might be taking place. So that's one of the reasons we initiated that in December. And so there's just a lot of things out there that go into that. And as you know, I mean, it's really difficult to predict the weather side of things and as we talked about the impact on irrigation this last year was significant primarily because of weather-related activities. And so it's really hard to tell you. I'll -- Mark, you want to try?

Yes. Michael, I don't have that level of detail of information with me, but what I can do is comment just in general. Irrigation sales that we have forecasted in the past have been anywhere in the range of basically flat to maybe about 0.3% kind of a growth rate. So they've been relatively flat, which I think in a lot of ways is probably tied to a lot of the water issues in the state really hampering any kind of expansion in agricultural industry.

Michael, this is Steve Keen. If your question is around the unusually high amount of sales this year that was weather driven, I would say and Mark can back me up here or change, but we don't factor in or repeat necessarily temperatures like that. We do tend to revert to a more normal level when we're looking a year ahead. Michael Klein - Sidoti & Company, LLC: Right because obviously, irrigation sales were high in 2012. And then the update to the IRP, you cited, I guess, a slightly improved outlook for irrigation sales and obviously that's over the long-term. So I'm just trying to tie that back together to maybe the more immediate term, I guess.

Yes, like Steve said, our forecast don't go up to where -- for instance, anticipate the same level of weather-related variances what you might have seen on the actuals in '12, so there is more moderate outlook. Michael Klein - Sidoti & Company, LLC: Okay. Okay, that's helpful. And, I guess, if the IRP update or just the IRP in general is more indicative of the long-term, should we assume load growth greater than 1.1% in the near-term? Is that the way to think about it?

Michael, that's a tough one to answer. I mean, I think we won't know that until it actually happens I mean we're seeing I think what we're trying to communicate earlier in LaMont's comment, is we're seeing a lot of positive economic activity in our service territory and we would anticipate translates into load growth, but that's offset somewhat by again some reductions in usage per customer. And so overall, we're using the 1 -- the 1 point, the 1% plus increase, but it's really hard to say what's going to happen specifically in 2013. We think there are really good indicators right now. But until we see that, it's and weather is a factor for us, I mean, it's extra comment, January, this January of '13 we've gotten off to a good start because it has been one of the coldest January on record in our service territory and we only had handful of days, for instance, that are above freezing in January. And so loads were high in January. And so from that standpoint, it does have an impact. When you look at February, it moderated a little bit. So again, weather does have an impact and to try to say what is the -- look at other economic factors and drivers. It's really kind of hard -- to pin point that, but our goal is to make sure we have adequate resource in which to meet whatever the growth needs are going to happen in our service territory. And that's Mark's challenge with the IRP. It's matching the near-term up with the long-term.

Your next question comes from the line of Paul Ridzon from KeyBanc.

What effective tax rate on a consolidated basis are you assuming in your guidance?

Paul, this is Darrel. When you look at our 10-K, our effective rate is around -- at Idaho Power, I think it was around 17% or so, when you take a look at the 10-K in Note 2. And that spend probably impacted downward a little bit because of some of the tax benefits that we recognized in 2012. We would expect that number to go up slightly higher, assuming more normalized tax items. So something in the low 20s is probably something is where we would probably ultimately can get back to.

Paul, this is Steve. Paul, if you look at Note 2, when you got back there, certainly the items that are singled out are like CapEx, tax method changes, the uncertain tax position. Those lines are things that you wouldn't necessarily expect to repeat. And as you get to the very bottom of the table, there's a line called Other net, and I would say that line has a lot of variability in it. It's a little harder to trend or predict anything on that line. It sometimes has true-up type items for tax issues. So if you'd factor those kind of things out and take a look at that table, I think you would get to at least a reasonable estimate of what the history has been on the rate and then use that to look ahead.

And if I understood your comments, year-end '13 share count should be very close to year-end '12? Is that correct?

That's correct. That's right.

And then just back to the IRP, I mean, ultimately, I guess, the fixed fern [ph] shortfall is Boardman to Hemingway. Is that right way of looking at it?

Sorry, Paul. Could you say that again? Sorry.

The ultimate fix to the growing shortfall '16 and beyond will be getting Boardman to Hemingway online, is that correct?

That will be one of the options that will be evaluated in the IRP. I mean, obviously that was the outcome of our 2011 IRP. Boardman to Hemingway was our highest priority resource again. So they will update that. That's what Mark and his crew are doing right now. He's going through that process. And we kind of really have to wait for the outcome. But anyway, our expectation is that Boardman to Hemingway is a resource that will allow us additional capacity to access resources in a region where we think there will be competitive price resource to acquire and bring home.

So regardless of DTA choosing us ida as a preferred solution to their view of the world, I mean, could you walk away from Boardman to Hemingway?

I think right now -- I mean, I think that you can always walk away from a project at some point. I mean, it was all said and done. But I think based on what we know today and what's out there, we still believe that that's a preferred resource. Again, we have to wait for the outcome of the '13 and obviously,potentially even a '15 IRP as we go through that, but that's where we stand today and we still think it's a very viable project.

So you're still in the process of thinking how -- if you go forward with B2H, you still have a shortfall and that's where you're right now in your current IRP, if I address that?

Sorry, Paul, I'm not sure I understand your comment. Go ahead again. We're not hearing you very well, sorry.

It sounds like B2H is very much strong on the table, but it still out there. So the next IRP in '13 is probably taking a look at how to address the shortfall between '16 when ultimately B2H could be in place?

Okay. Mark will comment on that. I understand what your question is now.

Yes, Paul, this is Mark again. Kind of going back to I think it was Sarah that asked the question about the demand response. What we end up doing with demand response programs going forward I think is going to be an important part of bridging that gap. Like we said, our first deficit we're projecting right now is in July of '16. Where we can't get B2H online potentially any earlier than '18, I think we'd be looking at demand response programs to carry us through a couple of those summers until we could get B2H online. Of course, all that's caveated with fact we do the IRP every 2 years and things are bound to change. So as we pointed out, we'll do another IRP in '15, take a look at it then and see what makes sense.

Paul, this is Darrel. I just want to follow-up on the B2H comment because I think it's also key to understand is our agreement with Bonneville and [indiscernible] is really we're all in through permitting and fighting. And we need to get through that process. And once we get to permitting, deciding and depending on what that outcome is they may be other decisions that are made.

And you have a follow-up question from the line of Brian Russo from Ladenburg Thalmann. Brian J. Russo - Ladenburg Thalmann & Co. Inc., Research Division: Could you just give us a sense of your outlook for Bridger coal, what that unit actually provides in earnings or margins? And then just any level of comfort that the evaluation of environmental spend at the plant that the coal mine supplies. It's not at risk of any retirement?

Brian, this is Darrel. I'm going to start and I'm going to have Lisa Grow comment on. She heads up our power supply segment. One of the things you have to remember about Bridger is it is our least-cost resource from a coal perspective. It is a very competitive resource. As you might have recalled it's a mine mouth facility. So you have the coals right there at the plant, and it's been very efficient facility for us. Yet as we've indicated in our coal study, it will require certain upgrades to certain of the facilities there to meet environmental requirement. But even after assessing all of those issues, it continues to be a competitive resource for us, again, meeting all known standards and requirements as we know them today. And so we believe that there, they continue to evaluate new reserves on site at that facility. So from that standpoint, it continues to be something that's squarely in our resource portfolio as we look forward. And Lisa, I'm not sure if you want to comment on anything.

[indiscernible]

Okay. So I don't know if that answers your question, Brian. But I mean, that's how we look at that resource. You cannot predict what future regulatory or environmental requirements come down the pipe, but that's a pretty competitive resource today. Brian J. Russo - Ladenburg Thalmann & Co. Inc., Research Division: Okay. No, I appreciate the comments. And could you just update us on what your most currently updated rate base is?

Steve?

That's not a number that we really kicked out. I think Darrel and I talked about this earlier, and we didn't publish anything that has that it in. And I guess, I might refer back to how Darrel answered earlier that for late this year and next year, we'll be looking to the year-end equity numbers. We'll be watching rate base. And it has grown substantially with the addition of Langley Gulch and a pretty substantial spend each year over the next couple of years. But we'll be watching that, and it will part of what we factor into the plant and how we address 2015. And watching the combination of what the engine produces with whatever growth comes through the system versus what we might do from a regulatory standpoint, it certainly -- we were very successful the last time that we made an attempt to keep our rates current, to have new rates online as we were going to be coming out of the last tax credit agreement. And that's certainly a viable scenario that we'll be looking at again.

Brian, this is Darrel. One of the things you should at least think about -- I guess, if you think about it from the numbers we've given you before is you think about last year, in 2012, we spent about $240 million or so on property plant and equipment and we had depreciation of about $130 million. So there you've got about $100 million or so of new rate base that's going net of whatever deferred taxes might be associated with those investments. So it is -- we are adding rate base at kind of at around that level. Brian J. Russo - Ladenburg Thalmann & Co. Inc., Research Division: Okay. So just when we do our own forecasting of what your rate base might look like in a few years, should we be aware of any kind of a meaningful deferred tax adjustment or a reduction in kind of the ongoing rate base?

There is an element of that, Brian. Certainly, the most significant one is if you look at the Langley Gulch plant, I didn't bring my -- it's out in our investment books that we've got on posted. We actually have the rate base off of Langley, and rather than being $400 million, it's like $330 million, $340 million, something like was the rate base we posted for Langley. It being a very large plant that landed in a year with bonus depreciation had a little more impact. So I think that one's worthy of note. And there would be some impacts from the annual depreciation off of our normal plant as well. But there's also a lot of deferred tax turning around annually as the plant goes away. So you can't just look at one and not pick up the other. But I would say Langley is worthy of note. You can't describe the $400 million and assume it all went into rate base. Brian J. Russo - Ladenburg Thalmann & Co. Inc., Research Division: Okay. So that adjustment in rate base, that can kind of reflect maybe the deferred tax, not you guys being under budget?

Right. No, that was a good part of what Langley [indiscernible] we have it in our books.

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

I'd to thank everybody for participating on our call this afternoon and your continued interest in IDACORP. Thanks a lot.

Have a good day.

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