Avista Corp (AVA) 2005 Q2 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Avista Corporation's Second Quarter Earnings Conference Call. My name is Anthony and I will be your coordinator for today. [OPERATOR INSTRUCTIONS].

I would now like to turn the presentation over to the host for today's call, Mr. Jason Lang, Investor Relations Manager. Please proceed, sir.

Thank you and good morning, everyone. Welcome to Avista's Second Quarter 2005 Earnings Conference Call webcast. Avista's earnings were released pre-market this morning and the release is available on our website at AvistaCorp.com. Joining me this morning are Avista Corp's Chairman of the Board, President and CEO, Gary Ely, Senior Vice President, CFO and Treasurer, Malyn Malquist, the President of Avista Utilities, Scott Morris, and Vice President and Controller, Christy Burmeister-Smith.

As part of today's presentation, we'll be using some slides, which can be found on our website under the Investors section. There will also be a replay of today's call available on our website at 12:30 p.m. Eastern.

Before we begin, I would like to remind you that some of the statements that will be made today are forward-looking statements that involve risk and uncertainties, which are subject to change. I would direct you to Avista's 2004 Form 10-K and Form 10-Q for the quarter ended March 31, 2005, which are available on our website, for reference to the various factors which can cause actual results to differ materially from those discussed in today's call.

Now I would like to turn this over to Avista's Chairman of the Board, Gary Ely.

Thanks, Jason, and good morning, everyone. Reviewing our performance for the second quarter and the first half of 2005, we are pleased to note that our utility operations continued to show strong results as compared to 2004. We are also pleased with the fourth consecutive quarter of improving positive results from Avista Advantage. Although we are disappointed with results for Energy Marketing and Resource Management segment during the first half of 2005, we expect this segment to have positive earnings for the second half of the year.

Overall, the results for the second quarter of 2005 were encouraging. However, we are expecting the results for the third quarter of 2005 to potentially be a net loss for the utility. The third quarter is historically a weak quarter for our utility operations and this year's results are expected to be reduced more than normal by higher electric resource cost. This is due to the reduced hydrogeneration and higher fuel costs and the expected absorption of a significant portion of the $9 million dead band under the Energy Recovery Mechanism in Washington. The expensing of the full $9 million of the dead band for 2005 was originally expected in our earnings guidance, which we are again confirming today.

On a different note, I'm pleased with the emphasis and the focus that both our Board and our senior management team is placing on strategic planning at the corporate, portfolio and business levels. We would expect to drive an additional value for our shareholders as we begin to implement these directions over the next few years.

Lastly, we have added strength to our senior management team with the addition of Marian Durkin as our General Counsel. She begins work Monday and brings a broad background, which includes strong strategic capabilities especially in the area of mergers and acquisitions.

Now I'd like to turn this call over to Scott Morris for his report. Scott.

Good morning and, thank you, Gary. As noted in the news release earlier this morning, Avista Utilities contributed $0.38 per diluted share in the second quarter of 2005, an increase from $0.19 per diluted share for the second quarter of 2004. For the first half of 2005, Avista Utilities contributed $0.76 per diluted share, an increase from $0.41 per diluted share for the first half of 2004.

Utilities earnings were positively affected by general rate increases implemented in Idaho and Washington during the second half of 2004. Results for the second quarter and first half of 2005 were also positively impacted by a $3.2 million pre-tax gain on the sale of our South Lake Tahoe natural gas distribution property, which was completed at the end of April. This was our only regulated utility operation in California.

During the second quarter and the first half of 2005, Avista received the benefit of lower electric resource costs relative to the amount allowed in base retail rates under the Washington Energy Recovery Mechanism dead band, as compared to the expense of higher electric resource costs in 2004. Lower electric resource costs in 2005 were primarily results of improved hydroelectric generation from earlier than normal runoff due to warmer weather in the first quarter and increased precipitation during the second quarter of 2005.

In addition, total retail loads were less than expected and we optimized our electric resources through increased wholesale sales. Slide 4 presents the quarterly and year-to-date expense or benefit under the Energy Recovery Mechanism dead band in Washington for 2005 and 2004. Activity for the third and fourth quarters of 2005 represents our current forecast.

Utility earnings represent a positive benefit of $700,000 of the $9 million dead band under the Energy Recovery Mechanism in Washington for the first half of 2005 compared to expensing the entire $9 million for the first half of 2004. For the second quarter of 2005, we received a positive benefit of $900,000 compared to an expense of $2.7 million for the second quarter of 2004. However, we still expect to expense the entire $9 million dead band during the remainder of 2005 due, in part, to forecasts of below normal hydroelectric generation and increased fuel costs for thermal generation.

This is currently projected to result in an expense of $9.7 million for the third quarter of 2005, which included the reversal of the $700,000 benefit received for the first half of the year. As mentioned in our first quarter report, the lack of precipitation this winter was a concern to us. However, during late-March through the second quarter of 2005, precipitation and hydroelectric generation conditions improved significantly. We expect hydrogeneration to be about 94% of normal in 2005 based upon the forecast of below normal precipitation and stream flows for the remainder of the year. This expectation may change based upon precipitation, temperature and other variables.

We have power cost adjusted mechanisms at Idaho and Washington that mitigate much of the earnings impact of the below normal hydrogeneration conditions. Outside of the $9 million dead band in Washington, 90% of the power supply costs above the amount allowed in base retail rates are deferred and shareholders absorb the remaining 10%. Thus, the reduction in hydrogeneration is not expected to have a significant negative effect on operating cash flows or earnings from the amount originally forecasted.

As mentioned in our first quarter report in March, Avista filed a request with the Washington Utilities and Transportation Commission designed to increase our annual electric and natural gas revenues by $35.8 million and $2.9 million, respectively. The WUTC generally has up to 11 months from the date of the filing to review the general rate case. Based on the current schedule, established by the WUTC, we expect a final decision by January, 2006.

In other regulatory matters, the Idaho Public Utility Commission issued an order in April, 2005 approving the inclusion of the remaining 50% interest in the Coyote Springs 2 generating plants in base electric rates. Also in June, 2005, the WUTC issued an order which approved the prudence and recovery of the $10.8 million of deferred power costs incurred for 2004. We are also planning to file our application to license our Spokane River hydroelectric facility with the Federal Energy Regulatory Commission by the end of this week.

Finally, I would just like to bring you up-to-date on the 6 year project to upgrade our transmission infrastructure. Earlier this month, we reached a significant milestone by bringing the Boulder Substation, located in the city of Spokane Valley, up to operating at 50% of its planned capacity. Boulder is the second new substation constructed as part of this project. The Dry Creek Substation, located in Clarkstown, Washington, was completed in early June. The transmission project is expected to be completed by the end of 2007, and will help us meet our goal of increasing reliability for our customers throughout our service territory and to add valuable, additional East-West capacity to the region.

With that, I'll turn it over to Malyn.

Thanks, Scott and good morning, everyone. As you read in our news release this morning, and as you can see in Slide 6, Avista Corp reported net income of $18.6 million, or $0.38 per diluted share, for the second quarter of 2005 compared to $10.1 million, or $0.21 per diluted share, for the second quarter of 2004. For the first half of 2005, net income was $28.8 million, or $0.59 per diluted share, compared to $22.4 million, or $0.46 per diluted share, for the first half of 2004.

For both the second quarter and the first half of 2005, we showed improvement for Avista Utilities and Avista Advantage, offset by a decline for the Energy Marketing and Resource Management segment. Scott has already outlined the most significant items that affected earnings for the utility operations, including the affects of rate increases and the Energy Recovery Mechanism dead band.

I would like to make a few comments on financing activities, cash flows and liquidity before I discuss subsidiary results. We continue to focus on reducing interest costs, as well as improving interest coverage ratios and our balance sheet with a goal of restoring an investment-grade corporate credit rating. Positive cash flows from operations, proceeds from the sale of our South Lake Tahoe natural gas distribution properties and a reduction in our total cash position during the first half of 2005, provided the majority of the funding for Avista's cash requirements, including utility capital expenditures of approximately $115 million and dividends to shareholders.

The most significant capital expenditure was the acquisition of the remaining interest in Coyote Springs 2. As the acquisition of the Coyote Springs 2 was beyond our normal capital budget, we are pleased that we were able to cover the majority of the funding with operating cash flows. During the first half of 2005, we redeemed a total of $26 million of medium-term notes, scheduled to mature in future years and $8 million of notes that matured. The amount outstanding on our 5 year credit facility, a $350 million line of credit, increased from $68 million to $108 million during the first half of 2005, primarily to fund these redemptions and maturities.

During the first half of 2005, Avista Energy paid $15 million in dividends to Avista Capital, which flowed up to Avista Corp. During the remainder of 2005, we expect cash flows from operations and our committed line of credit to provide adequate resources to pay dividends, fund capital expenditures, repay maturing long-term debt and meet other contractual commitments. This excludes the $54.6 million of WP funding LP debt, maturing in October 2005. We're evaluating our options with respect to that debt and expect to ultimately refinance the debt on a long-term basis. However, the maturing debt is expected to be funded by our committed line of credit on an interim basis. If market conditions warrant, we may also issue additional long-term debt beyond the amount required to fund the maturing WP funding LP debt in order to reduce our overall debt service costs and manage the risks associated with future changes in interest rates.

The Energy Marketing and Resource Management business segment had a net loss of $0.01 per diluted share for the second quarter of 2005. The net loss for the second quarter of 2005 was primarily due to planned maintenance at the Lancaster natural gas-fired generation plant, which is 49% owned by Avista Power. Avista Energy incurred a slight net loss for the second quarter of 2005. The second quarter is historically a low earnings quarter for Avista Energy, due to the difficulty in recovering demand charges that it pays for thermal generation it controls through a purchase power agreement. Because of the availability of relatively low-cost hydrogeneration, sales of energy from thermal generation are generally lower during the spring than during other time periods.

This business segment had a net loss of $0.18 per diluted share for the first half of 2005, primarily related to losses in Avista Energy's natural gas portfolio during the first quarter that we discussed during the first quarter conference call. Avista Energy continued to produce positive results on the electric side of its business. As we discussed at length during the first quarter conference call, losses and gains from the operations of Avista Energy are due to a variety of factors. Most relate to normal business uncertainties, but some relate to variances created by differences in the ways that certain transactions must be accounted for.

The accounting treatment does not impact the underlying cash flows or the economics of these transactions. The difference is generally reversed in future periods, as market values change or the contracts are settled or realized. These differences primarily relate to Avista Energy's management of natural gas inventory, as well as Avista Energy's control of natural gas-fired generation through a power purchase agreement. These differences had a $2.3 million positive effect on the results of the second quarter for 2005, essentially a reversal of a portion of the losses incurred in the first quarter. These differences accounted for almost half of the net loss for Avista Energy for the first 6 months ended June 30, 2005.

In July, 2005, Avista Energy amended its committed credit agreement to increase the amount available from $110 million to $145 million, and to extend the expiration date by 2 years to July, 2007. We're pleased that our banks continue to support Avista Energy despite its underperformance in the first half of 2005. The amendment to the credit agreement also removed an event of default covenant, which required minimum credit ratings of Avista Corporation.

As discussed earlier, Avista Energy paid $15 million in dividends during the first half of the year. Our goal is to improve the returns from this business. To the extent permitted by various agreements, and without hurting Avista Energy's ability to conduct its operations, Avista Energy will continue to pay dividends to Avista Capital. This should lower our capital investment in Avista Energy and improve our returns.

Avista Energy has recently entered into an agreement with Barrick Goldstrike Mines located in Nevada. Avista Energy will provide for Barrick's electricity needs by optimizing their natural gas-fired generation, electric transmission and gas transportation assets. This represents further expansion of Avista Energy's successful business of managing the output and the availability of generation assets owned by other entities. Also, Avista Energy has recently expanded its natural gas end user business to commercial and industrial customers in Montana.

Avista Advantage contributed $0.02 per diluted share to earnings in the second half of 2005. On a year-to-date, Avista Advantage has contributed $0.04 per diluted share. As indicated in Slide 7, Advantage continues to show significant improvement since the first quarter of 2002. We continue to be pleased with the performance of this company. Its revenues increased by 39%, as compared to the first half of 2004, while the costs of processing a build declined by 9% in the same timeframe. The positive earnings impact is the result of customer growth, as build sites increased by 40% and a focus on controlling operating costs.

As you can see in Slide 8, we are confirming our 2005 guidance for consolidated earnings in a range of $0.95 to $1.05 per diluted share. We expect Avista Utilities to contribute between $0.95 and $1.05 per diluted share in 2005. As we mentioned earlier, we expect that Avista Utilities earnings may be negative for the third quarter of 2005 due, in part, to the anticipated absorption of a significant portion of the $9 million dead band under the Energy Recovery Mechanism in Washington. The outlook for the utility assumes a forecast of normal weather and temperatures and below normal hydroelectric generation, as well as no regulatory disallowances for the remainder of 2005.

The 2005 outlook for the Energy Marketing and Resource Management segment is a range of a loss of $0.05 to a contribution of $0.05 per diluted share. This will require the Energy Marketing and Resource Management segment to earn between $0.13 and $0.23 per diluted share for the remainder of the year. We expect Avista Advantage to contribute at least $0.05 per diluted share and for the other segment to lose $0.05 per diluted share.

And now I'll turn the presentation back to Jason.

Thanks, Malyn. At this time, we would like to open up this call for questions.

[CALLER INSTRUCTIONS.] Our first question comes from Paul Ridzon from Key McDonald. Please proceed.

Good morning. Can you offer any clarity when the mark-to-market could reverse or I guess -- ? I know it's very difficult, and is there any thinking to possibly limit activity to avoid some of the big swings there?

Good morning, Paul. If you'll remember, we talked about it quite a bit in the first quarter, that a lot of those -- that volatility dealt with the natural gas prices because when you put gas into storage, it goes in at cost, and then if you sell forward those markets to be delivered, like in first quarter of 2006, than they are market-to-market, so you have that differential. And that continues until you actually pull the gas out of the market and it depends on whether the gas prices go up or down.

What percent of the volumes should be out of the ground in '05? What should flow into '06?

Actually, all of the gas was sold forward that's in storage for delivery in the first quarter of '06. So we would expect the settlement to all occur during 2006 and the difference to reverse. But what happened, for example, in the second quarter in the interim was, gas prices changed. We had to mark the contracts to market and we actually had a slight gain, a small gain that reversed some of the earlier loss.

Gas prices retreated in the second quarter. Is that correct?

That's correct

They did versus where they were at the end of March when we closed the books for the first quarter. And so we have this quarter-to-quarter constant variation as a result of an economic transaction we made that will eventually produce positive results, but in the interim, we've got some volatility that has manifest itself.

And going forward, is the thinking, let the marks fall where they may? If you see a valuable transaction you're going to do it, even if it might have a negative, not taxable, but just earnings impact?

I think, Paul, you have to run the business as a business and you do make economic transactions. If you can buy gas at -- I used to say $3.00 -- I'll say $5.00 now, and then you sell that gas forward at $7.00 and you deliver it a year from now, well, whatever the price does in between is almost immaterial except under GAAP we'd have to report it and what the changes in 1/2 of that contract is, the sale piece, and the other stays at the inventory cost. So at the end, it's still an economic transaction and we will recover the cash flow out of that when we actually deliver the gas. So yes, we will continue making those kind of transactions.

And just every quarter, tell the Street what happened and just keep them in the loop.

Right.

Okay. Thank you.

Thanks, Paul.

[OPERATOR INSTRUCTIONS]. Our next question comes from James Bellessa from D.A. Davidson and Company. Please proceed.

Morning, Jim.

If your phone is on mute, sir, could you please un-mute it?

Excuse me. You have a slide that suggests that you have an Energy Recovery Mechanism dead band analysis. Can you hear me?

Yes, we can, Jim. We've got you now.

And it shows that you expect to have an expense of $9.7 million, if I'm reading the slide right, in the third quarter.

Yes, that is the current forecast

And you did not have this expense last year.

Oh, we had it, Jim. This is Malyn. We had -- we booked the whole $9 million of the dead band in the first half of the year last year.

Understood, but compared to last year's third quarter, you did not have it. If I look at it, that in and of itself could be $0.13 a share loss, and last year, you reported $0.05 gain. Is that the difference between the two? Is that the potential loss?

You're correct, Jim. Your reading that right.

You need to overlay on top of that, Jim, the impact of the rate increases that have occurred year-over-year, but your math is exactly right in terms of the dead band. It's a $0.13 swing from third quarter of last year to third quarter of this year.

Now your tax rate this period jumped -- or declined. It was down from the previous quarter's level. It's not consistent, the tax rate. What happens with your tax rate?

I'm going to ask Christy Burmeister-Smith, our Controller, to handle that question.

In the future, you will see more consistency in our tax rate. We will be applying [APB 28], which means that we'll project what the effective tax rate will be at the end of the year and then we'll adjust the quarter to that rate. This year, you are seeing a lower effective tax rate and a good piece of that is due to the energy credits we're getting for running Kettle Falls, our wood-waste plant.

If I took the first half tax rate, would that be a good proxy for the second half?

If you take the year-to-date tax rate, that would be a good proxy.

You had some line-item changes, several millions of dollars of changes in a couple of line items. Resource costs a year ago, you reported them at $92.4 million and this year you report them at $95.5 million. And operations and maintenance line item, last year you report at $36.4 and this year you have it at $33.3. Can you explain what happened, what the swings were from?

We did do a look at some of our definitions of what goes into gross margin and we have made some changes that we feel more accurately represent gross margin. Unfortunately, we can't restate history until we get to that quarter. I know you've asked this question before and we've discussed it with our attorneys and their advice to us is that we just have to wait until we get to that quarter. They are minor swings.

$3 million is not minor to me. You indicated that there's a hire earlier on, a person with M&A strengths and background. Tell me, is that something you're looking into, M&A activity?

I think, Jim, we don't talk about those things and we always are looking for opportunities, as we look at our business and see what things are out there, whether they be small. I might remind you that over the past several years, we've added four different areas of service to our Company. We added all the old CP National properties, the Oregon and California properties, which have been very good. And of course, we sold the California properties, which took us clear out from underneath California regulation. We bought the Citizens' Utilities up in Wallace, Idaho. We bought PP&L's properties in Northern Idaho. And we bought the old Columbia gas properties a number of years ago. That gave us a lot of gas properties down in the mid-part of the state.

So we're always looking, but, no, Marian Durkin is our general counsel. She has a broad range of background in everything from labor negotiation through M&A activity to whatever. So we're looking forward to have her come on board on Monday and I think she'll be a great strength to our team going forward.

Can you describe -- you indicated that you had some Montana business that's new to you. Can you describe what's happening in Montana?

Basically, Jim, what we're doing there is we have our retail gas marketing business in energy, that we have a very good business in Canada. And we have been doing a fair amount of that in Washington, Idaho and Oregon, where we manage the gas supply for mostly industrial customers and we're just extending that over into the Montana area.

Thank you very much.

Thanks, Jim.

Our next question comes from Douglas Lee from UBS. Please proceed.

Hi. Good morning, guys.

Good morning, Doug.

In your prepared remarks, you discussed achieving investment-grade ratings. My first question is that at the issuer S&P CCR level or is that at the unsecured level?

It's at the unsecured level.

A follow-on question is what steps do you think you need to take to achieve those metrics and what kind of timeframe do you think you can achieve those?

Our numbers, Doug, are not quite where they need to be and so we've been focusing on lowering our interest costs and interest expense and improving our earnings both, looking at both sides of the equation. And as I look at that, we think that we should have the numbers that would justify an upgrade some time next year and that's certainly the push that we're making with the ratings.

Great. Thank you.

[OPERATOR INSTRUCTIONS]. Our next question comes from John Hanson from Imperium. Please proceed.

Good morning. Just a little background on the atmosphere environment there for the rate case. I know you've got that kind of in process. Any change from the prior or how does that look in terms of running through completion versus settlement [inaudible]?

I think, John, I'll let Scott deal with that. Go ahead.

John, as you know, we filed in March and we never expect settlement when we file these. We always plan for the full 11 months. However, that being said, we are always in discussion with our regulators and we continue to have discussions. We do have planned settlement discussions, as a matter of fact, starting today for the next three days. We're hopeful that something comes out of those, but until we're through the process, we really don't know. So at this point, I would tell you to plan on January with us working very diligently to perhaps a settlement early if that's possible.

Okay. Thanks

Our next question comes from Doug Fischer from A.G. Edwards. Please proceed.

Good morning and just to follow on John Hanson's question, could you refresh my memory as to exactly what you're proposing in the rate case in Washington with regard to resource cost recovery? Will this necessarily be based on some long-term average hydro that might be difficult to achieve in '06? And how do you expect the commission to deal with resetting the price of natural gas in that calculation of resource costs?

Doug, again, a very good question. A majority of the case is really based on resource cost, power supply and resetting the dead band and the ERM. Our proposal is to eliminate the ERM -- or the dead band, excuse me, and keep the Energy Recovery Mechanism in place and get rid of the $9 million dead band. Also in that, we're planning on resetting the cost of the natural gas in the ERM to something that reflects more closely to the market that's currently in effect. So obviously, it would take a lot of price pressure off the Company if we're able have a $6.00 or $7.00 natural gas price, as reflected in rates as opposed to a little over $4.00 that are currently in there.

There is some resetting of hydroelectric generation and other normal power supply costs that you always evaluate in every rate case. So I will tell you that we're optimistic, that we'll continue to work with our regulator. We've had a lot of pre-discussions with them prior to filing. They're aware of what's in there and we'll just have to work through the process. It's difficult to say how they will react to us eliminating the dead band completely. Our hope is that it will go away. At the very least, we hope that they at least lower the $9 million dead band to something a little more reasonable.

Doug, I might add on to that. The other piece that's a fair sized piece in this particular rate case is the recovery, putting the Coyote Springs 2 second half that we purchased earlier this year, into rate-base in the state of Washington. If you'll remember, we did that in Idaho and got it in, in a very short period of time on a single issue case. And I think it's being received positively in the state of Washington as far as that purchase in the second half. So that's a big piece of this rate case also.

Just to follow up on that, I, unfortunately, don't follow Puget Sound and maybe you can recall for me exactly how they -- how and when they set the natural gas price for them as sort of an analog for what they might do for you.

I don't know that I have that here. I'm looking at the others and everybody's shaking their head. So, Doug, I don't know that I can answer that. I just want to make sure, though, that we're clear as far as the natural gas prices. Since we serve natural gas distribution to our customers, that's actually done on a PGA and it's usually done in the fall of each year and that will be upcoming, and that usually is -- in the past, it's been a pass-through or 100% recovery of our commodity cost to our customers, which is different than resetting gas prices, stream flows and other stuff in the general rate case.

Right. I was focused on the electric side. But you say $6.00 or $7.00; by a lot of calculations, it might be higher than that right now. I haven't looked in the last few days at what it is specifically in your market, but at least nationally, it's higher than that. What's your -- do you expect them to get up to near the '06 forward price for gas?

Well, actually, it's a weighted average cost of gas that they use and so even though you may see daily prices even in the $8.00 range, it's what do you buy that gas over a 12 month basis and what-have-you so it's there. So during certain months, you'll be under no-matter-what; other months, you'll be actually recovering more than what you're paying for the gas.

Doug, just so much of it depends on where the gas goes. What the staff will largely focus on for us likely is the weight [COG] that Gary mentioned and we lost a lot of our gas prices up for our generation early this year. And so what we're paying, I think, is quite a bit below market for the most part and so that's likely what the staff will focus on, which means if prices stay higher next year, we will be under again on that particular resource cost. That's why Scott said we're focusing on trying to eliminate or shrink the dead band, so that we remove some of that significant risk that our shareholders are currently bearing and what appears to be a continual upwards spiral of energy costs.

So Malyn, I'm sorry to keep focusing on this, but its an important issue. So for gas, do they use your historic weight [COG] or do they use a forward '06 weight [COG]?

Doug, what we put in the case was the best information we had when we filed the case in March based on forward price curves. Obviously there's volatility. They might go down; they might go up. So there is some flexibility. As you go forward in the case, you look at where those forward curves are. Obviously, they kind of track. They went down a little bit and now they're going back up, so that's part of the process that we'll go through. But all you can file is what you know at the time.

But they will look at the forward market?

Yes, that will be a part of it, just like our historic will be part of it and then it's always an issue, especially if you go into a settlement, as coming up to what you can agree upon might be the appropriate rate for those costs and we just have to wait and see.

Okay. Thanks.

Thanks, Doug.

Our next question comes from Paul Ridzon from Key McDonald. Please proceed.

The Washington Commission is still a little green at this point. Do you think that might have some negative impact on the ability to reach some sort of settlement or -- ?

At this point, what I would just say is that anytime you're in regulation, I think it's really based on the case and it's based on the information. We have good relationships with staff. We're confident in the new Commissioners. They're very competent people, so my guess is that the case will speak for itself and we'll settle if it's merited and we'll go the full distance if we have to.

Okay. Thank you again.

Thanks, Paul.

Our next questions comes from Harriet King from [Flats]. Please proceed.

Could you give a little bit more detail on that Barrick Gold Corporation, whatever you have going with them?

Go ahead, Malyn.

Sure. I can't give you too much more detail, Harriet because we have a confidentially agreement that we signed with Barrick to not really talk too much about what it is. But they are building a new generation facility for their Barrick Goldstrike Mine, which is in Central Nevada. And essentially, they've contracted with us to dispatch the plant, to decide whether it's -- to make the call on whether it's less expensive to run the plant or to buy power in the open market.

To the extent that there is excess generation, we will sell that into the market for them. We will procure the gas for them. We will procure the transmission for whatever transaction is the most economic, and for that, we will receive an ongoing, kind of a monthly retainer, if you will, and we will share a piece of the benefit that we create for them.

Sir, we have no further questions in the queue. And Mr. Jason Lang, I'll turn it back over to you for closing remarks, sir.

I want to thank you all for joining us today. We certainly appreciate your interest in the Company. As always, if you have any follow-up questions, please feel free to contact me at (509) 495-2930. Again, thank you for joining us and have a great day.