Idacorp Inc (IDA) 2007 Q3 法說會逐字稿

Good day,everyone, and welcome to the IDACORP third quarter 2007 conference call. Today's call is being recorded and is being webcast live. The complete replay will also be available from the end of the day for a period of 12 months on the Company's website at www.IDACORPInc.com. (OPERATOR INSTRUCTIONS) . At this time, I would like to turn the call over to the Director of Investor Relations, Mr. Lawrence Spencer. Please go ahead, sir.

Thank you and good afternoon, everyone. Welcome to the October 31, third quarter earnings release conference call. We issued earnings release before the markets opened today and that document is now posted to our corporate website. We filed a Form 10-Q with the SEC earlier today and that document is also been posted to the IDACORP website. Included on the call today are LaMont Keen, IDACORP and Idaho Power, President and CEO, and Darrell Anderson, IDACORP and Idaho Power Senior Vice-President of Administrative Services and CFO. We also have other officers here today to help answer questions during the Q&A period. Our presentation today may contain forward-looking statements and it is important to note the corporation future results could differ materially from those discussed. A full discussion of the factors that could cause future results to differ materially can be found in the filings with the Securities and Exchange Commission. The information that we are required to provide in connection with certain non-GAAP financial information presented during this call maybe found in the earnings press release which, again, has posted to the IDACORP website at www.IDACORPinc.com.

Before turning the presentation over to LaMont I will briefly recap the financial results presented in today's earnings in the press release. IDACORP third quarter earnings report shows net income of $28.9 million. Down $15.1 million from last year's third quarter which included $11.5 million of income from discontinued operations. Earnings decreased by $0.38 per diluted share to $0.65 per diluted share quarter-over-quarter, $0.27 per share of the reduction is attributable to the sale of IDACORP Technologies in the third quarter 2006 recorded as discontinued operations. Our Chief Subsidiary Idaho Power had earnings of $0.54 per diluted share for the quarter, down $0.17 per diluted share from last year. With that, I will turn the presentation over to LaMont.

Thank you, Larry and good afternoon everyone. If we were looking for a theme this years third quarter in Idaho, it would be put, hot, dry and occasional on fire. Temperatures were elevated. Precipitation was down and Idaho had one of its worst fire years ever this past summer. Electricity usage among most customer segments was up, the dryer than normal conditions drove up irrigation usage and warmer than normal temperatures caused residential and commercial usage to increase. Customer growth was off paced from the rapid growth we have experienced over the past several years but remains in line with the growth projections of our energy plan for the future. We added 2,555 general business customers during the third quarter bringing our total customer count to nearly 480,000. As of September 30, this year's customer additions total 7,574 compared to 10,983 through the third quarter of 2006.

More customers and extreme temperatures usually result in higher demand and that's what happened. In July, where temperatures daily in the triple-digits we set three new all time peaks. The last occurred on July 13, when our customer set the new peak at 3,193 megawatts. We continue to experience high loads throughout July and August. These hot, dry conditions also combined to produce a difficult and unusual wildfire year across our service area beginning in July and stretching into September. We lost distribution and transmission structures from the numerous fires. Our line crews worked many long days under difficult conditions to restore power to effected areas and they not only reconstructed lines that were destroyed but in some cases took preventive measures that saved key lines from burning. We are proud of the workers and the exceptional job that they do.

Hydropower contributed only 41% of total generation in the third quarter compared to 47% in 2006. This was a result of the below normal winter snow pack and the dry conditions experienced this summer. Moving on to regulatory issues, the schedule for processing our generate rate case application has been extended. The new scheduled calls for staff and intervenes to file direct testimony by December 10. Rebuttal testimony will be filed by January 4, and the technical hearing is now set for January 22 through the 25. The new schedule afford the IPUC staff and other parties in the case the opportunity to review additional information before filing their testimony. We expect to have a final decision from the commission with rates effective in February 2008. The Idaho Public Commission has a new commissioner, his name is Jim Kempton, he replaces Paul Shulander who recently was appointed to lead the new State Office of Energy Resources by Governor Otter. Jim was one of Idaho's representatives on the power planning and conservation council prior to his appointment and is knowledgeable about energy issues in Idaho and the region.

Lastly, I would like to briefly discuss our 2006 energy plan which is also called our integrated resource plan which is being refined. The plan identified a need for a 215 megawatt base load resource by 2013 and assumed it would be a coal fired plant. However, given the uncertainty surrounding future green house laws and regulations as well as dramatically escalating costs and lead time for coal fired facilities we no longer consider it prudent or practically possible to pursue a new coal plant in this time frame. Therefore, we are altering our plan and expect the next base load unit to be a combined cycle natural gas combustion turbine. We haven't yet determined a specific location but expect it to be located near our load center near southern Idaho. In addition to changes in our generating resource needs, we are also evaluating two significant transmission projects that will meet customer load growth needs as well as increase transmission capacity and reliability on our transmission system.

The first is a previously discussed project, Idaho Power Company and Pacific Corp., are jointly exploring call the Gateway West project to build two 500KV lines between Wyoming and Boise. If constructed we estimate that the majority of the Gateway West project would be completed between 2012 and 2014 and the share would be between 800 million and 1.2 billion. We are also working with regional entities to explore alternatives for a 500KV project between south western Idaho and the northwest. The specific location of this proposed line has not yet been determined. If filled, this line could be in service as early as 2012. We expect that the combination of these two major transmission expansion projects would improve reliability and access to energy markets that would serve our customers into the future. Darrell Anderson now has some information for you about our financial results.

Thanks, LaMont. And good afternoon, everyone. Today, I will review some of the key drivers to the third quarter 2007 results. I will also update you on IDACORP and Idaho Power's liquidity, equity and debt financing then finish with a brief discussion of 2007 key operating and financial metrics. After that, we will open the call for your questions. As Larry mentioned earlier, net income declined by 15.1 million or $0.38 per diluted share as compared to third quarter 2006 results. Net quarter in the third quarter of 2006 included $0.27 per diluted share or 11.5 million attributable to discontinued operations. Earnings per diluted share at the holding company increased $0.08 and $0.11 per share for the third quarter and year-to-date 2007, respectively. The increase reflects the reduction in operating expenses and the effect of enter period tax allocations recorded at the holding company. These enter period tax allocations will reverse in the fourth quarter of 2007.

Income from continuing operations declined by 3.5 million largely due to the impact of decreases in electric utility margin along with increases in utility operations and maintenance expense. Our electric utility margin for the three month period ended September 30, 2007 declined 5.4 million from the same period in 2006. And increased 1.2 million on a year-to-date basis. The third quarter 2007 was 6.5% warmer than last year's unseasonably warm quarter and more than 50% warmer than normal. Also, customer growth continued at a moderate pace from quarter-to-quarter increasing 2.4% quarter-over-quarter. Despite increase in general business revenues due to warmer than normal temperatures and increased customers. The increased cost to supply the energy for more expensive thermal generation and market purchases decreased electric utility margin in the third quarter.

Total hydrogenation for the quarter was 1.5 million megawatt hours compared to 1.8 million megawatt hours in the third quarter of 2006. For the nine month period hydrogenation was 4.9 million megawatt hours, compared to 7.7 million megawatt house a year ago. As mentioned in our earnings press release this morning and more fully disclosed in our SEC Form 10-Q, operation and maintenance expenses, increases of 6.8 million for the quarter were due largely to third-party transmission of $2 million and higher regulatory commission expenses of $4.2 million. In a third quarter of 2006, we recorded a reduction in regulatory commission expense of $3 million related to a favorable judgement that reduced our expenses in that period compared to the third quarter. During the quarter, we sold 31,000 excess SO2 emission allowances for a net benefit of $1.2 million or approximately $0.03 per diluted share. Year-to-date, we have sold 35,000 excess allowances for a benefit of $1.7 million or approximately $0.04 per diluted share.

Now turning to cash flow. Cash flow from operations decreased by nearly $123 million in the first nine months compared to 2006. The largest component of the decrease relates mainly to the increased deferrals associated with the increase power supply expenses incurred during 2007. Partially off set by decreases in cash paid for income taxes. At September 30, we had no commercial paper outstanding at IDACORP, while Idaho Power had $145 million of outstanding commercial paper. In August and early September, IDACORP issued 381,337 shares of common stock under our continuous equity program. Net proceeds were approximately $12.3 million. For the first nine months of 2007, we have issued a total of 881,337 shares under the program for a total net proceeds of approximately $28 million. The proceeds will be used to fund our ongoing capital expenditures at Idaho Power. We have recently extended the program through November 2008 with approximately 1.1 million shares remaining available for issuance.

In October, Idaho Power issued $100 million for 30 year first mortgage bonds with a coupon rate of 6.25%. Idaho Power will use the proceeds to repay the 80 million 7.38% first mortgage bonds that mature on December 1, 2007. And a repay apportion of outstanding commercial paper. I will now update you on the key operating of financial metrics for 2007. These are also shown in the earnings press release we issued earlier in the day. The only change to our operating metrics is with the Idaho Power Capital expenditure target. We have reduced our estimated capital expenditure amount due the timing of spending on a gas peeking unit at the Avandar Anders complex. We are still on budget for the project and expect that some spending originally anticipated in 2007 will move into first quarter of 2008. The plant is still projected to be available in any time for the 2008 summer loads. We look forward to discussing our 2008 key operating and financial metrics in mid-February 2008 as we announce the fourth quarter and year-end 2007 results. That concludes our prepared remarks and we would like to now respond to your questions.

Thank you, ladies and gentlemen, we will now begin the question-and-answer session. (OPERATOR INSTRUCTIONS) . We will take our first question from James Bellessa from D.A. Davidson & Company.

Good afternoon. Tell me, you went through your income statement and shareholders benefit? Or is it really rate payors that get the benefit of the sale gain.

Jim, this is Darrell. The amount we reported is the shareholder benefit portion. We have about 90% of of the proceeds deferred that we do expect to go back to customers in some form.

And you said that you sold 30,000 units or what ever -- .

31,000 unit in this quarter and 35,000 units for the year.

And can you tell us what makes you want to sell those or not to hold them or not to sell them. Do you have some program or spread them out throughout the year. What is it, the goal here?

Jim, I am going to ask Jim Miller who heads up the Power Resource side and as to how we approach the decision to sell these excess allowances. I will let Jim respond to that.

Hi, Jim, this is Jim Miller. With the last sale of 35,000. We have pretty much taken care of the surplus SO2 allowances going forward. We have a small chunk we will hang on to, but going forward, we are allocated more than we use each year and slowly build up the excesses again. And at this point, again, we have no plans to dispose of those and we will review it I guess as time allows.

And this issue that you talked about in the period benefiting from enter period tax allocations and reversing itself in the fourth quarter, would you go through that.

Sure, Jim. We will have Gene Marchioro our tax director speak to that [APB28] allocation.

Hi, Jim. I will start by saying that Generally Accepted Accounting Principles interim reporting require us to record our tax expense at a rate commensurate with annual estimate of what the effective rate will be. In order to keep our tax expense at that level, we record an adjustment at the holding company that adjusts all the company's in the group and effectively adjust all of the recorded taxes and their actual accruals to the annual estimate and that's what you see at the holding company. And that's recorded as a benefit as this is an interim adjustment it reverses in the fourth quarter and actual taxes for the year will be the final result.

How much was the third quarter benefit and then we just take it out the fourth quarter? Is that right? What was the third quarter benefit?

Jim, we haven't broken that out and if you take a look at what we reported, as it results to the holding company results and look at the change between last year and this year, there was very little APB 28 impact in last year's third quarter. So, we do have some reduced expenses in the holding company in the third quarter but the primary change is almost could be distributed to ABP28, I wouldn't say 100% of it.

You are talking about 2 to 3 million. You are saying the earnings at the holding company improved 3.1 million.

Right.

So you are saying, a fair portion of that is this allocation.

Related to the APB28 adjustment, that's right.

This year has been dry. Let's just assume that over the next 12 months you are blessed and get the average moisture in your area. What does that characterize it, if you would, please the likelihood of the stream flows for the next 12 months. Normal moisture. Are your reservoirs below average and soil moisture below average and so forth?

Jim will talk to that.

This is Jim Miller again. You are right, reservoirs are down and 50 to 60% normal for this time of year and soil moisture is down. Good October. And la Nina is setting up and we are expecting a return to normal precipe. Even with normal precipe runoff would be expected to be something less than normal as we try to refill reservoir. I think at this point with precipe, we will have something less than the normal runoff and wait and see what happens with snow pack through the winter.

Going into 2006 which turned out to be an exceptional - exceptionally good moisture year, is the reservoir level lower now than it was in 2005. Are the moisture lower than they were in 2005?

I am thinking that we are close to kind of record levels as far as reservoir being low. Don't have the numbers in front of me. But I am assuming if it isn't lower. It is awfully close to those.

Thank you very much.

Thank you, Jim.

I will take our next question from Lasan Johong with RBC Capital Markets.

I have got a couple of questions on the gas plan. And it is probably the right decision. And obviously the economics of this is a smart decision or not depends on to some degree gas prices and you have kind of a view on natural gas prices going forward?

This is Darrell. I will start and probably defer it over to Jim in a minute. First of all, one of our decision points in deciding to work towards the gas plan is the fact that we have identified a resource need and we have a timetable in which to bring the resource in and given any reasonable timetable gas appears to be the appropriate resource to bringing it on line and the timetable that we needed. That's the first thing. As we look at the gas facility and we feel fuel it is an important component of this and we work hard in hedging the fuel program related to that gas plant. I will turn it over to Jim. He can talk about the resource side of it for us.

This is Jim Miller. Can't tell you a whole lot about our look going forward. We have got initial indicative prices for long-term gas supplies for the new unit. There at least what we have got so far it is in the range of 7.5 to $8.5 BTUs.

Are you talking about 10 years, 15 years, what are you talking about.

We have bids from 5 to 20 years. So, we haven't acquired any of it yet and the unit would be expected to come on line in 2012. The way it is now.

When would you expect to enter into these hedges that would lock in the gas prices.

Right before the plant opens or starting now. We will start working in earnest to lock some of them up in 2012 and at least a portion of them fairly soon in the next year.

Have you had any discussions with the commission about these very different hedging practices and policies that you want to put into place here and is that, the commission kind of holding the gas and holding their breath at the thought of charging 7 to $8 gas prices to constituents for the life of this plan?

Well, we haven't had any specific conversations with the commission other than to tell them we switched from coal to gas.

Give me a reaction to that?

Well, I will tell you, they were very pro coal and they understand the situation we are in and the risks associated with trying to develop a coal resource right now. I think they understood and they are supportive of our move.

So, let me just put a little hypothetical spin on the situation. What happens if you can travel for the gas prices for say 15 years and around 2014, 15, 16, and due to the gas flow, is that going to cause you heartburn or problems with the commission.

Of course not. I say that tongue in cheek. And that's really no different than issues we had with lon- term coal contracts as well.

I understand the need for security of supply. That's not what I am questioning. I am questioning how rational do you think the commission would look at the decision right now relative to and retrospectively making judgement on you and pointing fingers and say you should know better. I don't agree with them. I agree with you.

Very preliminary at this point and our intent would be to have those discussions with the commission and hopefully agree on a hedging strategy and get their buy off on it before heading into a long-term contract.

Today we have an active risk management policy that we use to manage exposure that we have for commodity risk we have diesel plants that we use that risk management policy to work through the gas hedges and actually that is kind of oversoft. But participated with the customer advisory group which includes representatives from the commission staff and we expect it would be something that will be included in the conversations as we move forward with our hedging program.

That's great.

So I just want to make sure you remember we do have an active risk management program.

I understand that. And I have always understood that. That's a different story than going to the commission and saying here is what we are going to do and here is the plan and let's talk about it and get to a point where we both agree. Having a risk management structure and policy is one thing but the commissioner buy off is another totally different story. As long as you are doing that, that's fine with me. The other question is cost, $1000 K W, $1200KW.

1100 is what we are assuming right now.

Is that based on the indicative bids or kind of market information?

That is based on market.

Okay.

We have not gone out for bid yet.

Okay. So that is market information. And you said you have a particular site developed yet. What are you looking for into the site?

No, we have started a sitting study and and we have identified a number of potential sites that we will be doing investigation on. We will have a site selected by next summer.

I see. Okay. I was probably thinking of second transmission business then. And speak of the second transmission business. Any cost estimates there, you gave one for the first one but not the second.

We don't have any cost for that yet and we are still working through the details of the project. We felt it was appropriate to talk about it today and we haven't worked through it.

The joint venture. You are developing. Is that a 50/50.

It is today. That is correct.

Gateway West project.

That is correct.

Okay. Fantastic, thank you very much.

Okay.

Gateway West venture product is going in on it.

Hello?

Hello, we are not sure who that was. Or what was was? Okay. Next question.

As a reminder, if you would like to ask a question. Press star 1. And we will take our next question from Paul Ridzon from Keybanc.

Industrials dipped a little bit. Anything meaningful there or what is driving that?

I don't have anything specific, Paul, right here in front of us as it relates to this drop there.

Any update on the timing of a potential hybrid.

Pardon?

Any update on the hybrid?

Paul, we are still looking at that and evaluating that as many of the other tools as we look to finance the construction program going forward. And no new information going there.

Would you characterize it as likely.

I would characterize it as something in the tool box we would look to use. And it won't be a major part of the capital program and it has a the potential to be part of it. And it is something we will continue to look at going into 2008.

The second transmission project, the 500KV line. Is that, would that be in partnership with Northwestern, is that the line you are looking at.

That is not the line. We will be looking at, at various parties to do that line and we do not expect to do the line by ourselves.

Year-to-date on reg is that $0.17 and you are guiding 10 to 15, the Delta there is just, that the enter period tax allocation.

That's right.

And what drove the six week delay in the procedural schedule in the rate case. Was that your request. What was the impetus of that.

I will have LaMont talk to that comment.

That was by mutual agreement of the company in the party. We filed on the forecast test year for 2007 which is some what unique in Idaho regulation and the delays simply accommodated pressures on their schedule and gave them the opportunity to review more actual information before they filed their testimony.

And with regards to the wildfires, how much of the increased transmission could you attribute to that. Or is that a meaningful piece?

The increased wheeling expense for transmissions? Is that what you are referring to.

What are you speaking to, Paul? Impact of the fires.

Yes, what happened to wheeling, how much power did you have to try to move around to get around the fires. How much did that cost.

Not materially impacted by the fires. They were more inside of our system making sure we maintained service to our customers and the wheeling you see there is on other systems because of the drought and the hydrogenation was down and we purchased a lot of of energy we had to import. But not because of the fires.

Any sense at this point of which end of the 15 to 20% effective corporate tax rate you might lean towards?

Paul, we gave you a range. That was our best estimate that we have versus giving you a point estimate and it is within the range.

Thank you very much.

We will take the next question from Adar Zingo. Dimmer Lucas Partners.

I have a couple of questions. First is the second transmission line tath you guys mentioned the 500KV the same as the Macnary Boise from the IRP.

Yes.

And I just want to confirm you plan on building this with a partner?

With a partner, right.

That would be our intent.

Great. The second, can you talk more about the steps and and the regulatory process you have to go through before you can go through with these projects?

We are going to have Lisa Grow who heads up our transmission group is going to speak that question.

Hi, there, this is Lisa. We are working with the BOMs as the lead citing agency for the federal lands and then we have to go through county by county in the state of Idaho for the other private lands that we have to get permits for citing. So, so it is the right of way acquisition and citing and permitting from the agencies and from private entities. But as far as going to the Farker or the PUC, we don't have to have approval to get it. It is more about the citing and permitting.

You have to get approval in order to get cost recovery; right?

Yes.

That would be done project by project basis.

Yes.

With the various commissions.

Yes.

Same thing with the IRP process, what are the next steps there?

Same issue. And the resource has been identified, well, in a refreshed IRP, if you will. And we don't, well, let's see, well, the schedule right now is the citing process should be done by next summer and go out for a EPC contract to bid on that next summer and filed a filing with the Idaho Commission for certificate of public need and convenience. And I think it is spring of '09, I guess is about the time we go in, about the time we try to award contract.

All right. Thank you very much.

As a final reminder if you would like to ask a question, press star 1 at this time. We have a follow up question from Lasan Johong with RBC Capital Markets.

What price you actually sold your SOG credits for?

Average price was $560.

So then you bought it for roughly $525?

No, one other thing. We reported on was the net benefit that went back to the share owners in a 90/10 sharing.

Oh. I see.

So the total proceeds were quite a bit higher than that.

I understand now. Where you got the issue from. Okay. Thank you.

You bet.

And we have no further questions from the phone audience at this time.

Okay. Thank you all for participating on the call and I will turn it over to Larry.

We would like to thank you for your continued interest in IDACORP in our third quarter earnings and hope to see many of you at the EEI Financial Conference next week. We will have the materials that will be used at the conference posted to our IDACORP website next Monday, November 5. Goodbye.

This does conclude the conference call, and we appreciate your participation and you may disconnect at this time.