Justin Forsberg - Director, IR Darrel Anderson - President and CEO Steve Keen - SVP, CFO and Treasurer Vern Porter - VP, Transmission and Distribution

Julien Dumoulin-Smith - Bank of America Merrill Lynch Paul Ridzon - KeyBanc Chris Ellinghaus - Williams Capital

Thanks, Rocco. Before the markets opened today, we issued and posted to IDACORP’s website, both our second quarter 2018 earnings release and our Form 10-Q.

The slides we’ll be using to supplement today’s call are also available on our website. We’ll refer to those slides by number during the call.

As noted on slide two, our presentation today will include forward-looking statements which represent our current views on what the future holds. These forward-looking statements are subject to risks and uncertainties, some of which are listed on slide two and in our filings with the Securities and Exchange Commission which you should review that may cause actual results to differ materially from statements made today.

We caution against placing undue reliance on any forward-looking statements. As shown on slide three, on today’s call, we have Darrel Anderson, IDACORP’s President and Chief Executive Officer; and Steve Keen, Senior Vice President, Chief Financial Officer and Treasurer.

We also have other individuals available to help answer any questions you may have during the Q&A period. On slide four, we present our quarterly financial results.

IDACORP’s 2018 second quarter earnings per diluted share were $1.23, an increase of $0.23 per share over last year’s second quarter. For the first six months of 2018, earnings per diluted share were $1.95, $0.30 higher than the same period in 2017.

We have increased and tightened our full-year 2018 earnings guidance estimates to a range of $4.20 and $4.30 per diluted share. I will now turn the presentation over to Steve.

Thanks, Justin. Good afternoon, everyone.

Strong customer growth and constructive and balanced resolution of a number of regulatory proceedings added to an otherwise solid operational foundation this quarter. With successful activities in both the prior and current year’s second quarters, the moving parts are plentiful.

And I will run through them today. Slide five includes a reconciliation of income from the second quarter of 2017 to the same period of 2018.

Strong customer growth of 2.2% helped drive an operating income increase this quarter, adding $1.8 million. Usage per customer was also higher, increasing operating income by $4.7 million, due mostly to more normal precipitation, which led to a 15% increase in sales to irrigation customers over last year’s second quarter.

Partly offsetting the higher irrigation sales was a 4% decrease in usage per residential customer as cooling and heating degree days were lower in the second quarter this year. However, the lower weather-related residential usage per customer was partially mitigated by an increase of $2.3 million in fixed cost adjustment revenues.

Of note, the volume of sales to commercial and industrial customers, which are less sensitive to weather impacts, were 2% and nearly 1% higher than the same period in 2017, respectively. Lower customer rates related primarily to quarter-over-quarter differences due to last year’s North Valmy plant settlement as well as the tax reform settlements that were implemented June 1 of this quarter, led to the $6.8 million decrease in retail revenues per megawatt hour that is next on the reconciliation table.

Recall that the impacts of the first quarter and second quarter 2017 benefits related to the North Valmy plant settlement were all recorded in the second quarter last year. They also contributed to the $3.9 million comparative decrease in depreciation expense, further down the table, though the impact was partially offset by higher depreciation expense from an increase in electric plant in service as we continue our trend of capital improvements.

This year, the Public Utility Commission of Oregon also approved $2.5 million of additional annual collection, related to accelerated depreciation for North Valmy. In addition to these changes in retail revenues, Idaho Power’s operating income benefited from a $1.3 million increase in transmission wheeling due to an increase in the transmission wheeling rate that went into effect last October.

Transmission rate is now more closely aligned with the cost of providing transmission service. Finally, other operating and maintenance expense was $5.6 million higher than the second quarter of last year, due mostly to a $3.1 million increase that was primarily related to the timing of accruals for variable employee-related expenses, a $0.9 million increase in transmission and distribution asset maintenance service costs, and the recent tax reform settlement stipulation that provided for amortization of $1.1 million of non-cash expense of regulatory deferrals that were a liability of Idaho customers.

Despite these differences, for the quarter, we are maintaining our forecasted range of operating and maintenance expenses for the full-year 2018. Even with all the moving parts and the grossed up revenue reductions from tax reform, Idaho Power achieved an almost $1 million positive change in operating income.

Further down the table, the $1 million increase in earnings of equity method investments relates to increased earnings from Bridger Coal Company and is timing related. We anticipate annual earnings in 2018 related to this investment to be fairly consistent with recent years.

Income taxes were $9.7 million lower, largely related to the lower statutory rate as well as a few other items. During the quarter, we saw $1.4 million income tax benefit resulting from the reversal of Additional Accumulated Deferred Income Tax Credit or ADITC amortization.

The reversal is a net benefit because we reversed $1.9 million in the second quarter of last year compared with a $0.5 million reversal for 2018. With the conclusion of various regulatory proceedings finalized this quarter and our performance so far this year, certainty around full-year expectations has increased and we now expect Idaho Power’s 2018 Idaho jurisdictional return on year-end equity to be above 9.5% and within the bid band.

Idaho Power does not expect to record any additional ADITC amortization in 2018. The $1.3 million flow-through benefit of tax deductible make whole premiums that Idaho Power paid in connection with the early redemption of long-term debt in April of 2018, also contributed to the lower income tax expense.

Finally, the Valmy plant settlement stipulation I referred to earlier, impacted income tax comparability by increasing income tax expense in the second quarter of 2017. The remaining income tax expense for the comparable periods is lower due to the -- due to the lower federal and state statutory rates in 2018.

Decreases in year-to-date income tax expense roughly correlate to the grossed-up revenue reductions and O&M amortizations discussed earlier for stipulations in both Idaho and Oregon. The tax reform stipulations focused on the pro forma impacts of income tax law changes as applied to 2017.

All of these changes combined to increase both, Idaho Power’s and IDACORP’s net income by $12.3 million and $12.5 million respectively, over last year’s second quarter. IDACORP and Idaho Power continue to maintain strong balance sheets, including sound liquidity and investment-grade credit ratings with minimal impact from the tax reform settlements.

On slide six, we show IDACORP’s operating cash flows along with our liquidity positions as of the end of June 2018. Cash flow from operations increased approximately $7 million, mostly due to higher net income and the timing of working capital proceeds and payments, offset by changes in income tax accruals and retirement plan contributions.

You’ll recall that Idaho Power issued a 30-year $220 million bond with a 4.2% coupon rate, during March this year. A portion of the proceeds from that bond were used for the early redemption in April of the 10-year $130 million 4.5% coupon bond that was due in 2020, and the remainder benefits ongoing capital and operating needs.

The liquidity available under IDACORP’s and Idaho Power’s credit facilities is shown on the bottom of slide six. At this time, we do not anticipate issuing additional equity through the end of 2018 other than relative nominal amounts related to equity compensation plans.

Slide seven shows our updated and increased 2018 earnings guidance, and estimated key financial and operating metrics for the full-year 2018. Our regulatory outcomes this past quarter have in some cases removed uncertainties and in others, approved cost recovery, such as the Valmy decision in Oregon.

These outcomes combined with our first six months results, allow us to refine and increase our earnings guidance for IDACORP to the range of $4.20 to $4.30 per diluted share. Based on the midpoint of this guidance, we would expect to achieve our 11th consecutive year of earnings growth.

This guidance change includes our expectation to no longer use additional ADITC in 2018. We reaffirm a seventh straight year of relatively flat operating and maintenance expenses and also reaffirm spending between 280 and $290 million on capital expenditures this year.

As we have moved through half of the year, current conditions and actual results suggest that the hydroelectric generation range can be tightened to the range of 8 to 9 million megawatt hours for 2018. We remind you that our guidance assumptions reflect normal weather conditions for the last six months of 2018.

With that, I’ll turn the presentation over to Darrel.

Thanks, Steve, and thanks to everyone participating on today’s call. The second quarter was a strong one for IDACORP and Idaho Power.

It started with the welcome news of the indefinite extension of our ADITC mechanism. And we continued to experience positive growth trends within our service area.

Further, both our customers and the Company will benefit from the productive regulatory outcomes that were finalized in the second quarter. As we look at slide eight, we see that customer growth continues to trend upwards.

Idaho Power’s customer base increased 2.2% last quarter compared to the second quarter of 2017. Our service area continues to make headlines as it attracts new businesses and residents.

Boise recently made Business Insider’s list of 13 U.S. cities where anyone would be lucky to live.

Our state capital also came in at number 12 on Newsweek’s list of top U.S. cities ranked by quality of life and average salary.

These accolades underscore many of the reasons Idaho remains one of the America’s fastest growing states. We have recently seen expansion of new food manufacturing and dairy capacity within the service area, including the announcement that Netherlands based cold storage company NewCold will build one of the nation’s largest sub-zero cold storage facilities in Burley, Idaho.

The number of large load requests is already 40% above last year’s total number of requests received, only six months into 2018. While not all of these large load requests result in new large customers coming on line, we have learned that the number of large load requests can be an indicator of the potential for economic growth.

As an update on a company we highlighted a few quarters ago, Formation Capital’s cobalt mine in Idaho was energized and placed into service at the end of June. We expect the load from mine operations to ramp up over time.

In a very different kind of mining, we continue to see active interest from cryptocurrency and blockchain customers. However, we have seen actual connections delay due to the volatile nature of cryptocurrency.

We are working with several companies launching operations within our service area that we expect to see come on line by year-end as we finalize the logistical and regulatory details of bringing these companies and customers onto our system. Further on the customer front, our already strong J.D.

Power customer satisfaction scores continue to improve. Idaho Power ranked second among 14 West Midsized Segment Utilities and first among our Northwest investor-owned utility peers in a recent J.D.

Power 2018 Electric Utility Residential Customer Satisfaction survey. This is our highest ever result in this customer category.

Our corporate-wide focus on enhancing the customer experience continues to strengthen our core business. According to Moody’s latest forecast, Idaho’s GDP is predicted to grow 4.5% in 2018 and 4.2% in 2019.

Employment within our region remains strong. Second quarter unemployment in Idaho Power service area was 2.8% compared to 4% nationally.

Compared to this time last year, employment within Idaho Power service area has grown 3.2%, exceeding 518,000 people employed, which is a record for the service area. On the regulatory side, I will start with the ADITC earnings support and sharing mechanism.

This spring, the Idaho Commission approved an agreement on rate decreases related to federal and state tax reform. The approved tax agreement also included a provision to extend our revenue sharing and earnings support mechanism beyond 2019.

The evergreen extension of this mechanism means any portion of the existing $45 million of unused additional ADITC remaining on December 31, 2019 will continue to be available for future use, if Idaho jurisdictional earnings were to fall below 9.4%. This is a benefit for both our shareowners and customers as it improves both, earnings predictability and potentially delays the need to file a general rate case going forward, adding price stability for our customers.

As Steve indicated, we do not currently anticipate using any additional ADITC in 2018, and we reaffirm that we do not plan to file a general rate case in either Idaho or Oregon in the next 12 months. Steady load growth, combined with increases in a number of customers, productive regulatory outcomes and the management of operating expenses all play significant roles as we look at the need and timing of our next general rate case.

We will continue to evaluate the need for general rate case in 2019 and beyond. As seen on slide nine, on April 3rd, we successfully joined seven other utility -- several -- seven other electric utilities in the western Energy Imbalance Market or EIM.

Joining the EIM allowed us to purchase energy from across the region in a more efficient and real-time manner, which generally stated, will help us respond to constantly changing customer demand by deploying the least cost available resource to balance load. We expect this will help Idaho Power keep energy rates low and will help its efforts to meet the challenge of integrating an existing large volume of third-party solar and wind energy on our system.

In May, we received an order from the Idaho Commission regarding our request to create new customer classes for residential and small general service customers with on-site generation. The order was a positive outcome for Idaho Power and its customers as the Commission, both granted our request for new customer classes and acknowledged there may be inequity in the way customers with on-site generation contribute to their share of fixed costs, under the current system.

There is still much to be done as we perform a cost-of-service study and work with the Commission staff, customers and other stakeholders to find a fair, long-term solution. But, this order is a positive first step for the Company and its customers.

And it is one of the first utility outcomes nationally in which a commission has established new classes for customers with on-site generation. Idaho Power currently has approximately 2,500 customers utilizing on-site generation.

So, we feel that collaboratively addressing the issues now will help to prevent inappropriate cost shifting to other customers in the future. I will close with a look at weather on slide 10.

We saw cooler than normal conditions during the second quarter, but the weather turned hot in July. Today, in Boise, temperatures are expected to push the century mark where we have consistently been for the last couple of weeks.

The August through October weather projections indicate a greater than 60% chance of above average temperatures in Idaho Power service area and equal chance of above or below normal precipitation. With that, Steve and I and others on the call will be happy to answer any questions you may have.

Hey. Good afternoon.

So, a few different things here. Perhaps just to come back to the rate case timing.

I mean, it seems like it could really be pushed out for a protracted period here. Can you give us a little bit more sense on the variables here and the timing?

Obviously, it’s a ‘19 decision at this point, but even beyond that, how you think about it?

Julien, this is Darrel. So, let me -- as I said in my prepared comments, we will continue to look at a series of factors, number one, what’s going on with customer growth; number two, what’s going on with the economy as a whole, what is happening with our business as a whole.

And we will look at all of those factors and determine whether or not we find the need to actually go out and have to -- and file a general rate case. The other thing you might recall that our rate case process is fairly elongated timetable.

So, it’s generally around seven months from the time we file to the time that we get an order. So, obviously, it is a long-term look at things.

And so, right now, based on what we know today, as we said, we don’t expect to file in the next 12 months. I would also say that given the fact that we have the ADITC extension that that may allow us to stay out longer than that.

But, right now, we are just committing to the next 12 months. But, with the extension and the evergreen nature of the ADITC mechanism, that may provide us additional time to stay out.

But, again, we’re not committing to that today.

And obviously, the low growth has been exceptional, and clearly that seems to be translating back into some of the preliminary stuff on the IRP. Can you comment a little bit about how that reconciles against your current thinking on generation build?

And obviously, it’s early days here in the next iterative process and maybe that reconciles with the time line for the rate case. But, can you give us a little bit more thought on that?

So, we are right just in the early stages of the IRP process. We are assessing a lot of different factors.

And I think as you know, our IRP process is very-collaborative. And so, as we begin that process, we’ll be looking at all aspects of our load and resources, and take a look at what makes sense with the things that are happening out there.

As you know, based on our 2017 IRP, the top resource in that portfolio continues to be the Boardman to Hemingway Transmission Line. And because we believe that having access to energy within the region because of the [indiscernible] nature of the Northwest, made sense then and that will be again continued to be assessed as we go into the 2019 IRP.

So, there’s a lot of factors, there’s a lot of things that are happening in the region. And we have a lot of stakeholders that we will continue to discuss as part of this process.

And so, I would like to say that I can give you some answers as to what I think 2019 looks like, but we are not in a position really to do that today. But, I would just say, stay tuned.

Because as we have these calls, we will continue to update folks as to the status of our IRP process. But, it’s a great question.

It’s something that we are very actively engaged with both internally as well as with our stakeholders.

Let me just ask that slightly differently. You’ve talked some customer growth numbers, some kilowatt hour growth numbers.

How does that reconcile against the last IRP at this point, just to kind of ultimately translate into an initial sense of how many incremental peak megawatts you might be looking at here?

Sure. That’s a fair question.

And so, as you look at where we’re at today, we talked about a 2.2% customer growth rate in this year-over-year growth. Obviously, that’s higher, that’s what’s in our IRP today.

But, again, that’s a near-term number. And we still look out on a long-term basis.

We look at over 20 years what that looks like. And so, we will be reassessing those.

We have seen swings in those numbers in prior years. And so, what’s happening today doesn’t necessarily going to happen 10 years from now.

And so, when we look at on a long term, we’ll have to align around what those growth numbers look like. But today, in the near term, those growth numbers are in excess of what’s been in our IRP.

And so, we will just have to look at it. And I would like to be able to give you more certainty as what that looks like today.

But, we are crunching numbers for that process as we speak as to what load is going to be a big part of that. And in addition to that what’s happening in the region is going to be a consideration also.

So there’s just a lot of variables that I’d like to be able to tell you what it looks like today but we’re not in a position to do that. So, we take two years to do this.

That’s fair. Can you talk a little bit more about what exactly you’d like to get done in the time line involved, given Governor Otter’s time line here for the balance of the year?

Just delineate a little bit more on what needs to get done, just given the existing administration, the familiarity on issues. Maybe I’ll leave it as broad as that.

I’ll start briefly to that, Julien. I think that, yes, the current administration has obviously been there now going on eight years and so has been actively engaged in the issues that we have had to work on, transmission-related projects, relicensing activity, among other things.

And so, yes, the current administration is very up to speed. But as you know, the Lieutenant Governor has also been in that administration for quite some time also.

And obviously, the Lieutenant Governor is a candidate for the Governor’s seat. And so that will -- the outcome of that election will have an impact, obviously on who is in that Governor seat going forward.

Again, that election will happen in November and we’ll see kind of where that plays out. But with the current administration in place, we’d love to continue to move things forward on relicensing, continue to move things forward on our site-specific criteria related to the Hells Canyon relicensing effort, some of those sorts of things.

But again, sometimes the calendar will run out and we will not force something before it’s time. And so, if the governor continues to stay in his -- if we get something done between now and the end of the year, that’s great.

If we don’t, we will work with the next administration and do what we need to do to move our issues forward. So, I feel pretty good about where we are on a lot of these things.

And when we have a transition in leadership, we have to -- I think, historically have been pretty successful on engaging with the new set of leaders. So, I think we are going to continue to manage what we can control is I guess what I would say.

But does it give you sort of -- just given the desire to finish things up from all sides, does that give you added confidence do you think that you could get some of the lingering issues, like you say on relicensing out of the way or it’s perhaps not conclusive?

I’m going to say it’s not conclusive is where I’d leave it. I’d say, we will work with whoever is in the Governor’s office at the time, and we have demonstrated that success in the past.

Did you give kind of your latest view on like the most optimistic time lines for B2H and GW?

Yes. So, on -- you’re talking both Gateway and B2H, correct?

Yes.

Yes. Okay.

So for us on Gateway, obviously, our -- the 2 sections in Gateway, we actually don’t have a specific timetable for us. We have a broad range of timing as it relates to Boardman to Hemingway.

And for us, Boardman to Hemingway -- excuse me, Gateway West is really about reliability on our system and availability to better manage our footprint. And so Sections 8, 9 are 2 of the key components there for us.

I have our transmission team representative -- they’re here today. I’m going to give them a chance to at least comment on some of the timing on Gateway West and then also talk a little bit about where we’re at with Boardman to Hemingway.

So, Vern Porter, who is our Vice President of Transmission and Distribution. And he’s got a long title, but I’ll shorten it to that.

We’ll give him a chance to kind of speak to where we are at.

You bet. First of all, for Gateway West, permitting wise, we’re continuing to make progress on that.

And we just -- as Darrel mentioned, we just got the record decision for Segments 8, 9, which were the segments really from the Twin Falls area to south of Boise here, and the most western parts of the project. So that really completes the federal committee process on that project.

Now, of course, the next steps needed to be coordinated with PacifiCorp on that project, which would detail local and county type permitting on that. We know from -- as far as timing wise, we’ve always projected that the Gateway West project would be built from east to west, which starts in Wyoming and head west towards Idaho.

And PacifiCorp this time is working on the eastern-most segment is, between a place called the Aeolus and then the Jim Bridger section. It’s about 150 miles.

So they’re starting to work on that now. And so we expect them to continue working westward.

PacifiCorp’s 2017 integrated resource plan states that they will get across Idaho and get to Hemingway by -- in the range of 2020 to 2024. So more to come on that.

We’ll continue to coordinate with PacifiCorp on timing and when those events will be built. On Boardman to Hemingway, we are making good progress there on the federal permitting side of things.

We remember that back in November 2017, the BLM issued a record of decision, a big milestone for the project. And we just received back in June, the 4 service draft record of decision.

And so they’ve just completed a 45-day comment period on that, and we expect the record of decision from the forest service and from the Navy in 2018. On the state side of things, we’ve -- back in December 2017, we submitted our applicator for site certificate.

So it’s a big application, 17,000 pages, and we are working with the Oregon Department of Energy on completeness of that application, which we expect to happen very soon. And once that happens, the Department of Energy will hold public meetings in the 5 Oregon counties.

And then they’ll start focusing on preparing and issuing a draft proposed order, which we expect to happen in 2018 as well. So lots going on and moving forward.

And we expect to continue to make progress in the permitting of these projects.

And Steve, if my math is right, which is always a dubious assumption, your trailing 12 is $452 million. What timing issues are we expecting to hit in the second half that has you most optimistic you put it right now $430 million?

Paul, trailing, you’re getting back into the prior year. I do think we had a little bit more of a particularly quarter-over-quarter, pretty heavily loaded second quarter last year.

I do think we’re on a trend to a good number and that’s why we’ve lifted our guidance. But I haven’t got a reconciliation of the $450 million.

We mentioned in the fact that some of our expenses we’ve accrued this year is related to some certainty that we feel. We were a little more predictable than last year.

And I do think, as I recall, we had some items that lifted us towards the end of last year. They weren’t necessary items we would know about at this point in time.

So I’m guessing that’s part of what’s missing right at this moment.

Darrel, you mentioned crypto. How big a load could that be?

And how do you guard yourself against potential credit risk around that volatile business?

First of all, both very good questions. And I’ll answer the second one first.

We actually are working on ensuring that we do protect ourselves from a credit perspective with these folks. And so we are working on some efforts on deposits and other things with those types of folks to ensure that we -- if they aren’t here long term, that we don’t get stuck holding the bag, so to speak.

On the first side of that, those numbers -- some of the numbers that get thrown out are pretty large. But the reality there is, they kind of run, it seems to, in 5- to 10-megawatt blocks is sort of kind of where they seem to do that.

And so they’re just looking for available capacity on our system that would be the cheapest way to hook up to our system. And so it could be hundreds of megawatts, if you believe the projections, but we haven’t seen that actually materialize.

And I think part of it, it’s been some of the volatility in that industry these days. So we are doing the best that we can to manage ensuring that the Company is protected at the same time providing service because we are -- we provide service to all.

So that’s our obligation. But we do want to make sure that other customers are protected at the same time.

So we’re actively working on that, Paul.

Darrel, you sort of were talking about pretty strong interest from new customers. But you’ve for the last, almost decade since the recession ended, you’ve had some pretty consistent acceleration of customer growth.

So now that you hit 2.2%, do you get a sense that you’re still accelerating from that customer interest?

Let me go back and share a couple of thoughts on that too. It sort of builds on Julien’s questions also.

In our 10-Q, we kind of provide the historical growth rates that we include in the IRP and both from a standpoint of peak demand and annual growth. And I think the -- it’s interesting if you were to look at those numbers, again, as we look on the long term.

From a planning perspective, they will average -- if you look at that last 3 IRPs, those annual growth rates in the 5-year windows were like 1.1% to 1.2%. On the 20-year numbers, they average about 1% on average.

And so the 2.2%, obviously, is an aggressive growth number. But we’ve seen higher numbers in the past.

And what we hope is going to actually happen is a more -- we don’t want to see the spikes of the mid-2000s because that’s not healthy as we come up and fall off a cliff. And so the hope is, we are maintaining a -- the types of customers that we are adding, I believe, are -- hopefully, are sustainable.

They’re bringing quality jobs. They’re manufacturing type of businesses, combined with some technology types of businesses to old-time mining operations.

And so it’s a really diverse group. It’s not tied to any one particular sector.

And so can we sustain 2.2%? I don’t know.

But I will tell you the level of interest we are having, as I indicated in just our new large load request interest, is pretty impressive. And it doesn’t appear to be slowing down.

So that’s -- so I’d like -- I can’t really predict the future, but I can just tell you that our service area in particular is experiencing significant growth. And I would say most of it is in and around the Treasure Valley here in the Boise area, but there’s a lot happening in The Magic Valley and Twin Falls and also over on the eastern side in Pocatello.

So that’s actually good news also from a geographic diversity perspective.

Is it possible -- I’m just looking at your growth numbers historically. And you have a lot of years that were 2.5% to 3%.

Is it possible that, that’s more sort of your fundamental growth rate there, absent the recession years?

Let’s see -- and other thing too -- I should clarify too is between customer growth and load growth because they aren’t always the same. We talk about 2.2% customer growth, it doesn’t always necessarily mean you’re going to have 2.2% load growth.

So that’s kind of another factor to consider.

Yes. Chris, I think we used the customer number often because it’s an indicator of what’s coming.

If those customers hook up, you don’t necessarily have their load that moment. Sometimes the load ramps up, it takes a period of time.

But it does show the activity that’s going on that will generate our growth. I do think when customer growth is a 2%, the load growth may be below that, probably closer to 1% and somewhere between 1% and 2%.

And as you mentioned, there has been years we’ve been around 4% when things were really going on a customer growth basis. So I guess, echoing Darrel, it’s not impossible that we go a bit higher, but it’s certainly been a steady pace in and around this level.

And we usually don’t hope for it to be higher because it’s been fairly sustainable at the level that it’s at. Those years when we approached 4%, those were right before the crash that we kind of -- people were building things that -- not sure they were needed for 5 or 6 years.

So I’m not sure that’s the most healthy place to be. But on the load side and this continuation effect you ask, I do think there is an element of our size of city, the livability of Boise that probably is lending us a little bit of longevity to that.

I don’t think it’s necessarily a flash. I have commented before that if you keep -- you watch what happened at Salt Lake and where Salt Lake has gone.

I -- look at us and think it’s similar. I think a city of our size becomes attractive because suddenly you’ve got services to provide and there are other industries there that people feel comfortable and that generates more interest.

And we’re kind of in the sweet spot right now where people are seeing and liking what they see in Idaho. I think around the country, you’d find cities that eventually hit a spot where all those things added up to, it’s not as quite as good as it used to be.

I don’t think we’re there. So I think there is time left in our story.

Okay. One last thing.

You were talking about the heat in July. How was the precipitation?

Little to none.

So this...

It isn’t really untypical.

So from a standpoint of irrigation load, it’s probably maybe where you’re headed. As we get to now, I mean, the irrigation sort of peaks around the first week or so in July and it’s that kind of time frame and then we start seeing that fall off as the crops -- depending on what crops are out there, the wheat starts coming on and those sort of things.

And so we see a declining irrigation load as we go into end of July into August. So it has been dry, quite dry.

But we’ve seen strong irrigation loads. But as the crops come up, we see a natural decline in those loads.

It safe to say, Chris, that it’s been a warm, and I’d say a good month in July in terms of the weather. You also have to remember last year’s July was, as you go to look at quarter-over-quarter for 3, last year’s July was extremely hot as well.

I think, it may have been the record at the time. So at least over, like, the last 10 years.

If we look at the last 20 years...

So we had another good July, but where it lands exactly compared to last year, it’s hard to say.

But it was probably wetter last July, right?

It seemed like the -- again, it harmed us a little more earlier. The wet that we got in the spring hurt us last year in terms of the irrigation load.

And I remember sitting here and thinking, well, we might catch up, and I don’t know that we quite did. This year is playing out a little bit more normally, I would say, pretty typical use coming into where we are today, which has helped us.

And I would expect that will continue on if the weather doesn’t change a lot because it’s hot and dry.

Thank you, Rocco. And thank you all for participating on our call this afternoon.

We appreciate your continued interest in IDACORP. And we hope you have a great rest of the day recuperating from your other calls.

Thank you very much.