Idacorp Inc (IDA) 2013 Q3 法說會逐字稿

Good day and welcome, everyone, to the IDACORP third-quarter 2013 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, Jackie, and good afternoon, everyone. Welcome to our third-quarter 2013 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 website at www.IDACORPInc.com.

We will be using a few slides to supplement today's call, and these are also located on our website. We will refer to specific slide numbers as we work our way through today's presentation.

On Slide 2, we show the presenters on today's call -- LaMont Keen, IDACORP's President and Chief Executive Officer; Darrel Anderson, Idaho Power's President and Chief Financial Officer, and Steve Keen, Idaho Power's Senior Vice President Finance and Treasurer. We also have other individuals available to help answer your questions during the Q&A period.

Before turning the presentation over to Darrel, I will cover a few details with you. First, our Safe Harbor statement is on Slide 3. Our presentation today contains forward-looking statements. While these forward-looking statements represent our current judgment or opinion of what the future holds, these statements are subject t risks and uncertainties that may cause actual results to differ materially from statements made today. As a result, we caution you against placing undue reliance on these forward-looking statements.

A discussion of factors and events that could cause future results to differ materially from those included in forward-looking statements can be found on Slide 3 and in our filings with the Securities and Exchange Commission, which we encourage you to review.

On Slide 4, we present the quarterly and year-to-date financial results. As you can see, IDACORP's third-quarter 2013 earnings per share were $1.43, a decrease of $0.41 per share from last year's third quarter. Year-to-date 2013 earnings per share were $3.01 compared with $3.05 per share for the first nine months of 2012.

I would now like to turn the presentation over to Darrel.

Thanks, Larry, and good afternoon everyone. IDACORP and Idaho Power had another strong third quarter. The positive operating results, which included historically strong lows due in part to a second straight year of hot and dry weather, as well as solid customer growth, were offset by tax items, including an unplanned tax charge in the third quarter.

On Slide 5, we present a reconciliation of earnings from the third quarter of 2012 to third quarter of 2013. The year-to-date reconciliation table is included in the Form 10-Q we filed this morning.

While net income decreased, we believe two primary factors should be considered when comparing performance for the periods, both of which are shown in the reconciliation table. The first factor was higher operating income due to less revenue sharing in 2013 versus 2012.

Idaho Power operating income improved $7.1 million over the third quarter 2012. A combination of increased power supply costs and reductions in sales volumes attributable to lower usage per customer were partially offset by an increase in sales volume attributable to customer growth.

Weather conditions for the quarter as measured by cooling degree days were similar to the third-quarter 2012 conditions, both of which were greater than normal. We did achieve a new system peak of 3407 megawatts on July 2, up from a peak we set in 2012 of 3245 megawatts. The reduction in revenue sharing costs in third quarter 2013 compared to the same period in 2012 resulted in an $8.7 million increase in operating income.

The other factor was the offsetting impact of income tax method changes and other income tax items recorded in 2013 and 2012. Steve will review the tax method changes in a little more detail when I complete my comments.

Now, moving to Slide 6, I want to expand on our improved operating income in the last three years. The three and nine months ended September 30, 2011, 2012, and 2013 show an improvement that we believe is reflective of the strength of our core business. While both 2011 and 2012 relied in varying degrees on beneficial tax method changes and tax settlements to reach our reported earnings per share, 2013 core utility operations continued to make a meaningful contribution to our growing bottom line.

On Slide 7, we present our 2003 key operating and financial metrics which indicate no changes from our prior estimates we shared with you in August. Due to the results so far, we are increasing the lower end of the earnings guidance range of $3.40 to $3.55 per share to the range of $3.45 to $3.55 per share. With the updated range, we anticipate being in a position to achieve our sixth consecutive year of earnings growth. The new range incorporates the impact of the Idaho sharing mechanism under Idaho Power's December 2011 regulatory settlement agreement. The sharing mechanism reduces the rate of earnings growth within the range as earnings move from the 50% sharing level to the 75% sharing level. The 50% sharing level was triggered by a 10% return on year-end equity in the Idaho jurisdiction and the 75% sharing level kicked in at 10.5% return on year-end equity in the Idaho jurisdiction. The midpoint of our updated earnings guidance puts us into the threshold of the 75% sharing level. Through the end of the third quarter, we estimate we will share $6.2 million with customers under the Idaho sharing mechanism and we recorded that amount for the first three quarters of 2013.

I will now turn the presentation over to Steve to discuss the tax method changes, our liquidity position, and a recent filing with the Idaho Commission.

Thanks, Darrel, and good afternoon everyone. I will first discuss Idaho Power's current tax method change.

Idaho Power benefited in recent years from the impacts of tax method changes as well as increased flowthrough deductions annually relating to tax deductions for capitalized repair costs. In 2010, Idaho Power adopted a new income tax method of accounting for capitalized repairs that resulted in a $41.5 million tax method change benefit. In the third quarter of 2012, an additional benefit related to a repairs tax method change was recognized, resulting in a $7.8 million benefit. The 2012 change was a result of our alignment with an IRS Safe Harbor methodology established specifically for transmission and distribution assets.

On September 13, 2013, the US Treasury Department and IRS issued final regulations addressing the deduction of capitalization -- of expenditures related to tangible property for tax years on or after January 1, 2014. The revenue procedure was also issued this year that prescribed Safe Harbor unit of property definitions specifically for electric generation property.

Due to this most recent change in tax law and Safe Harbor guidance, Idaho Power assessed and estimated the impact of the method change relating to electric generation property. Based on that assessment, Idaho Power does intend to make this method change specifically for generation property and therefore recorded $4.6 million of tax expense in the third quarter of 2013. This amount relates to the cumulative method change adjustment for years 2012 and prior. Idaho Power does not expect the method change for generation assets to materially impact the ongoing capitalized repairs deduction included in its 2013 income tax provision, or in future periods.

With a tax benefit of $7.8 million recorded in the third quarter of 2012 and a tax expense of $4.6 million recorded in the third quarter of 2013, the combined impact resulted in a $12.4 million decrease in Idaho Power's quarterly net income on a comparative basis. Predicting these impacts on a quarterly basis has been challenging, but we are not currently aware of any anticipated additional guidance to be issued by the US Treasury or the IRS relating to this issue. A more lengthy discussion of these tax method changes is included in the Form 10-Q we filed this morning in Footnote 2, income taxes, and in MD&A.

Now, moving to Slide 8, we show IDACORP's year-to-date operating cash flows and liquidity position at September 30. Cash flow from operations for the first nine months of 2013 was $247.6 million, an increase of $66.1 million over the first nine months of 2012. The majority of the increase results from a $34 million improvement in income before income taxes. Additionally, smaller defined-benefit pension plan contributions in 2013 improved operating cash flows by $14 million. Also, a reduction of non-cash earnings associated with the collection of AFUDC increased cash flow by $8 million as capital projects moved from their construction phase into rate phase. The remaining increases resulted from a combination of changes in working capital and other items.

IDACORP and Idaho Power currently have in place credit facilities of $125 million and $300 million respectively. In October, we successfully extended the termination dates of both credit facilities from October of 2017 to October of 2018. After considering commercial paper balances and other obligations at September 30, IDACORP and Idaho Power had $72 million and $275.8 million respectively in available liquidity under the credit facilities.

Also, as of September 30, there were 3 million IDACORP common shares available for issuance under IDACORP's continuous equity program. No shares have been issued during 2013, and we do not expect to issue any shares during the remainder of the year.

The final topic I'd like to discuss is our regulatory filing with the Idaho Commission regarding base level net power supply costs. On November 1, 2013, Idaho Power filed an application with the Idaho Public Utilities Commission requesting approval of new normalized or base level power supply expense which, if approved, would reflect in base rates approximately $106 million of net power supply expenses and allow the Idaho jurisdictional portion of those expenses to be collected through base rates rather than through the power cost adjustment mechanism. This $106 million of ongoing and permanent costs are the result of a number of factors, including increased mandated energy purchases pursuant to the Public Utility Regulatory Policies Act of 1978, reduced surplus energy sales revenue due to lower energy market prices, and the elimination of previously anticipated revenues from the Hoku Materials Inc. special contract. While approval of the application would result in no net change in the amount collected through base rates and the PCA in aggregate, it would decrease the amount of any base rate increase requested in Idaho Power's next Idaho general rate case application. We view this as a positive step that more appropriately aligns cash flows from base rates with normal power supply expenses.

Now, I'll turn the discussion over to LaMont.

Thanks, Steve, and good afternoon everyone. I want to focus my portion of the call on growth from several perspectives.

As indicated on Slide 9, Idaho Power believes its service area has many characteristics that make it desirable for the expansion of existing businesses and residential customers. And in recent years, we have seen growth in our customer count and associated positive impacts on the company's revenue.

I'd like to highlight some accolades our state and company have recently received for business friendliness. On September 25, Forbes Magazine named Idaho as the ninth best state for future job growth. With this ranking, Idaho is in good company with states including Arizona, Texas and Colorado, boasting a projected annual job growth rate of 2.2%. The Forbes ranking looks at 35 factors to determine the best and worst states, including projected employment.

Additionally, Idaho ranked number 18 for the second year in a row on the Tax Foundation's 2014 State Business Tax Climate Index. A rating of 1 means that the state's tax climate is most favorable to business, and a rating of 50 means it is least favorable. So Idaho placed approximately in the top third for favorability.

And speaking of favorable environments, the city of Boise ranked number 11 in livability.com's list of 100 Best Places to Live. Further, according to an October 29, 2013 CNN Money article, Boise is listed as one of the 10 best places to retire.

I also want to share with you an exciting announcement recently made in Idaho Power's service area. California-based energy bar manufacturer Clif Bar signed a development deal on October 17 that paves the way for them to begin construction on a 300,000 square-foot bakery in Twin Falls in April 2015. Clif Bar announced that it anticipates the bakery will be operational by the end of 2016 and intends to invest a total of $160 million in the project. Clif Bar also announced that it expects 250 full-time jobs to be created initially and that if market conditions allow, that number could increase to 450.

Idaho Power also projects customer growth will continue in a more positive direction than previously reported in the company's 2013 IRP. The company recently prepared updated customer and load forecasts based on observations of positive economic activity in our service territory and more robust forecasts of near-term economic conditions. Based on these updates, the company projects a 2.1% five-year annual compound growth rate for residential customers and a 1.4% five-year annual compound growth rate for residential load. This is an increase from figures published in the company's 2013 IRP which for the same period forecast compound annual growth rates for residential customers and load of 1.8% and 1.1% respectively.

Future anticipated infrastructure projects, including those identified in the 2013 IRP, are intended to help ensure Idaho Power continues to provide reliable service to existing customers while meeting expected future customer growth. The 500,000 kV Boardman to Hemingway line shown on Slide 10 is important to this initiative and also supports expansion of the transmission system in an effort to enhance system reliability and access to wholesale markets. However, the environmental requirements for and application of environmental regulations to the siting process have changed significantly since the start of the project, making identification of a suitable route for the transmission line more challenging. This has resulted in project delays and increased permitting costs. In light of those delays and current and future siting impediments or potential impediments, Idaho Power now expects the in-service day for the line will be in 2020 or beyond. Given project delays, Idaho Power is conducting an enhanced review of other power supply resource options to cover potential resource gaps as it continues progress on the Boardman to Hemingway line.

On another resource front, this week, we began the hearings at the Idaho Public Utility Commission, or IPUC, regarding the request for a Certificate of Public Convenience and Necessity related to the selective catalytic reduction, or SCR equipment, to reduce nitrogen oxide emissions at the Jim Bridger coal plant. We estimate that the total cost for Idaho Power's share of the upgrades for Units 3 and 4 is approximately $130 million, including AFUDC. Our application requests the IPUC to provide Idaho Power with authorization and a binding commitment to provide rate-based treatment for Idaho Power's share of the capital investment with approximately $63 million authorized for recovery on or after January 1, 2016 and approximately $67 million authorized for cost recovery on or after January 1, 2017. We have requested the IPUC issue an order by the end of November 2013.

And finally, as shown on Slide 11, in September, IDACORP's Board of Directors approved a 13.2% increase in the regular quarterly cash dividend on IDACORP's common stock from $0.38 to $0.43 per share, or $1.02 per share on an annualized basis. Reflecting the company's commitment to growing the dividend, IDACORP's management also anticipates recommending to the Board additional annual increases to the dividend of greater than 5% until it reaches the upper end of the target annualized dividend payout ratio of between 50% and 60% of sustainable IDACORP earnings.

Now, I and others on the call are available to answer your questions.

(Operator Instructions). Paul Ridzon, KeyBanc.

Good afternoon. Do you have any latest thoughts on your aspirations for the regulatory plan post the Idaho settlement?

This is Darrel. Let me -- I'll address that, but before I do, let me just correct one thing that was said as it relates to the dividend. The $0.43 does equate to an annualized rate of $1.72, just to clarify that in case I might've got misunderstood on the call, so I just want to clarify that.

Back to your original question related to options, I believe what you're asking for is options beyond 2014. And we are looking at all different options related to 2015 and beyond, all the way from extension of our current agreement, looking at the possibility of filing another general rate case should that be the warranted path.

One of the things that we would plan to do is we will update you on that. We anticipate updating you on that in our February call.

As a reminder, we've had this deal in place with the Commission now going into our fifth year in essence. And over that five-year period, we have yet to utilize any of the credits that we had available to us.

So we believe the mechanism has done what we had hoped it would do, and we believe it's also in the same time benefited the customer from the standpoint of the sharing mechanism that is there as we continue to project sharing going into 2013. So, as you recall the last time we were able to get an agreement on extension of the deal, it was really pretty much close to the end of that particular year. So if we can give you guys some inkling or feedback on that in February, which we would hope to do, that obviously would be a fair amount ahead of where we have been. And we still have 14 months remaining on the existing agreement as we sit here today.

So we are looking at that. That's one of the challenges we know that are out there. A lot of people want to know what's going to happen when this goes away, and so we are aware of that. We will give you as much information as we have as that works forward.

The other thing that I think we want to mention along those lines is, as Steve mentioned, we just filed on Friday our net power supply cost filing, and we want to make sure that has an opportunity to run its course before we are to move on the next general rate sort of proceeding. So we do expect that the net power supply cost filing will work its way through through the first quarter of 2014, but we hope to be able to at least give you some inkling of the direction we are headed on our February call. I said a lot there, but hopefully that made some sense.

Thank you very much. Can you give some guidance of what you expect your effective tax rate to be in 2013 and 2014?

Yes, I would say last time we -- I went back and looked at a couple of our conversations in the past calls, and we were anticipating, at that point in time, maybe the low 20%'s. I would say right now that's probably moved up a little bit to mid 20%'s to pushing upper 20%'s at this point in time.

And then can you just run through some of the options, given the new delay in Boardman to Hemingway for supply.

You bet. We are actively in the middle of assessing that, obviously, in light of the comments LaMont made regarding our changing load forecast, so we are going to be looking at a number of different options anywhere from a new peaking resource, market purchases, demand response programs, energy efficiency programs. All of those will be on the table to evaluate what those needs are.

First and foremost, we want to make sure that our customers have a reliable energy source. And so that's where our focus is, and we're going to make sure that, as the demand grows, we're going to be in a position to meet those demands. So all of those are on the table, Paul. And as clarity comes, we will make sure that you guys all are apprised of what that direction is.

Thank you very much.

Brian Russo, Ladenburg Thalmann Co.

Good afternoon. Your year-to-date earnings per share was $3.01, so that implies a fourth-quarter 2013 earnings of approximately $0.49 to get to your midpoint over your full-year guidance. And 4Q 2012 EPS was $0.33. So just curious. What's driving the fourth-quarter 2013 earnings growth versus fourth-quarter 2012?

This is Darrel. I'll take a shot at it and then maybe Steve will kick in. But let me just kind of -- a little bit of reflection. If you take a look over the last five years and you take a look at where our annual earnings have been, on average, we've done about $0.30 a share on average in the fourth quarter. And some -- the $0.49 you referenced, if you look back 10 years, that would be a tie for the highest over those last 10 years.

And I guess what I would say is to go back to my comments in my prepared remarks is we believe that the core business is doing what we think it should be doing, combining with ongoing energy sales combined with what I would say is effective cost management. It's really kind of the combination of those two items that is allowing us, we believe, to provide you first of all the earnings range, and then also, as you did the math, to get to the midpoint that equates to somewhere around $0.49. That's what we are seeing. And I think it comes back to, as we are looking at it, the core business. There are no crazy tax adjustments or any of those kind of things incorporated into those numbers. There's all -- so it really is the business doing what we anticipating it to do.

Okay, great. And then just to follow up on the Boardman to Hemingway delay to at least 2020, I think initially it was for 2016 and it was delayed to 2018. And the strategy was to use short-term market purchases, energy efficiency, demand-side management to bridge the gap from 2016 to 2018. What would the timing -- if you chose to pursue a new resource or peaking plant, what would be kind of the timeline for when you would actually need that?

We just provided some updated growth numbers that LaMont referred to. We are incorporating those numbers as we go through the update to our midterm IRP process. So as we go through that process, we will take a look at that.

Our next formal IRP isn't until 2015, in which that is probably the IRP that I would expect that you would see something in there concrete. But as we go through the update process, as we go into 2014, if there's something that flushes out of there that it makes an obvious recommendation for us, we would communicate that. But I think all those things you just mentioned are those things that we will be looking at.

To the point of a project, though, one of the things you should look for in what we are planning to see is a draft EIS on B-to-H coming out in the first half of next year. And that will be -- once you have a chance to see that, that will help us also then determine the likelihood of the 2020 date. We say 2020 or beyond, so we are looking at 2020 right now. And that, depending if it goes beyond that, would maybe dictate a different resource.

And how many megawatts or capacity was B-to-H supposed to -- or was designed to wield into your service territory from the last -- to get a sense of how much capacity you guys actually really need?

Our number for summer was 500 megawatts.

Okay. Great. And then also you haven't used any ADITCs like you mentioned earlier. But you also benefited quite significantly from weather in 2013 and 2012. I was wondering. In 2013, is there any -- can you quantify weather versus normal? And then secondly, if weather was normal, are you confident you would not need the ADITCs?

That's a tough question because we don't necessarily break out the complete weather impact on -- try to differentiate the weather component against all the other factors that are going on out there because there is weather, but there's also elasticity. There's changing demographics, all kinds of things that go into that number. And we look at that all the time. So I can't give you a weather number, and I really can't take that and break it out to a number that says we would have needed ITCs or not.

As you recall, when we started out the year, we had projected a utilization of a modest amount of ADITCs. And so while we did have weather that was somewhat abnormal from the standpoint of the way the summer went because cooling days were significantly above normal, that was predicated on a more normal forecast on weather. And so I would say that there would've been a modest utilization of credits. That's how we started out the year. If you recall, that was less than $5 million.

This is Steve. It was less than $5 million. I do think that's an important point that, when we gave our guidance, we really are looking at a more normalized look at what we expect for the year. And sharing has its -- the mechanism has its kind of pluses and minuses. And the fact that we are in sharing here in the third quarter with a higher target, there will be more sharing in the fourth quarter. And to the extent those dollars are going over into sharing, that kind of moves some of the extra benefit that might have been there from a really hot year, really is shifting over into the sharing side. And it's not as much is showing up on the bottom line, so it kind of goes in reverse. If you were to pull the weather out and go back to normal, you would be pulling a good amount of that out of the sharing side as you move down towards what the earnings impact is.

Okay. My last question is procedurally what needs to happen with those various options you're exploring for 2015 rates? If you were in discussions with staff on any related item, I think you'd have to notify the Commission, correct, in advance?

Right. I'm going to let Greg Said speak to that a little bit, let someone else speak here a little bit, but let him comment a little bit on procedurally what could happen. I think what he will do this share a little bit about how it came out the last time, because it's probably not dissimilar. I'll pass it on to Greg.

Any of the options the Darrel discussed earlier would require a filing of some sort with the Commission. Obviously, a general rate case would involve a notice of intent to file followed by a filing, and then seven months of review of that application before rates could become effective.

In our last agreement to reach a settlement, that followed a general rate case application and really came in in the 11th hour of the determination of that general rate case. So we had filed in June of that year, and then reached settlement on that case followed by the settlement stipulation for the use of investment tax credits following the settlement of the case.

So, we would more than likely need a demonstration of what our future needs for revenue would be before we could reach agreement as to a mechanism to deal with the continuation of investment tax credits. So, in any event, there would be a filing of some sort before the Commission.

Okay, so if I'm understanding this correctly, even if you were to pursue some sort of settlement agreement, or extension of the current rates, it would likely be after a notice of intent to file a rate case because you'd have to kind of justify any revenue requirement or needs? Is that accurate?

I think that is accurate. Generally, there is a desire to see a demonstration of needs before you can enter into an agreement to how to deal with that need.

Okay, great. Thank you very much.

Sarah Akers, Wells Fargo.

Good afternoon. Is there a date as to when the midcycle IRP update will be completed?

That's a great question. I'm looking over at Lisa Grow, and we think it's midyear most likely.

Okay, midyear 2014?

Correct.

Got it. And then on a different topic, the 10-Q outlined the FERC revenue requirement I think effective October 1 of this year. That's about $10 million higher than the prior revenue level. So should we think about that as a $10 million base rate increase from an earning standpoint or is there something else going on there?

Can you repeat that question? Sorry.

Sure, no problem. So, in the 10-Q, it outlines the FERC revenue requirement effective October 1 that's about $10 million higher than the prior period. So, I'm wondering if we should think about that as a $10 million base rate increase from an earning standpoint.

Ken Petersen, our Corporate Controller, will kind of response to that one.

I believe, without looking directly, that what you're looking at is the full amount. If you look at the FERC jurisdiction, it represents about 5% of the total, so it's not that high. It is an increase, though, so it will have some impact, just not to the level that you're looking at I don't believe.

Okay, got it. Thank you.

This is Greg. I wanted to double back to your question about the IRP update. Typically, what happens for the update is the update has a requirement to be filed 12 months after a plan is acknowledged. So, it really depends on when the 2013 plan is acknowledged as setting the date for the requirement of the 2014 update.

Okay. And so has the 2013 plan not been acknowledged yet then?

That's correct.

Okay, got it. Thank you.

Ashar Khan, Visium.

Can you just give us an update? Are CapEx numbers for 2014/2015 still the same?

Right. What we've done now in the 10-Q now on the CapEx side of things is kind of laid it out by year. We gave you a number that kind of lays it out, so right now the number is -- we haven't really changed those numbers at this point. So in and around $275 million to $290 million next year, $300 million to $315 million in 2015. And those include costs associated with our SCRs that LaMont referred to -- include some expenditures associated with those.

So that's nearly like, what, a 4%, 4.5% increase in rate base for next year or something like that?

It would be --

You have to net out the depreciation that's running as well that's around $120 million, and --

What is your average rate base this year? Can I ask on which you did your 10.75% --

That's actually based on year-end equity.

Okay, sorry. But what is your rate base for this year?

We don't have an updated one at this point. We haven't had to go back and calculate that file.

Okay. Fair enough. So my other question is with a good -- I guess the other way to ask that question is what equity balance do you expect to end up the year at?

I think what you can do is take the quarter-end balance, the balance at 9-30, and take your estimated earnings less the dividend and you can probably get pretty much what that number is.

What that number is. Okay. Fair enough.

Just make sure you're jurisdiction -- depending on what it is you're looking to calculate, if you're looking to do the Idaho component only, make sure you jurisdictionalize it for that 95% or so that's associated with Idaho.

With Idaho, okay. Well, if I'm right, that cash flow -- am I right cash flow has been better than expectation for the year?

Yes. Cash flow is a little better this year than we had last year. And I do think it's been just in general the last few years with the settlement and with the very current rate structure, we've seen cash flows improve.

And so where is this excess cash being used? Can I ask is it being used to just buffer up or what are you doing with this excess cash?

For one thing, we are putting out a reasonable amount of CapEx. One of the reasons that we put the chart and kind of put some focus on it last quarter was to show that, if you look back, the period -- and look at the average expenditures during the period when we built Langley Gulch and look ahead at the capital we've got projected, we are really at about that same level. So even though we are not building a major baseload facility, we are spending a similar amount of money on other parts of the company, which is really just the basic care and feeding of Idaho Power.

Okay. My last question to follow-up to it is do we, based on good cash flow this year, do we need equity next year, or no, in any form?

We haven't actually stated the 2014 equity outlook. But if you look at the fact that we have improved our cash flow, we've been raising our dividends, and we've moved our ratios from really to where our equity was the low number. We were somewhere around 48%, probably sub-50s% equity, to where now we are north of 50%, probably approaching 52%. Those signal that we have strengthened our balance sheet and the cash flow has been good. And it's really been that improved cash flow I think that's helped us be in a much better place to raise our dividends and to even put a forward signal that there's further enhancement until we approach the upper end of our guidance range on dividend.

Okay. That's great. Thank you so much.

At this moment, we have no further questions. (Operator Instructions). That concludes the question-and-answer session for today. Mr. Anderson, I will turn the conference back to you.

Thank you, Jackie, and thanks for all for you participating in our call this afternoon and your continued interest in IDACORP. We hope to see many of you next week at the EEI Financial Conference in Florida. Thanks again.

Ladies and gentlemen, that concludes today's conference. Thank you for your participation. You may now disconnect and have a great day.