Idacorp Inc (IDA) 2010 Q1 法說會逐字稿

Good day, and welcome, everyone, to the IDACORP First Quarter 2010 Conference Call. Today's call is being recorded and is being 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, Regina, and good afternoon, everyone. Welcome to our May 6th first quarter 2010 earnings release conference call.

We issued 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 at our IDACORP 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 and Idaho Power president and CEO, and Darrel Anderson, IDACORP and Idaho Power executive vice president of administrative services and CFO. We also have other individuals available to help answer your questions during the Q&A period.

Before turning the presentation over to LaMont, I'll cover a few details with you. First, our complete Safe Harbor statement is on slide 3. Our presentation today may contain forward-looking statements and it is important to note that the corporation's future results could differ materially from those discussed. A more complete discussion of factors that could cause future results to differ materially can be found in our filings with the Securities and Exchange Commission.

Now referring to slide 4, I'll briefly discuss the financial results from today's earnings press release. First quarter 2010 net income attributable to IDACORP was $16.1 million, $2.8 million less than last year's first quarter.

Idaho Power's first quarter 2010 net income was $18.2 million compared to $19.3 million in 2009. IDACORP earnings decreased by $0.06 per diluted share quarter-over-quarter to $0.34 per diluted share. As indicated in today's earnings press release, the 2010 earnings guidance remains unchanged, in the range of $2.65 to $2.80 per diluted share.

I'll now turn the presentation over to LaMont.

Thanks, Larry, and welcome to our call participants. We thank you for your interest in IDACORP.

Our local economy continued to feel the impacts of the recession during the first quarter, and the warmer than normal winter temperatures and relatively poor economic conditions impacted retail energy sales and, therefore, earnings. First quarter hydroelectric production was stronger this year compared to last year during the same period. Our hydroelectric facilities generated approximately 1.9 million megawatt hours during this quarter compared to approximately 1.6 million megawatt hours in 2009.

However, based upon current snowpack conditions, hydro generation for the year is expected to be between 6.5 and 8.5 million megawatt hours in 2010 compared to 8.1 million megawatt hours in 2009. We continue working with others along the Snake River Basin to find ways to collaborate and keep more water in the river, optimizing our hydroelectric capacity, which, as you know, is the backbone of our generating resources.

And while our earnings were lower during the same quarter this year versus last year, our earnings guidance for the year remains unchanged. Despite the slow economy and anticipated below normal hydro conditions, we continue stepping forward as an enterprise, delivering on our financial and operational commitments and building the business for the long term.

Our three-part strategy, responsible planning, responsible development and protection of resources, and responsible energy use, remains our guide through the recession. During the quarter, progress continued on a range of projects, furthering our long range goals, as shown on slide 5. To date, we've installed approximately 250,000 advanced meters for our customers, with the balance due to be installed by the end of 2011.

Advanced meters are the first step toward preparing for a new era for electric energy. The $47 million Department of Energy Smart Grid Investment Grant allows us to accelerate planned smart grid infrastructure, providing customers more choice and control, and to promote productive relationships with our 490,000 customers.

Progress continues on our Langley Gulch natural gas fired power plant and we remain on schedule and on budget. We anticipate breaking ground this summer and are excited to add this base load generating resource to augment our diversified portfolio.

Our 500 kilovolt transmission projects benefit from the Memorandum of Understanding, or MOU, signed with PacifiCorp in March. While not binding, the MOU sets the foundation for more efficient utilization of the existing transmission system and allows for partnering on new projects for both companies to better serve regional needs.

It calls for joint ownership and development opportunities associated with the Boardman to Hemingway and Gateway West transmission line projects. At its core, the MOU allows Idaho Power to share development costs while implementing the strategies set forth in our 2009 integrated resource plan and meeting our obligation to serve.

On April 30th we entered into a joint purchase and sale agreement with PacifiCorp that established joint ownership for both companies in the Hemingway and Populus substations that are currently being constructed, and executed operating agreements governing our respective obligations at those substations. We will remain the operator of the Hemingway substation and PacifiCorp will remain the operator of the Populus substation in southeastern Idaho. And we will share costs based upon our ownership interest.

Recently we announced the Company's proposed route for our Boardman to Hemingway transmission line projects. You can see the proposed route on slide 6. The proposed route came out of our team's diligent work with landowners and citizens across the region. And I commend Idaho Power employees and the local communities for working together with an open mind and focusing on solutions for the transmission line project.

Our proposed route considers environmental concerns, risk and cost in a way that, if approved by the Bureau of Land Management and other regulatory agencies, is intended to responsibly meet the energy requirements of our customers in balance with the concerns of other stakeholders.

We also moved forward on our regulatory strategy, finalizing the regulatory settlement at our Oregon jurisdiction and making the filings in Idaho consistent with our settlement there. Our annual power -- Idaho Power cost adjustment, or PCA filing, requests rate relief for our customers, improved power supply cost recovery, and an increase in base rates to cover other costs and investments.

Darrel will be speaking at more length about the recent PCA filing for Idaho customers, although I wanted to take a moment to acknowledge all of the hard work and collaboration in reaching a settlement agreement in January 2010. The settlement among Idaho Power, the IPUC staff and intervenor groups provides customers relief for the time when our communities are struggling. Additionally, it furthers our strategy of seeking out innovative ways to provide needed cost recovery and a fair return for our investors.

As part of the settlement agreement, the PCA filing on April 15th provides a $146.7 million PCA rate reduction and an $88.7 million base revenue increase. Under the agreement, we are also able to file with the Idaho Public Utilities Commission to recover costs associated with the advanced meeting -- metering infrastructure project, our pension plan and the fixed cost adjustment decoupling mechanism. These filings were completed on March 15th and we expect the Idaho PUC to rule on all of our filings in late May, with implementation of new rates on June 1st.

We also reached a settlement agreement on our 2009 general rate case in Oregon, providing the Company an opportunity to recover costs in a jurisdiction where we have under-recovered in recent years. The new rates became effective on March 1st, 2010.

I'll now hand it off to Darrel Anderson, who will update you on our financial results for the quarter.

Thanks, LaMont, and good afternoon, everyone.

Today I will discuss the major components of our April 15th Idaho 2010 PCA filing, the reconciliation of earnings from first quarter 2009 to the first quarter of 2010, our liquidity positions at IDACORP and Idaho Power, the current credit ratings at IDACORP and Idaho Power, and finish with a discussion of the 2010 key operating and financial metrics. After that, we look forward to taking your questions.

I'll first discuss the Idaho settlement agreement order as it relates to our April 15th, 2010 PCA filing with the Idaho Public Utilities Commission. This is shown on slide 7. The column on the left shows the amount of PCA recovery above base rates from the 2009 PCA filing, which was $188.8 million. The column on the right shows the estimated breakdown of the components of the 2010 PCA filing.

At the base of the column is the $42.2 million of PCA charges to be collected over the 2010 - 2011 PCA year. As noted earlier, the midpoint of the range of our estimated hydroelectric generation this year is less than the Company's actual hydroelectric generation last year and lower than normal. As a result of this and other factors, we are forecasting net power supply costs at a level higher than our new base power supply costs in the 2010 - 2011 period.

The next two segments on the chart relate to base rates and show the proposed increase in base net power supply expenses of $63.7 million and a $25 million annual base revenue increase. These two increases reset base revenues for 2010 and into the future.

The top segment, or $57.9 million, represents the benefit to the Idaho retail customers for the 2010 to 2011 PCA year, which translates to an average 6.5% rate reduction for the 12 months. The PCA filing is subject to the Idaho Public Utilities Commission's approval. We expect a final order later this month.

Larry already gave you the quarter-to-quarter results, but let me spend a little time talking about the major drivers between periods. On slide 8 we present a reconciliation of net income from first quarter 2009 to first quarter 2010, reflecting a decrease in net income attributable to IDACORP from $18.9 million to $16.1 million.

The benefits of the higher electric rates and other regulatory changes are more than offset by reduced sales volumes and increased operating expenses. The increase in depreciation expense is primarily due to the accelerated depreciation of existing customer meters as we convert the Idaho retail meters to advanced metering infrastructure. We are currently collecting the accelerated depreciation and general business revenues.

Also during the first quarter we recorded -- during the first quarter of 2009 we recorded $3.3 million in life insurance gains that did not recur in the first quarter of 2010. Bridger Coal Co. earnings were $3 million less than 2009, primarily due to higher operational costs. Annual earnings from Bridger Coal Co. are expected to approximate 2009 levels by year-end.

Finally, Idaho Power recorded $4.5 million of accumulated deferred investment tax credits amortization in the first quarter of 2010 in accordance with the 2009 settlement agreement with the Idaho PUC. The amount of accumulated deferred investment tax credits recognized is based on the estimated annual earnings at Idaho Power Co. in the Idaho jurisdiction and as allocated across quarters with the interperiod income tax expense allocation.

I'll now discuss IDACORP's liquidity for the first quarter 2010. Cash flow from operations improved $56 million to $100 million in the first quarter 2010. The increase is primarily the result of changes related to the PCA and PCAM that increased cash flow by $32 million. Increased collections of 2009 year-end accounts receivable add an additional $13 million to cash flow for the quarter.

A 2009 refund of $13 million to Idaho Power's customers made pursuant to an OATT FERC order did not recur in 2010, also increasing operating cash flow. Other net increases in operating cash flow were due to net changes in other working capital accounts, including accounts payable and income taxes.

Cash used for investing activities was $71 million, an increase of approximately $30 million over the first quarter of 2009. Idaho Power's net expenditures for utility plant accounted for the majority of the increase. Refinancing activities during the first quarter 2010 included the net repayment by IDACORP of $28 million in short term debt.

Commercial paper outstanding at March 31st, 2010 was $26 million at IDACORP and none at Idaho Power. Current revolving credit facilities at IDACORP and Idaho Power are $100 million and $300 million respectively, with $74 million available at IDACORP and $276 million available at Idaho Power at March 31st, 2010. Both of these facilities expire in April 2012.

On slide 9 we summarize our current credit ratings by three credit rating agencies. Over the last three months, each credit agency reaffirmed the security ratings, and Moody's Investor Service and Fitch Ratings each revised their rating outlook for both IDACORP and Idaho Power from negative to stable. Because of the outlook change at Moody's, Idaho Power's senior secured debt ratings changed from A-3 to A-2, in line with a prior notching modification applied to utilities with a stable outlook.

I'll now update you on the key operating and financial metrics for 2010, on slide 10. These are also shown in both the earnings release and our first quarter 2010 Form 10-Q, which were both issued earlier today.

While none of the metric ranges have changed since our fourth quarter reporting, I would like to discuss the non-regulated subsidiary and holding company range, along with our decision to stop providing annual tax rate changes -- ranges for IDACORP and Idaho Power.

For the first quarter of 2010, non-regulated earnings and holding company expenses resulted in a net loss of $2.2 million, primarily due to the impact of interperiod tax allocation at the holding company. We continue to expect that combined earnings in holding company expenses will be in the range of breakeven to a positive $3.0 million for the year.

Since the Company has initiated earnings guidance for 2010, the need for tax rate metrics are diminished. In a change from past practice, IDACORP and Idaho Power will discontinue providing estimates of their respective effective income tax rates for 2010. These rates will be affected to the extent Idaho Power uses additional accumulated deferred investment tax credits pursuant to the Idaho settlement agreement and/or changes its tax accounting methods for tax projects, all of which are discussed in the Form 10-Q filed today. IDACORP and Idaho Power are also withdrawing the estimates of their respective effective income tax rates for 2010 that were provided previously.

In our 2009 Form 10-K and our first quarter 10-Q, we discuss a tax project that we are evaluating that would allow a current income tax deduction for repair related expenditures on utility assets that are currently capitalized for book and tax purposes. The level of benefits that we could recognize from this project, if implemented, could lessen the need for additional amortization of accumulated deferred investment tax credits and possibly result in reversal of credits previously recorded.

In addition, Idaho Power and the Internal Revenue Service are jointly working through the impact of IRS guidelines related to uniform capitalization methods. We expect this work to be completed during 2010. Resolution of this matter could also reduce Idaho Power's need to amortize additional accumulated investment tax credits in 2010. The nature of these tax items prevents them from being factored into current computations of interperiod allocation of income tax expense.

This concludes my financial update. Now we'd like to respond to your questions.

Thank you. (Operator Instructions). And your first question, gentlemen, comes from the line of Brian Russo with Ladenburg Thalmann. And your line is open, sir.

Good afternoon, guys.

Hi, Brian.

Just real quickly on Bridger Coal, it seemed to be a pretty meaningful delta in the year-over-year earnings and I was just curious if you could just give a little more insight as to what's going on there.

Well, in the first quarter we did have some increased expenses in the first quarter that, as they worked through that through the balance of the year and as they worked through the pricing methodology for the coal for the balance of the year, they would expect to recoup those increased costs that occurred in the first quarter.

Okay, so, I guess we should see more positive earnings variances out of Bridger Coal for the remaining three quarters?

Right. What I said earlier in the prepared remarks was the fact that we expect that the earnings from Bridger Coal to approximate those earnings that were recorded last year. And so if you take a look at where our annual earnings came in at Bridger last year, you -- we would expect those to come back in and around those ranges.

Okay, great. And then, can you just talk a little bit more about the rate settlement and how that works from a quarter-to-quarter basis? I kind of thought that you kind of trued up your ROE relative to your year-end shareholder equity. But it looks like, I think, if I heard you correctly, you do it on a quarterly basis?

Right, Brian. The tax -- the one component of the tax settlement -- or, excuse me, of the rate settlement was the ability to amortize accumulated deferred income tax credits. So that's one part of it.

As you know, the other parts of it kind of reflect our ability to go back and recoup base rate increases. But the piece around the ITC is the result -- we treat it similar to how we treat other tax items, so we take a look at the estimated impacts of credits that might otherwise amortize and then take that into account in looking at our effective tax rate. And so therefore we do have to look at that on a quarterly basis, not dissimilar to what we would otherwise do with normal -- with interperiod tax allocations.

So I think -- so what we have -- we take an estimate, an annual estimate of what we think the credits are going to be, and then we have to then basically pro rata allocate those along with the rest of our effective tax rate.

Okay. So, does it imply that you guys earned a 9.5% ROE in the first quarter?

What it -- Brian, what we do is we take a look at the estimate for the year. And so in any particular quarter it may -- it doesn't necessarily apply to that particular quarter. What it applies is to our annual estimate is expected to be.

Okay. And you also mentioned earlier that the low hydro conditions is impacting your fuel costs relative to where the PCA is set, or that base PCA. And I'm just wondering, can you talk about kind of the rate mechanisms and structure you have in place to kind of mitigate the incremental fuel costs.

Right. What we talked -- what I mentioned earlier as part of the breakdown of the PCA, what you see there is the $42 million block, it really reflects what our assumptions are for the forecast. And part of that's because we do expect below normal water conditions.

Therefore, we do expect some increment to the base power supply costs, which is the $42 million tranche reflecting not only the water but also other power supply costs that we are incurring, as we're signing contracts and other things, that is putting upward pressure on our net -- on our base power supply costs. So water is one of those components, but we're looking at our entire portfolio of power supply costs.

And so that when you look on page -- excuse me, on slide 7, the first block, that $42.2 million, really reflects our estimate of what that forecast piece is.

Oh, okay. So I guess it's --

So that's how we would --

-- accurately reflecting --

-- to --

-- current fuel costs.

Right. That's how we would be looking to capture those -- what we forecast to be increased costs.

Got it. And could you just comment on your dividend policy, please?

Sure. We're going to -- we'll have -- LaMont will comment on that.

Yes. Thanks for the question. With regard to the dividend, obviously we monitor that on an ongoing basis. It's a decision of the Board of Directors as to if and when we would change from the current dividend that we're paying out. As we look at it, we understand that, as we sit here today, our yield is below that of the industry and probably of the return to investors, the cash payment's a little less than we would expect it to be over the longer haul.

Having said that, as we sit here today, we have an aggressive capital expenditure program. We have rating agencies that are still very watchful for anything that would be perceived as adverse with regard to us doing anything but entirely supporting our credit quality. So with that, I don't think you can anticipate anything soon, but I can tell you that it's on our watch list. And as events change and as we're able, we understand that our investors want part of their return to come in the form of cash at some day maybe a greater level than what we're paying today.

Thanks. Is the board -- does the board review the dividend kind of at one point in the year or is this something that they could review quarterly or however the meeting schedules are?

They could do it at any time. But typically we do at least once a year, typically in the May or the September meeting give them a thorough update of where we stand versus the industry and versus other indicators of where we think the dividend might be. And we will do that again this year as well. And again, it's always their prerogative. But I do still want to caution that probably a change in dividend policy for us is not in the near term future.

Okay, thanks a lot, guys.

Thanks, Brian.

Your next question comes from the line of Emily Christy with RBC Capital Markets.

Good afternoon.

Hi, Emily.

I was hoping you'd comment on the status of your decoupling program, the fixed cost adjustment mechanism.

Sure. What I'm going to do is I'm going to have Ric Gale, who you've heard from before, speak to the status of the fixed cost adjustment mechanism.

Hi, Emily. The Company filed after its three-year pilot to make the decoupling or FCA, fixed cost adjustment, permanent. And after some comment, the commission has issued an order and has essentially ordered that we continue in pilot status for another two years. The commission has on several occasions expressed comfort in the mechanism and pride in the mechanism, so we think ultimately it will continue to be part of our rate mechanisms. It's really delivered as promised over the three-year pilot.

So then what do you think was the -- prevented them from making it permanent at this time?

Well, I think there was enough comment. It is a complex -- I mean decoupling is a complex ratemaking concept. And there was enough confusion between some of the [commenters], including the AARP, who have a national perspective that they're against decoupling, doesn't necessarily apply to our mechanism. But there was enough comments that raised concerns that the commission took a typical response and said we'll pilot it for two more years.

Okay. And if I could switch gears for a minute, I was hoping you could comment on what you're seeing in the Idaho economy, just generally in terms of unemployment. Are you seeing signs of stabilization still or any uplift at all yet?

Emily, that's a great question. This is Darrel. Our recent unemployment rate just came -- or at least through March, really suggests that -- the latest that our Department of Labor has come up with, we're sitting at 9.4% as a state. And the good news there is it's the first decline in that rate in 32 months. So that's good news.

Then some of that unemployment is regionalized somewhat. And in our Treasure Valley area here in the Boise area, for instance, that number is up around 10%. In other parts of our service territory, those numbers are less than 9%. So it kind of depends. And part of the Boise area unemployment spike was due to Micron, which is one of the larger employers in our area, who laid off a few folks. And those -- they haven't come back to bring those folks back on. So that's one data point as it relates to unemployment.

I think the other thing that's going on, one of the things that supports our economy is technology and we're seeing some small signs from some of our folks we have -- we've talked in the past about a polysilicon manufacturer called Hoku and we talk about that in our financial publications because they're a new customer. But they've just recently kicked off a test program, a successful test program, so it looks like they'll be ramping up their operations on the eastern side of our state. And another one of our larger technology companies has announced plans to possibly expand their polysilicon efforts, as well as looking at some other lighting and other technology related areas.

So we're seeing some signs of potential improvement in our service territory and we have -- we also believe from a state perspective, that the state just finished up its legislative session and they worked very, very hard to ensure that we continue to have a good business environment. They focused on a balanced budget, focused on doing that, not necessarily by raising taxes but by managing the outflow of expenses.

And so we think that there's a lot of good signs on being pro-business and being -- so when they -- when you do see a slight up-tick in the economy, we expect that Idaho will be a place that people will want to do business, especially people that want to potentially migrate from other points in the West to what we believe is a very business friendly environment. So we're actually pretty bullish, despite the fact that we did -- we have seen a slowdown in the number of customer additions.

But when you take a look at the -- our sales volumes for the quarter, while they were off, predominantly most of those were really weather related. We didn't -- we don't believe from a customer count standpoint that they -- we've been relatively flat. So we think we're set up for, as soon as some of these green shoots get a little bit larger. So we feel pretty good about where we stand.

Okay, great. Thanks for the color.

Sure, Emily.

Your next question today comes from the line of James Bellessa with Davidson & Co.

Good afternoon.

Hi, Jim.

I'm sitting here and I listened to the explanation about the taxes and no longer disclosing or divulging what your assumptions are there. And I just ask myself, are you the only company, utility-like company that has such tax strategies?

And second, what would it take to get out from underneath those tax strategies? And would your company be a cleaner, better able to be predicted company if you were out from underneath them and might you get a higher multiple on your stock as a result?

Jim, this is Darrel. Let me try to tackle most of that question, if I can. If I miss some points, let me know. First of all, let me kind of explain a little bit why we are different, first of all, from just taxes in general and why taxes have more of an impact on us than maybe other companies.

First of all, you need to remember that we are a flow-through company. That's been [inaudible] both expenses in certain cases and benefits will flow directly through to our income statement. And that's something from a regulatory perspective that's been in place for a long time. For anything other than -- is mandated to be normalized, we are in a flow-through -- we're a flow-through situation. So number one, to the extent we have fluctuations in tax items, whether they be expenses or benefits, they will have an impact on our effective tax rate. So that's the first thing.

The second thing is as it relates to the two items that I mentioned in my prepared remarks around simplified service costs and repairs, those other -- many other companies are doing those things. The impact that those particular items have on us is magnified because of the fact that we are a flow-through entity. So that's why -- one of the reasons why you might see our effective tax rate fluctuate a lot.

And then the third piece of that equation is because of our settlement and because of the amortization of accumulated deferred investment tax credits, they also have, then, a further impact on our effective rate. So that's a couple of things.

Now, as it relates to these projects that we're working on, all we -- we're not doing anything out there that's not out of the mainstream. But we do believe if there's ways that we can maximize cash flow or improve our cash flow from a standpoint of taking allowable deductions that are within the IRS guidelines, we think that's a prudent thing to do. And that's really what we are doing.

And there are other companies, my guess is other companies that you would cover, are doing the same thing. They have a lesser impact because they don't have the flow-through nature so you don't see the fluctuations. But we think, to the extent it's possible, that for us to help manage cash, reduce our need to go out and possibly issue new equity and some of those kind of things, we think those are good things to do.

We try to be as transparent as we can with respect to these projects and these types of things. It just happens that sometimes there is some volatility to that. But we think in the bigger scheme of things that we think they're the right things to do. And to forego those wouldn't necessarily be prudent.

I don't know if I answered all your questions there. But it is -- I understand, maybe, some of the frustrations that can come about trying to estimate some of those things. But we, at the same time, because of the flow-through nature, it does create some of those complications.

In your well received settlement agreement, where you're able to draw on these ADITCs, was it your suggestion in the settlement agreement that you were able to make the adjustments on a quarterly basis rather than a true-up at the end of the year or was this what was imposed upon you to get the settlement agreement accepted?

This is really more about the appropriate accounting convention and recognizing the credits in accordance with interperiod tax allocations.

Thank you very much.

Thanks, Jim.

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

Hey, good afternoon.

Hi, Sara.

A follow-up on the tax question. For the tax project with the repair related expenditures and also the uniform capitalization project, if you are able to take advantage of those, would those be onetime items in 2010 or could the benefits extend in '11 and beyond?

They're -- in both of those programs, there are cumulative benefits as well as ongoing benefits.

Okay, so we -- it could potentially extend even beyond '11 when you no longer have the option to use the ADITCs?

That's correct.

Okay, thank you.

You bet.

Your next question comes from the line of Brian Russo with Ladenburg Thalmann.

Yes, hi. Thanks for taking the follow-up. Just could you remind us of your external capital needs as you kind of ramp up construction on Langley Gulch?

Right. Brian, right now we're actually in the process of assessing that, along with all of our other capital requirements that we have out there. As you know, we've got a capital table that's included in there. And some of it will be dependent upon the level of benefits we may be able to recognize associated with some of the tax items we previously discussed. So we're looking at a number of different scenarios there.

As we look at 2010 financing requirements, we really have minimal financing requirements going through the balance of this year. As we look at 2011, we have requirements -- we have a debt refunding that we have that comes due in early 2011 that, depending on how things go, maybe we do something early on that. But we'll continue to evaluate that. And then it's a matter, really, of the level of capital required, subject to some of these other things that are floating around, as to how much new capital we're going to need to raise in the form of either debt or equity.

And so I don't have a good number for you right now because of that. But I would argue it's fairly modest. Cash has been coming in better than where we're at today. We've spent $77 million to date on Langley Gulch through March and what we've done -- been able to fund that pretty much through internal generation.

So a combination, really, of we have our CEP program that sits out there where we have 2.1 million shares remaining that we can draw upon and would look to consider that. But we don't have any specific plans right now, but we also would consider being opportunistic if it makes sense to do that.

Okay, thank you.

Thanks, Brian.

Ladies and gentlemen, this concludes the question and answer portion of today's call. Mr. Keen, I will turn the conference back over to you.

All right, I'd like to thank you all for your interest in IDACORP and for participating on our call today. And we'll certainly keep you posted as events progress. And have a nice afternoon. Thank you.

Ladies and gentlemen, this concludes today's conference. Thank you for your participation. You may now disconnect. Have a wonderful day.