Jason Lang – Inventor Relations Scott Morris – Chairman, President and Chief Executive Officer Mark Thies – Senior Vice President and Chief Financial Officer Christy Burmeister-Smith – Vice President, Controller and Principal Accounting Officer Dennis Vermillion – Senior Vice President and President, Avista Utilities Kelly Norwood – Vice President of State and Federal Regulations, Avista Utilities

Paul Ridzon – KeyBanc Andy Levi – Avon Capital Mike Weinstein – UBS

Thank you Cynthia and good morning everyone. Welcome to Avista’s second quarter 2015 earnings conference call.

Our earnings released pre-market this morning and the release is available on our website at avistacorp.com. Joining me this morning are Avista Corp Chairman of the Board, President and CEO, Scott Morris; Senior Vice President and CFO, Mark Thies; Senior Vice President and the President of Avista Utilities, Dennis Vermillion; Vice President of State and Federal Regulation, Kelly Norwood; and the Vice President, Controller and Principal Accounting Officer, Christy Burmeister-Smith.

I would like to remind everyone that some of the statements that will be made today are forward-looking statements that involve assumptions, risks and uncertainties which are subject to change. For reference to the various factors which could cause actual results to differ materially from those discussed in today’s call, please refer to our Form 10-K for 2014 and Form 10-Q for the first quarter of 2015, both which are available on our website.

Also we’re planning to file our second quarter 2015 10-Q later today. To begin this presentation, I would like to recap the financial results presented in today’s press release.

Our consolidated earnings from continuing operations for the second quarter of 2015 were $0.40 per diluted share compared to $0.52 for the second quarter of 2014. In the second quarter of 2014, we had earnings from discontinued operation of $1.15 per diluted share.

On a year-to-date basis earnings from continuing operations were $1.14 per diluted share for 2015 compared to $1.31 last year. In 2014, we had earnings of $1.17 from discontinued operation.

The second quarter and year-to-date 2014 included the gain on the sale of Ecova that was effective June 30, 2014. Now, I will turn the discussion over to Scott.

Well, thanks Jason and good morning everyone. I would like to start by thanking Christy Burmeister-Smith for her 35 years of service to the company and its customers.

This is going to be her last earnings call as her retirement was announced late last week. Her leadership in finance and accounting has played an important role in building the financial strength of our company and we’re going to miss her tremendously.

I worked my entire career with Christy and she is I think was very special and we wish her all the very best in her future endeavors. And I also hope that someone comes up with a real tough accounting question on her last call.

So turning to the financial results, we had a solid second quarter with earnings that were slightly above our expectations and I am pleased with how well our utility continues to perform operationally. Although unusual weather impacted our results, we had a solid first half of the year.

Record high temperatures and below normal precipitation during the second quarter resulted in hydroelectric generation that was slightly lower than normal combined with above normal hydro generation in the first quarter. We are expecting annual hydro generation to be about 94% of normal this year.

Despite that we still expect to be within the 90% customer, 10% company sharing band of the Energy Recovery Mechanism in Washington. This ultimately benefits both customers and shareholders.

We reached the first anniversary of our acquisition of Alaska Electric Light and Power on July 1st and we continue to be pleased with its operations. AEL&P contributed $0.9 million for the second quarter and $3.6 million to our earnings for the first half of 2015.

In addition, we continue to explore opportunities with respect to LNG and natural gas distribution in Alaska. With respect to regulatory matters, we continue to speak the timely recovery of our operating cost and the significant capital we are spending to improve our system for our customers.

We currently have outstanding general rate cases in Washington, Idaho, and Oregon and as part of the filings we have requested decoupling mechanisms in Idaho, and Oregon similar to what we have in Washington. And lastly, we are confirming our 2015 earnings guidance with a consolidated range of $1.86 to $2.06 per diluted share.

And even though The Stanley Cup has been over for two months and Mark is still wearing his Chicago Blackhawks’ jercy this morning. I will turn the call over to him.

Good morning everyone. Thank you, Scott.

Yes, I did want to callout The Stanley Cup Champions, The Blackhawks. I figure that I wear it again today for good luck.

For the second quarter, Avista Utilities contributed earnings of $0.39 per diluted share, which was a decrease from $0.44 last year. Our quarterly earnings decreased primarily due to expected increases in our operating expenses, depreciation and amortization, taxes other than income taxes and income tax expenses partially offset by an increase in gross margin.

That increase in gross margin resulted from an increase in electric cooling loads and general rate increases in Washington and Oregon. These increases in gross margin were partially offset by a decrease in natural gas heating loads.

Both the increase in electric loads and the decrease in gas loads are partially offset by the new decoupling mechanism in Washington, which was implemented on January 1st. On a year-to-date basis, Avista Utilities contributed $1.10 per diluted share, which is a decrease from $1.24 last year.

Year-to-date earnings decreased primarily due to weather that was significantly warmer than normal and warmer than the prior years in the first quarter, which reduced our electric and natural gas heating loads. This was partially offset by the decoupling mechanism in Washington, increased cooling loads in the second quarter and general rate increases in Washington and Oregon.

In addition to the fluctuation in gross margin, we experience expected increases in operating cost, depreciation and amortization, and taxes other than income taxes. For the second quarter, we did not have any pretax benefit or expense under the Energy Recovery Mechanism in Washington compared to $3.6 million pretax for the second quarter of 2014.

For the first half of 2015, we recognized a pretax benefit of $5.7 million under the ERM compared to $4.9 million last year. And for the full year, as Scott mentioned, we expect to be in the 90:10 sharing band for the ERM.

And again also to identify last year’s results, we did have our other businesses were positively impacted by a settlement in California, partially offset by a contribution to the foundation last year which resulted in about $0.09 of difference from last year to this year. From a capital expectation, as Scott mentioned, we continue to be committed to updating and maintaining our utility systems.

We expect Avista Utilities CapEx to be about $375 million this year and $350 million in the next two years. And at AEL&P we expect to spend about $15 million for each 2015, 2016 and 2017.

A significant portion of their capital expenditures are due to the construction of additional backup generation plan. At this point I’ll talk about liquidity and financing plans.

We continue to have very strong liquidity. We have $400 million committed line of credit that expires in April of 2019.

And as of June, there were $90 million of cash borrowings, and $34 million of letters of credit leaving approximately $275 million of availability. AEL&P has a $25 million line of credit that expires in November of 2019 and there were no borrowings under this facility.

For 2015, we expect to issue up to $125 million of long-term debt in order to maintain an appropriate capital structure and we don’t anticipate issuing any equity other than employee plans. For 2015, as Scott said, we are confirming our guidance for a consolidated range of $1.86 to $2.06 per diluted share.

Due to the significantly warmer than normal weather and reduced heating loads in the first quarter, we continue to expect the earnings of – reductions of approximately $0.08 per share including the impact of decoupling. We expect this to be partially offset by a benefit under the ERM of about $0.06 per diluted share.

In addition, as you recall, we did not reach the targeted level of stock repurchases, so we continue to have about $0.03 of dilution in our forecast. We expect Avista Utilities to contribute in the range of $1.81 to $1.95 per diluted share for 2015.

Due to the warmer than normal first quarter weather, again we expect about $0.08 per diluted share net of decoupling to impact our guidance. Our range for Avista Utilities encompasses expected variability in power supply costs and the application of the ERM to that power supply cost variability.

The midpoint of our guidance range does not include any benefit or expense under the ERM, and as I mentioned, we expect to be in a benefit position within the 90:10 resulting in about $0.06 per diluted share added to Avista’s earnings. We are also estimating that we will have a provision for earnings sharing for our Washington electric operations and our Idaho operations included in our expectations.

Our outlook for Avista Utilities assumes, among other variables, normal precipitation and temperatures for the remainder of the year and it includes the expected impact of decoupling in Washington. We are expecting below normal hydroelectric generation for the third quarter and normal hydroelectric generation for the fourth quarter of this year.

Due to the strong generation through April, we are expecting hydroelectric generation to be about 94% of normal for the full year. We estimate that our 2015 Avista Utilities guidance range encompasses a return on equity of approximately 8.4% at the bottom end and 9% on the top end of our range.

Moving on to AEL&P, we expect them to contribute in the range of $0.08 to $0.12 per diluted share. And our outlook for AEL&P assumes, among other variables, normal precipitation and hydroelectric generation for the remainder of the year.

We expect our other businesses to be between a loss of $0.03 of share and a loss of $0.01 of share, which includes costs associated with exploring our strategic opportunities. Our guidance generally includes only normal operating conditions and does not include any unusual items such as settlement transactions, impairments, acquisitions or dispositions until those activities are known.

So, now, I’ll turn the call back over to Jason.

Thanks Mark. Cynthia, we would now like to open the call up for questions.

Good morning. How are you?

Hi, Paul.

Good. Good morning, Paul.

Christy, congratulations. It’s been a pleasure working with you.

I hope you enjoy your retirement.

Thank you.

My first question is what was – how was hydro last year in the third quarter?

I don’t – Paul, I don’t recall last year. Last year, overall, we had a decent hydro year.

What it was in the third quarter, I don’t specifically recall. But what we’ve noticed is since the first quarter, we got very strong hydro.

Second quarter was often we really have not had any rain. So once you get through the normal melt, the hydro really relies on a annul rainfall and we’ve had very low rainfall in the second quarter and the expectations into the third quarter have been very low rainfall at this point.

So we expect that the third quarter will be softer and the fourth quarter we expect back to normal with normal hydro.

And Paul, I would just add that if you remember, we don’t get very much hydro in the third quarter anyway. So if we are a little bit below normal, it’s not tremendously impactful because we planned for that anyway.

[Indiscernible]

Well, the other thing is just we rely more on our natural gas. And then in the third quarter, our natural prices continue to be a very low, which is why we are expecting to be in the 90:10 in the ERM again is because natural gas prices are so low at the point.

And one of the assumptions you made was normal hydro in Alaska. What's the risk there if you have below hydro – and you have to below normal hydro and you have to burn diesel?

Is there a straight pass-through or is there some risk to shareholders?

This is Dennis. They – in a very low water year, the first thing that they would do is interrupt their – their interruptible customers.

They have Greens Creek mine and the cruise ship in – that interconnect [indiscernible] import. So that would be their first mode of action.

And that is not enough than they would supplement their generation with diesel. And it is – they do have a mechanism that allows them to recover that through rates.

Yes, this is Kelly. It’s called the cost of power adjustment mechanism and it’s a dollar-for-dollar tracking mechanism.

So the risk is to cruise ship and the mining that would just be some margin loss there?

Yes and that would be tracked through their cost of power adjustment mechanism.

So that would be accounted for all. Okay.

And then just – I know you’ve kind of indicated you have an answer by year-end, but your latest thoughts on LNG and LDC in Alaska.

Paul, we continue to do our due diligence and we want to make sure that we have done our homework. So while we maybe have been, I would say, appropriately cautious, we feel appropriately, I think, optimistic as we continue to look at opportunities and while we haven’t made a final decision, we expect to make that decision by our third quarter call.

And I would just say what we have seen so far makes us is positive. But we’ll make a final decision.

We want – we needed to get a little bit more information and in the third quarter call we’ll have an answer for you.

And can you share if that – that optimism is around LDC or LNG or both.

Well, again, it is really – remember it’s really around building out the LDC in Juneau and serving that load with LNG probably from some other source, not that we would build it, so it’s really be a play to build a local distribution company and the source coming from LNG.

And other LNG opportunities, we continue to evaluate those, but the one we have – the stronger expectation at this point is the Alaska – the southeast Alaska LDC in Juneau, as Scott mentioned. But we are still very actively looking at other opportunities and as we get further color on those, we will provide information.

We would expect the Alaska LDC to be a regulated business, just to make sure that you’re clear on that.

LNG would be a gating factor for an LDC?

Well, it is just the supply factor, Paul.

Okay.

You know, again, there is no gas. So we would just – we would have to find an LNG source.

We can either build it ourselves or contract with somebody and we’re as part of the investigation.

Okay, so stay tuned for the third quarter. Thank you very much.

Thanks, Paul.

Hi, good morning to you guys.

Good morning, Andy.

Hi, just a couple of things just to come kind of slow. So just on the $0.08 of weather hit and then the $0.06 of ERM benefit, are they kind of offsetting each others, is that what you’re saying?

Yes.

Okay.

And then we also have the $0.03 of dilution from a negative. So very similar – it’s same as the first quarter.

I think in the first quarter though the ERM was $0.06 to $0.07 and we’ve narrowed that to $0.06, but otherwise it’s identical to the first quarter.

Okay and I’m doing this from memory, so if I'm wrong just tell me. But I think that what you have said earlier in the year was that, if you have the benefit from the ERM, which you do, you will be trending towards the high end of your guidance, but I guess because of the weather that kind of offsets that, is that kind of the way to look at it?

That’s exactly right. The ERM, if you took the ERM in isolation, that would be above because the midpoint of our guidance we don’t include any benefit or expense from the ERM.

So with the ERM in isolation that would be towards the higher end, but with the negative impacts of the weather and the dilution that moves us down.

I understand, okay. And that’s actually answered my third question, so – which I don’t have to ask now.

And then the $0.08 is relative to normal right, the weather?

Relative to our expectations, it’s included – our expectations include normal weather, but it’s relative to our expectations…

Right, right, right, okay, great. Okay, cool.

Great. Okay, thank you very much.

That answers my question.

Thank you Andy.

Hi, guys.

Hi, Mike.

Good morning. Quick question about the rate cases and rate case fallings.

Can you give us just an update, what's going on with the partial settlement in Washington and then also what's happening with the rate case in Idaho and the one that you’re filing, you have filed in Oregon as well?

Okay, this is Kelly. We filed the partial settlement in Washington on May 4, staff and intervenors in Washington filed their testimony last week and we have a settlement discussions beginning actually tomorrow.

Then there will be – if we don’t reach settlement there, [indiscernible] is due September 4, hearings October 5 through 8 with an expectation of an order from the commission the end of the year at 1st of January. So nothing out of the ordinary in terms of proposals from staff and intervenors, who are encouraged that staff in Washington continue to use the attrition analysis, which we proposed originally in our filing, so we’re pleased to see that.

In Idaho, we filed June 1 there, a settlement conference is coming up September 18 and we would expect that case to be concluded by the end of the year. In Oregon, we filed, I believe May 1 there and settlement conferences are scheduled for September 15, September 17.

And that schedule will run through – run through early march if we don’t settle that case. So I’ll leave it there unless you have any other questions.

And I think typically you usually settle your cases right I mean until last time you actually had a litigated case.

I spent several years since we have litigated, so yes, we…

Right.

We get – we do settle if we can get the right outcome, if we don’t get the right outcome then we will litigate.

Right that makes sense. And when you talked about the attrition methodology that they accepted in the recommendation talking about customer growth attrition or customer usage attrition that you’re going to…

Actually, as I use the word attrition – the use of the word attrition just simply means that that we’ve recognized and staff recognized that our investment and our cost are growing at a faster pace in our revenues, which means you need to recognize…

A regulatory lag...

Regulatory lag, exactly. So that method recognizes there is regulatory lag and allows a provision to mitigate that.

Is it – are you talking about decoupling or some type of fixed cost adjustment like you export in Idaho?

No decoupling, actually once you set rates, decoupling helps to actually keep you in that same spot as you work through the year…

Right.

But in terms of regulatory lag attrition is really a separate way of rate making that allows you to get closer to the opportunity to actually earn your allowed return.

Are we talking about moving away from historic test years and more towards measurable changes or anything like that?

In the last that’s two different cases. In Washington, we’ve used the attrition approach, which has really put us in a pretty good place in terms of having the opportunity to earn our allowed return.

So that is a departure from the historical test period rate making with limited pro forma adjustment, so we’re pleased with that.

Very interesting and thank you.

Thanks, Mike.

Thanks, Cynthia. I would like to thank everyone for joining us today.

We certainly appreciate your interest in our company. Have a great day.