Idacorp Inc (IDA) 2016 Q4 法說會逐字稿

Welcome to IDACORP's fourth-quarter and year-end 2016 conference call. Today's call is being recorded and webcast live. A complete replay will be available from the end of the day for a period of 12 months on the Company's website at idacorpinc.com. (operator instructions)

At this time, I will turn the call over to Justin Forsberg, Director of Investor Relations. Please go ahead.

Thanks, Steven. Before the markets opened today, we issued and posted to the IDACORP website our fourth-quarter and year-end 2016 earnings release and our annual report on Form 10-K. The slides we'll be using to supplement today's call are also available on our website and will continue to be available for the next 12 months. We will refer to those slides as we present today's updates.

As noted on slide 2, our presentation today will include forward-looking statements, which represent our current judgment or opinion of what the future holds. These forward-looking statements are subject to risks and uncertainties that may cause actual results to differ materially from statements made today, some of which are listed on slide 2, and are supplemented by information in our filings with the Securities and Exchange Commission, which we encourage you to review. We caution you against placing an undue reliance on any forward-looking statements.

As shown on slide 3, on today's call we have Darrel Anderson, our President and Chief Executive Officer; and Steve Keen, our Senior Vice President, Chief Financial Officer, and Treasurer; along with other individuals available to help answer your questions during the question-and-answer period.

On slide 4, we present our quarterly and annual financial results. IDACORP's 2016 fourth-quarter earnings per diluted share were $0.66, an increase of $0.03 per share from last year's fourth quarter. For the year ended December 31, 2016, earnings per diluted share were $3.94, $0.07 more than for the same period in 2015. These results mark our ninth consecutive year of earnings growth.

I will now turn the presentation over to Steve, who will discuss the results in greater detail, and will review our 2017 earnings guidance and corresponding key operating metrics.

Thanks, Justin. We had a nice finish to the year and believe the outlook for IDACORP's utility business remains strong.

On slide 5, you'll see a reconciliation of the $3.6-million increase in net income from 2015 to 2016. Addressing the year-over-year changes, customer growth in our service area increased operating income by $11.2 million, or 4%. However, decreased usage per customer, largely related to moderate summer weather and irrigation impacts, more than offset customer growth and lowered operating income by $14.7 million.

As a reminder, our Idaho FCA mechanism moderates the impact of weather but is not applicable to irrigation, large commercial, or industrial customers.

Other changes to operating income were the result of several items. First, other operating and maintenance expenses increased $9.7 million compared to 2015, primarily related to higher variable labor-related costs that were mentioned last quarter, as well as scheduled hot gas path maintenance at the Langley Gulch Power Plant.

It's also worth noting that in spite of the increase over last year, we finished 2016 with just under $352 million of O&M expense, putting us close to $350 million for the fifth year in a row. We are pleased with the results of our efforts to control spending over the past several years. It benefits both our owners and our customers, and it is a continued focus in 2017.

The next item impacting operating income is the $5.6-million increase in depreciation expense, related to growing plant investments. Also during 2015, Idaho Power recorded a $3.2-million provision for sharing with Idaho customers, which lowered prior-year revenue under the Idaho regulatory settlement stipulation. No such sharing provision was recorded in 2016.

While Idaho Power's 2015 return on year-end equity in the Idaho jurisdiction was greater than 10%, the Company's Idaho return in 2016 was only slightly above the 9.5% tax credit support level, or just inside the dead band. Idaho Power's actual combined return on equity for all jurisdictions was 9.47%.

Overall, Idaho Power's 2016 operating income decreased $17.1 million year over year, again showing the impacts of relatively moderate summer lows.

Moving to the tax line, income tax expense decreased by $11 million from a combination of the accounting treatment for stock compensation, variations in existing flow-through income tax adjustments at Idaho Power and lower pretax earnings.

Also, IDACORP Energy Services recorded $3.7 million of increased net earnings during the fourth quarter of 2016, a result of a settlement relating to the California energy market proceedings, discussed in note 10 on our Form 10-K filed earlier today.

IDACORP also benefitted in 2016 from distributions received from fully amortized affordable-housing investments at IDACORP Financial Services, as discussed last quarter.

Moving now to slide 6, we show IDACORP's operating cash flows along with our liquidity positions at the end of the year. Cash flow from operations for 2016 was $347.7 million, a decrease of $5.5 million from the same period in 2015. Changes in regulatory assets and liabilities accounted for the decrease, while the timing of distributions from Bridger Coal Company provided some offsetting positive cash flow increase.

IDACORP and Idaho Power currently have in place credit facilities of $100 million and $300 million, respectively, to meet short-term liquidity and operating requirements. The liquidity available under the credit facility is shown on the bottom of slide 6.

Although we do not plan to issue equity during 2017, outside of normal issuances under compensation plans, we continue to evaluate the potential renewal of our continuous equity program, which expired last year.

Slide 7 shows the updated financial and operating metrics for the full year of 2017. We are initiating earnings guidance in the range of $3.90 to $4.05 per diluted share. Should we obtain the midpoint or higher of this earnings guidance range, IDACORP would achieve its tenth consecutive year of earnings growth.

The earnings guidance range assumes normal weather conditions and includes an estimate that Idaho Power will utilize less than $10 million of additional accumulated deferred investment tax credit amortization to achieve a 9.5% return on a year-end equity in the Idaho jurisdiction.

As a reminder, the current Idaho stipulation allows for the use of up to $25 million of additional credit in any given year, and the full $45 million of credit is currently available for earnings support through 2019. Our efforts remain targeted on managing costs and growing revenues with the goal to continue to preserve credits for future years.

The other three metrics listed on this slide are all in line with recent performance. First, we expect 2017 O&M expense to be in the range of $345 million to $355 million, which would again put O&M costs relatively flat each year since 2012.

Next, we expect capital expenditures to be relatively consistent with 2016, in the range of $290 million to $300 million. Finally, we are optimistic about this winter's above-normal snowpack and precipitation levels in the Snake River, Boise, and Payette river systems. We anticipate reservoir storage to reach adequate levels, and we are currently expecting hydroelectric generation to be close to normal, as well, in the range of 7 to 9 million megawatt hours.

In closing, we are also keeping an eye on the potential impacts federal tax reform could bring to our industry and utility customers, including the current limited proposals put forth by the House and the President.

However, it's too early in the legislative process to draw definitive conclusions as to what direction tax reform will ultimately take. While many current proposals have positive attributes -- a lower corporate tax rate, for one -- there are other possible headwinds, such as the loss of interest deductibility. Given the uncertainties, I will focus on two specific tax-related items for IDACORP and Idaho Power.

First, the holding company has minimal debt, and thus currently has no material exposure to changes in interest deductibility. Second, due to Idaho Power's regulatory flow-through income tax accounting, it's plant-related deferred tax liability balance is lower than it would be under full normalization accounting. Therefore, a reduction in the federal corporate income tax rate will create less excess deferred income taxes than if a full normalization accounting had been employed.

An additional note is that of our existing deferred tax balances, the majority are protected by the normalization requirements of the current tax code. In previous modification to tax law, a prescribed methodology for handling such balances was typically included in the final tax package.

There are many complications involved in reforming the Internal Revenue Code. If tax-reform efforts become more certain, we will provide additional clarity on potential impacts to our results.

I'll now turn the presentation over to Darrel.

Thanks, Steve, and it's great to speak with you guys this afternoon. Today I want to begin by discussing a recent addition to our Boards of Directors, as well as upcoming changes to our management team.

First, as shown on slide 8, two weeks ago Annette Elg was appointed to serve on the Boards of Directors of both IDACORP and Idaho Power Company. Besides being an Idaho native, Annette joins our Boards with a wealth of business experience and a deep understanding of our service area, having recently retired as Senior Vice President and Chief Financial Officer for the J.R. Simplot Company, one of the largest agribusiness companies in the country. Annette will be up for election along with all our other Board members at the annual meeting of shareholders this spring.

As shown on slide 9, three officer title changes were approved this month to better reflect the scope and level of responsibilities in their areas. Lisa Grow will take on the role of Senior Vice President and Chief Operating Officer; and Brian Buckham will become Senior Vice President and General Counsel.

In addition, Vern Porter will be named Vice President of Transmission and Distribution Engineering and Construction and Chief Safety Officer. This change takes advantage of Vern's nearly 30 years of experience in all areas of operations and provides added emphasis on Idaho Power's continued pursuit of a strong safety culture.

I'm also pleased to announce the promotion of Adam Richins to Vice President of Customer Operations and Business Development. Adam has been with Idaho Power since 2011, most recently serving as General Manager of Customer Operations, Engineering and Construction. Adam's mix of business, engineering, and legal experience will serve him well in this new role, especially as we put added emphasis on our business-development activities.

These management changes will be effective March 1 and are part of our ongoing long-term succession-planning efforts. I am confident that these leadership additions and changes will help position IDACORP and Idaho Power well for the future.

Next, I'll provide an economic and business update for our service area.

Slide 10 includes an update on customer growth. In December, the US Census Bureau identified Idaho as the state with the third-highest population growth rate, with a population increase of more than 1.8% from 2015 to 2016.

For 2016, Idaho Power's customer growth rate mirrored the population growth rate, at 1.8%. As of December, preliminary labor statistics show unemployment in our service area was 3.6%, compared with 4.7% at the national level.

During 2016, employment in our service area increased approximately 3.5%, now exceeding 480,000 people employed. That is robust economic data by most standards.

We believe that growth is attributable in part to the fact that more people and companies are learning that Idaho Power's service area is a great place to live and do business. Another empirical example comes from moving companies United Van Lines and U-Haul, who both reported Idaho as a top destination for relocation. The movers ranked our state number four and number seven, respectively, for inbound moves. The U-Haul ranking is up 14 spots from last year.

In addition, Vogue magazine recently included Idaho as the only location in the United States on its list of the ten hottest travel destinations in the world for 2017. We welcome all of you to come and visit our great state.

As a final note on the service-area economy, as of December 2016, Moody's Analytics forecast growth in gross area product in our service area of 4.4% and 4.6% for 2017 and 2018, respectively. These updated gross area product figures reflect a decrease for 2017 and an increase for 2018, relative to the September 2016 estimates of 4.9% and 4.1% for the respective periods.

We continue to be bullish on growth in our service area, and growth continues to provide a lift to lows while offsetting what we are seeing in declining use per customer.

Moving on to slide 11, Idaho Power's regulatory strategy considers short-term and long-term needs and considers several factors that can affect the timing of rate filings.

During 2017, we will continue to assess the need to file general rate cases in Idaho and Oregon. As Steve mentioned earlier, a focus for 2017 will be on continuing to optimize our core business through the active management of expenses. At the same time, we will continue our business-development efforts to grow revenue. As we focus on these areas in 2017, we are seeking to balance the dual goals of earnings a fair return for shareholders, while keeping customer rates competitive.

I want to highlight a few specific areas of regulatory emphasis for us in 2017.

As you know, Idaho Power has been working for many years to renew its long-term federal license for the Hells Canyon complex, our largest hydroelectric generation source. Idaho and Oregon are currently at an impasse in their respective Clean Water Act Section 401 certifications, with regard to fish passage and reintroduction conditions, which makes the timing of final resolution and relicensing uncertain at this point, though we are steadfastly continuing our efforts to obtain a reasonable resolution.

At the end of 2016, Idaho Power filed with the Idaho Public Utilities Commission, or IPUC, for a prudency review of costs spent through December 2015 in the relicensing effort.

Idaho Power is not currently seeking a change in rates with this request. As of today, the IPUC already authorizes Idaho Power to include in its Idaho jurisdictional rates approximately $10.7 million annually of AFUDC, relating to the Hells Canyon relicensing project. Collecting these amounts now reduces the amount we will need to collect in the future once relicensing costs are approved for recovery in base rates.

In regards to other generation resources, we continue to evaluate the most economic operating life of the North Valmy coal-fired power plant and technically feasible closure dates. In fall 2016, we filed applications with both the Idaho and Oregon Commissions requesting accelerated depreciation of the facility that would allow the plant to be fully depreciated by the end of 2025. The North Valmy cases, along with the overall system-depreciation cases filed last fall, continue to move through the regulatory process.

On January 31, the IPUC approved our request for the deferral of costs related to Idaho Power's planned involvement in the western Energy Imbalance Market. We believe this approval to defer Idaho Power's costs is the right step towards matching costs of participation with the anticipated power supply related benefits customers will receive. We are still on track for a 2018 go-live date.

Also in regards to resource planning, Idaho Power is in the midst of preparing its 2017 integrated resource plan, our IRP. Monthly meetings of our IRP advisory committee will continue through this coming spring; and we expect to file the document at the end of June.

As part of the IRP, we will be evaluating additional selective catalytic reduction equipment, or SCRs, at the Jim Bridger coal-fired plant. As you know, Idaho Power and the plant's co-owners have installed SCR commitment on units 3 and 4 to reduce nitrogen oxide emissions at the plant, in order to comply with regional (inaudible) rules.

In light of the uncertainty surrounding environment regulation, the economics of running the plant, and the substantial estimated costs of the SCR installation, Idaho Power is assessing with its co-owner whether to move forward with the installation of SCR equipment on units 1 and 2 at the Jim Bridger plant.

On the 500-kV transmission project front, the Bureau of Land Management, or BLM, released its Record of Decision for the remaining two gateway west transmission line segments 8 and 9 last month. It had released its final supplemental Environmental Impact Statement, or EIS, for these portions last October.

Additionally, the BLM issued a final EIS for the Boardman-Hemingway line in November. We expect a Record of Decision for this transmission line in 2017.

I believe it's important to mention the successful resolution of a longstanding legal proceeding which had a favorable impact on our 2016 results. We reached, and the Federal Energy Regulatory Commission has approved, a settlement relating to the California energy market proceedings, which have been ongoing for well over a decade. The settlement resulted in the IDACORP Energy Services earnings Steve discussed earlier. This outcome has been a long time coming, and we are pleased to see the end of our participation in the case.

Finally, turning to weather conditions. Slide 12 shows the projected March-to-May weather outlook from the National Oceanic Atmospheric Administration.

Current projections suggest that there's a 33% to 40% chance of above-normal precipitation in Idaho Power's service area and an equal chance of normal temperatures. The one thing I can say for certain about the weather is that the water year has been off to an excellent start, with current snowpack above Brownlee Reservoir in excess of 130% of normal. While there is still time left in our snow-accumulation period, we are optimistic about an improved water year.

And now Steve and I, as well as others on the call, will be happy to answer your questions.

Thank you. (Operator instructions) Chris Ellinghaus, Williams Capital.

Hey guys, good afternoon. Steve, your guidance -- in talking about ADITC recognition potential for the year is bigger than last year, does that indicate to us that you're expecting some headwinds, and can you give us any color on what you see for headwinds this year?

You know, Chris, I would put it in the -- it's more that the mechanism, itself, forces you to higher earnings. Because as we've talked in other settings, it's somewhat math how you determine where that 9.5% support line moves to, and it will move higher next year.

And if you look back just two years ago, we had a pretty significant amount of [sharing]. Last year, we had a very small amount of sharing. This year, you find us with no sharing and close to the demarcation of where we could have used credit.

As that income pushes higher, you have to find a way to do it, and we're not doing it through rate changes right now. We have done a lot of cost control. We've had some improvements in customers that are coming to the state and in usage. But it's really the fact that the income moved higher, and we're solving it with really the same rate structure that we have, that says we may use a few more credits than we did last year.

I don't think -- if you go back and look at the progression over about the last three or four years, it's pretty obvious that we would move to a little higher number. I know one of the analysts actually had higher projections for credits in 2017 before the call. So it is -- I think it's more of a natural progression, and we know that that's what's coming.

Chris, this is Darrel. I would just add a couple things to that, and things to think about. Things that will move that less-than-$10-million number are going to be if our expenses are more or less than what we are planning, if growth is more or less than what we have currently forecasted for 2017 -- all those things will go into the whole notion of whether that credit number either goes down or goes up.

And so I think based on what we see as the plan -- that's why we kind of came out with the less-than-$10-million number, but growth can take care of that number, optimizing our business can impact that number. And we are focused on trying to get that number to zero. But as we stand today, we're coming out with a less than 10. But just like we did last year, when we said less than 5, our goal is to use none to preserve credits going into the future.

Chris, one other item to consider is, while it doesn't show up in the reconciliation because to some extent it was in 2016 and 2015, is we have the ability to do a bond refinancing each of those years that helped us -- roughly $5 million that -- those opportunities are gone. So we have to solve it with different tools this year.

Right. Okay, the guidance is for normal weather, but you've had a pretty good start to the year. Is that included in your guidance at this point?

No, we don't roll that in, Chris. And we do have -- I think it is important -- I mentioned it in my script, but -- our mechanisms -- the decoupling provisions that we have, particularly in Idaho, help a lot with weather.

We believe there's still some benefit shows up in years that we have beneficial weather, and there's some that goes away. Particularly in the summer when the irrigation is high or low, that has an impact on us.

But I think your observation is correct. It was pretty cold here as we entered 2017. And certainly the snow looks better than we've seen for quite a while. So those are all positives, but we don't put those in guidance yet.

Okay. And do you have any thoughts on the outlook for irrigation in 2017 at this point?

Well, the good news is there should be water. We've had some on-and-off years -- one of the struggles that you worry about going into summer is, is there enough water that even if the conditions are right, that they have enough to irrigate the whole season.

That shouldn't be an issue this year. But to try to predict it now is hard because we could get water late into the spring, and that could dampen what irrigators do. You could also have a more normal summer and a really -- as far as water, and a really hot summer that takes it sky high. So the good news this year is, we don't have -- it doesn't look like there's any limitation in regard to how much water would be available.

Chris, one other thing. The ag community now is in the process of deciding what it is they're going to be planting. And so those I mean they sort of wait on how much water they're going to have. So if they're going to have water later, that means the more water-intensive crops they're more likely to plant. And so we are just in the process of gathering that information ourselves, and trying to ascertain what they've decided to plant with our ag reps that are out in the community.

So we'll be gathering that information, too. We don't have a really good sense today, but as Steve said, the likelihood of water being available longer is on the positive side today.

That was kind of what I was getting at. I was curious (multiple speakers) sort of a self-fulfilling prophesy.

Yes. And you also have to look at what's going on with market prices for crops and things like that because they also look at that.

And one thing I will tell you, this winter did have an impact on our onion-growing community. Because actually a lot of onions were lost because some of the storage sheds that were crushed by snow. And so there's been a significant impact on the available onions. So that may have an impact, too, which is not necessarily a bad thing because that's a water-intensive crop, itself. So that may have a bearing, too. But that has big damages in the storage side this winter.

Okay, great. Thanks for the details, guys.

Paul Ridzon, KeyBanc Capital Markets.

Good afternoon. Darrel, is it too late to buy onion futures?

(laughter) I am not venturing into the ag business today.

I actually was distracted, and I missed your commentary about potential rate-case timing. Could you just review that?

Sure. So what I actually [didn't say] -- I said we were evaluating in 2017 where we're going to go, but just to add maybe a little bit of color.

It's unlikely that we would be planning a general rate case in 2017. The more likely scenario is -- and a lot of this is going to be dependent on how growth continues to go for us -- but the more likely scenario is we would likely file an [2018 for a 2019] sort of deal. But that's still, again, a work in progress. We will finalize those plans as we go throughout the year. But right now, we're not anticipating a 2017 general rate case.

Great. And usage -- it seems like the loss to lower usage per customer seems to be getting higher. What's the dynamic there?

Well, this last year the -- I do blame a little bit of it on weather. As Chris was asking about the water situation, last year remember, we weren't sure that there would be enough water. It had not been an awesome winter, and going into the summer we weren't sure how much there was going to be.

What happened is, we got a lot of rain late -- it went all through the spring, and that impacted irrigators use. They got basically free water, so they didn't have to pump anything to take care of it. That had an impact on us.

And it was still an okay irrigation year, but relative to 2015, it looked not so great. 2015 was a really strong year. It was a very, very hot summer, and it was good for us.

So I'd say it's difficult to separate those impacts from the other things that go on. There's no question there's a continued impact every year from the code changes and conservation. But weather creeps into that as well and impacts what we put together and call use per customer.

And Paul, this is -- if you look at last year in particular, or 2015 against 2016, in particular in the residential side when you're looking at cooling degree days, we were down I think 22% from 2015 numbers on cooling degree days.

So as Steve mentioned in his notes, the weather was a factor, especially in the residential sector. And the other part of that is, because of our tiered rates, if you have that reduction in use per customer in weather-related and people that move into those up tiers, that has an impact.

So I think -- as we look at 2016 overall, a somewhat moderate weather year, which did drive that down. But I would also say on the bigger, macro level, on use per customer we're no different than other utility companies where people are putting in more efficient appliances, whether it's your air conditioning, whether it's your TV, whatever it is, they are more efficient today, and they are using less.

So our challenge is to continue to grow customers, which is why we're re-emphasizing the business development side of things, recognizing that that's going to be a natural attrition on use per customer because of what's happening with appliances and what have you. So you take that combined with the moderate weather, which is what had an impact on 2016.

What are the implications if you don't put SCRs on Bridger? Do you need gas?

Well, I think the question would be, what would we be able to negotiate with respect to the extension of a life on that plant beyond the current period. And that's what we would want to look to do if we were to somehow negotiate no SCRs but then get a little longer extension on the life.

I'll have Lisa Grow -- she's here with us today -- we'll ask Lisa to go ahead and comment on it (technical difficulty). Lisa?

Good afternoon. This is -- what we're looking at as a possibility for the Jim Bridger power plant is something similar to what we did with [Fordman] power plant. As you may recall, that plant -- we're a 10% owner, and we negotiated a date certain for shutdown so that we didn't have to put the pollution controls on. So we are looking at a possibility of doing something similar as one of the scenarios that we're evaluating currently with the Jim Bridger power plant.

Okay. And then if you can't [accelerate] the Valmy, what would be the financial impact of that be, from an earnings standpoint?

In the filing that is out there right now -- Ken's here, he might help me out -- but it's really pretty modest in terms of what it adds additionally earnings-wise. There is a modest amount of help.

I think partly what's driving our filing there is that -- as they did the depreciation study, and those are done every five years, we saw that we were not in alignment with where the plant was going to be depreciated by the partner. And it was initiated by the fact that the study really said maybe we should align. We're now taking a look with the help of those parties in Idaho that will be working on the case to decide what really is the best timing and really the lowest cost to customers. And that's really what we're looking at.

Now, as you determine the approach to that, there's decisions on what time period you spread it over, as well. And all of those things are going to factor into what it ultimately brings to us. Do you have any other color on the earnings side?

I think that's correct, Steve.

And what have you baked into guidance, as far as the decision there?

Basically, we don't have any earnings lift in the guidance for that (multiple speakers). We just assumed flat. And depreciation cases often end up like that, in that you may hope you gain a little bit, but really in the end what we're hoping is that we don't get harmed by a change in depreciation, and we'll see how they play out. What we don't want is to have to run more depreciation through it and not have a way to cover that cost.

Thank you very much.

Brian Russo, Ladenburg Thalmann.

Hi, good afternoon. Correct me if I'm wrong, but over the past several years under the current rate structure of [year end] shareholder equity of 9.5%, it seems like your earnings year over year from your initial guidance would increase roughly $0.10 to $0.15 each year. But this year it looks like the midpoint of your 2017 guidance is $3.97. And when you compare that to the $3.89 initial guidance for 2016, that only implies $0.08 of growth. I'm just wondering if that's accurate and if you can comment on it.

It's fairly accurate. I think we had the midpoint at $3.87-5. The way I kind of get there, Brian, is if you take this year's earnings at the $3.94 and you look at what was outside of Idaho Power -- because the things inside of Idaho Power are really -- for the large part just offset what we might have otherwise used credit for this year.

But outside, we did have the legal settlement, and we also had some benefits that came out of some gains, some distributions that came through IDACORP Financials that really were not typical things and not things we have planned going forward.

The sum of those two is around $5 million, so roughly $0.10. And if you were to take that off of our final earnings, you would be down to a number that I would say is a little bit more of an ongoing-type look. And that number is a little bit below even what where we guided.

And you have to look to that to say -- when we set those guidance numbers, number one, it's a range, $0.15. We weren't necessarily at the midpoint when we started the range. And number two, that is based on a computation that's really got a lot of rate-making embedded in it. It looks at our jurisdictional separation between Idaho and Oregon. And that is determined by how revenues flow in a given year.

And as you look at 2016, there was... anomalies. There was different weather, to some extent in Oregon and Idaho, impacts of irrigation, and other things. And it moves around a little bit. So while it generally is close, it's probably within a penny or two, it's not perfect. So it isn't a number that you can look ahead and say with absolute certainty where you're going to land.

Those are the things contributing to us not being exactly right. I think if you take this year and kind of work it back to what you would say is a more sustainable-type number and then do the same calculus we've always done added to that $3.84, I think you'll be pretty close to where our -- it will sit right in the middle of our range and be reasonable.

Brian, I come back to the comment I made earlier on the weather side. I think you can't lose sight of where the weather was for 2016, even though we do have some mechanisms that moderate that. But at the same time, that still had some impact on kind of where we ended up, and it was more moderate on average, so.

Got it. And what's the 2017 effective tax rate?

Well, Gene tells me that we're going to be back around the 20% range, or at least approaching it. Gene, can you help on that?

Okay. And you mentioned the possibility or the evaluation of filing a rate case in 2018. Is there a scenario in which you can reach a settlement like you've done in prior years to just extend the current rate structure?

Brian, I think as we sit here today, everything is on the table. We would look at all different options that we have out there today. And if we had credits that were available to us going forward, that would definitely be something we would love to consider as part of that because the mechanism has served the Company well. It has served the customer well. So we would assume that would be on the table, again depending on if -- it would be great if we had $45 million of credit going into whatever year we were going into the next rate proceeding. That would be great. But it just kind of depends on where we're at at that time. But that is one of the things that would be on the table, for sure.

And then lastly, the hydro investments that you seek prudency for -- if I recall correctly, it was quite a large number.

$220 million.

$220 million?

Right.

And how would that be recovered -- spread over --?

Well, eventually we would be asking for recovery of that through either a one-off or a general rate proceeding.

Okay, got it. Thank you.

Ashar Khan, Visium Fund (sic) Management.

Hi, good afternoon. Nice to hear from you guys. My question was answered from the previous question.

Okay.

Well, it's good to hear from you.

Thanks, Ashar.

Thanks.

Paul Patterson, Glenrock Associates.

Good afternoon. Just on the rate case that you're contemplating in 2018 -- would that be a 2017 test year?

Again, that's something that's still a work in progress. We would kind of take a look at a number of different options that might be in place, whether it's 2017 with known immeasurables or a forecasted test year -- those are all things that we would continue to look at.

Okay. How should we (multiple speakers) --?

Paul, I was just going to point out -- you know, we talk a lot about this in the sense of -- really our major jurisdiction, but we do have -- we have two, and it's possible that they would be filed at different times. At least it's not impossible. And it's possible that they may have different methodologies when it comes to something like this because Oregon typically [likes to forecast test year]. And that plays into it, too. So it's hard to just give a definitive single answer.

Sure. Just -- when we think about, on a regulated basis, what your regulated ROE -- earned ROE is in your jurisdictions, or just in general, I guess -- I know you -- you're not filing the rate case just yet, but just in general, how should we think about where you're earning currently, on a regulated basis?

Well, what our actual earnings were this last year was at -- just under 9.5% for Idaho Power, looking at both jurisdictions. For Idaho, you'd have to say we got at least to 9.5% because we didn't use any tax credits, so it was probably a little stronger than the whatever else was there.

But certainly neither -- we've had some better years when we were up around 10%. We certainly weren't there this year. Our allowed rate -- I don't recall what the Oregon exact number is --

Nine --

Nine-nine in Oregon, and the [unstated] in Idaho was kind of roughly 10. You have to solve back to it, but that's what was used in -- so I would say that for us to achieve numbers that are near those -- if you look back over our long history, being within 50 basis points of that isn't bad. And that's what we have to assess is the items that we would be taking into a case versus what you think you would get in terms of settlement.

Fair enough. And then just in terms of tax reform -- is the assumption that basically if they were to lower the tax rate to 15% or 20% that all these tax benefits or most of these tax benefits would go away that you currently are -- and the rate payers are -- whatever, that you currently have right now, would we think that that rather lengthy list of tax stuff would pretty much go away, or how should we think about that?

You know, that is -- the devil's in the details, and that's what is impossible to determine today. And it all would depend on how they've structured the various items that have been thrown on the table.

You could end up with a lower tax rate and have every single one of those still be there. It depends on the approach that they take. And I would say if they take an approach as they have in the past where any accelerated deductions are more like additional depreciation and it's just an accelerated timing, that doesn't affect those deductions at all.

If it's some entirely new approach, you could see a change. And I guess for us, the final answer is, whatever tax you pay is really what goes into the regulatory model. So it would depend on whether we're ultimately paying less or more than we are today whether it changes things very much.

Okay. And then just -- the slide on succession planning, could you elaborate a little bit more in terms of what we should be thinking about in terms of potential leadership? I wasn't clear what that title really indicates. I mean, obviously you've got some professional development, what have you. I gather that. But I didn't -- is there any moves that we should be thinking about in terms of in the future that the succession plan is about, if you follow what I'm saying?

This is Darrel. We have an active succession-planning process. And so we continue to look at the future. And so over the last couple years, we've had a fair number of retirements at the senior level. And so what we've really been doing right now is continuing to look at that.

We don't have any pending retirements coming up, but you never can project those. But we just have people -- we've kind of moved some people into different spots as we look to the future, the next three, four years down the road sort of thing.

So that's kind of why we made some of the changes. And a couple of those changes were really to reflect what people were already doing. Probably the biggest change was when we promoted Adam Richins to his new role and then had Vern Porter kind of change some of his responsibilities. Those were probably the biggest changes when you look at that. And it's really related to continuing to plan for the future and making sure we continue to have seamless transitions.

We've had seven officers retire in the last three-plus years, and so we think we've done it fairly seamlessly. And so we just continue to work hard at that side of things. So there's nothing other than just the sort of normal course of business things. And there's nothing imminent that's coming up on any other changes that we're looking at today.

Thanks for the clarification.

Actually, I'm looking for some stability for a while, actually. It's kind of a nice thing, you know, with no necessarily pending retirements coming up. We had a couple last year, but right now we don't have any -- with what I know today, nothing pending.

Great. Thanks for the clarification.

Thank you.

Bill Apicelli, [Nexus].

Hi, guys. I just wanted to follow up on Paul's question. Steve, the numbers you quoted, were those the return on the allowed equity and rate base, or were those returns sort of on a GAAP basis?

I'm trying to remember which ones I gave you. The actual return for the year was based on looking at our GAAP -- at our year-end earnings. If you just take Idaho Power, we earned, like 9.47%. But we do have -- in the Idaho jurisdiction, the regulatory stipulation that we're working under supports Idaho jurisdictional earnings up to a 9.5%. And it looks to year-end equity. It's not a pure regulatory computation, so it does look at whatever your year-end GAAP equity is.

Okay. So if you -- when you go in for a rate case, they'll be looking at that equity balance and not sort of the equity allowed on a capital structure based on the rate base?

It's a great question because what will happen is the rates will get set traditionally. They will be looking at rate base. They'll be looking at your costs that you're flowing through, the capital you've got invested. And they will come up with a very typical regulated return that you will develop a rate from.

Then if that decision happens prior to the end of 2019, whatever time there is between then and the end of 2019 reverts back to this settlement mechanism. And it would look to year-end equity and apply whatever the adjusted return might be to that year-end equity number.

Now post-2019, that would all be up in the air. You would either revert back to what we've always had historically or would be looking at whether there's any way to negotiate an extension if there's credits left.

Okay, great. All right, thanks very much.

And a final opportunity (operator instructions). And that concludes the question-and-answer session for today. Mr. Anderson, I will turn the conference back to you.

Well, I want to thank you all for participating on our call this afternoon and for your continued interest in IDACORP and Idaho Power. And we hope you all have a great rest of your day. Thanks for participating.

That concludes today's conference. Thank you for your participation. You may now disconnect your line.