Pinnacle West Capital Corp (PNW) 2005 Q4 法說會逐字稿

[OPERATOR INSTRUCTIONS] Thank you, Ms. Hickman, you may begin your conference.

Thank you, Rita. I would like to thank everyone for participating in this conference call to review our earnings for 2005 and recent developments. Today I have with me Bill Post, our Chairman and CEO, Jack Davis, our president and chief operating officer who is also president and CEO of Arizona Public Service, and Don Brandt, our CFO. Before I turn the call over to our speakers, I need to cover a few details with you.

First, the quarterly statistics section of our website contains extensive supplemental information on our earnings variances and quarterly operating statistics. I encourage you to check the current quarter's section. Second, please note that all of our references today to per share amounts will be after income taxes and based on diluted shares outstanding. It is my responsibility to advise you that this call will contain forward-looking statements based on current expectations, and the company assumes no obligations to update these statements. Because actual results may differ materially from expectations, we caution you not to place undue reliance on these statements. Please refer to the MD&A in our September 2005 10Q which identifies some important factors that could cause actual results to differ materially from those contained in our forward-looking statements. A replay of this call will be available on our website www.PinnacleWest.com for the next 30 days. It will also be available by telephone through February 8th. Finally, this call and webcast are the property of Pinnacle West Capital Corporation and any copying. transcription, redistribution. retransmission, or rebroadcast of this call in whole or in part without Pinnacle West's written consent is prohibited. At this point I'll turn the call over to Bill.

I'd also like to thank everyone for taking your time to join us today. Like any other year, 2005 was marked by a number of accomplishments and challenges. And I'd like to highlight a few items for you. First, our electric operations and then a few other items. Growth in our service territory remains remarkable. Our customer growth averaged 4.3% in 2005, continuing at a pace that is second fastest in the U.S. and three times the national average. Our peak loads set a new record at 7,000 megawatts which represents an increase of more than 9% over the previous year. In 2005 we added more than 41,000 customers and passed the 1 million customer mark.

JD Power and Associates ranked APS in the top 5% in customer satisfaction among all investor-owned electric utilities in the United States. The Arizona Corporation Commission approved our retail rate settlement that resolved many of the issues created by the reversal of the electric restructuring in Arizona in April of 2005. In July, we completed the transfer to APS from Pinnacle West Energy of generation assets that were built to serve our retail customers. We announced the sale of our interest in the Silverhawk power plant in southern Nevada.

The sale closed on January 10th of this year thus closing out our merchant generation business and providing more than $200 million of cash that we invested in APS to help fund infrastructure additions needed to serve our growing customer base. Our coal plant operated a combined capacity factor that set an all-time record and we completed the second phase of our steam generator replacement program at Palo Verde. We took significant steps to add to our long term resources through the acquisition of the Sundance peaking plant in May, and the results of a RFP process that secured more than 1100-megawatts of long term purchase power agreements beginning in 2007. In November we filed a request for approximately 20% largely driven by higher fuel prices. Yesterday at the request of the ACC staff we updated that filing, which slightly changed our asking between base rates and fuel rates, keeping the total approximately the same.

Implementing a power supply adjuster or PSA during a time of high and rising fuel and power prices has required a lot of work with our regulators. Today we're implementing a 5% rate increase through a PSA adjuster and we plan to file for a PSA surcharge in the next few days which Jack will describe. In January due to the lack of action by the ACC on our 2005 fuel surcharge request and continuing high fuel prices we filed for an emergency interim rate increase, which is now scheduled for a hearing on March the 20th. As you have seen in all areas across the country, natural gas prices have increased to unprecedented levels, and we will continue to be very active in the regulatory area to recover our costs. We have also dealt with unplanned outages and reduced power operations at Palo Verde and Jack will give you more details.

Our credit ratings were downgraded by S&P and Fitch and Moody's changed our outlook to negative pending further action by the Arizona Corporation Commission on the recovery of our fuel costs. At our real estate subsidiary SunCor earned $56 million as it continued reshaping its business to focus on real estate development services in the west rather than just raw landownership. And we increased our dividend for the 12th consecutive year and sold $250 million of equity which we infused entirely into APS to strengthen our financial structure. Now Don's going to give you the pertinent details on our financial results and then Jack will update you on the regulatory developments and our recent operating performance.

Thank you, Bill. Today I will review our financial results for the year. I will also update you on our commodity risk management program, recent credit rating agency actions and our financing plans. For the year 2005 we reported net income of $176 million or $1.82 per share, compared with $243 million or $2.66 per share for the year 2004. Net income declined $67 million or $0.84 per share. Several unusual items affected this annual comparison. First, we recorded a regulatory disallowance of $0.87 per share in 2005 related to the transfer of the Pinnacle West Energy generating plants to APS. Second, we recorded a write-down of $0.57 per share related to the sale of Silverhawk in 2005 and, third, there was a gain of $0.23 per share in 2004 from the sale of our interest in the Phoenix Suns.

Several other factors impacted the annual comparison, including higher prices for fuel and purchase power, lower marketing and trading margins, and higher O&M and property taxes. These negative factors were partially offset by non-cash fuel deferrals under our PSA, 4.3% customer growth, a retail price increase, lower depreciation and amortization, weather, and improved SunCor results. Now I'd like to review the details of these factors in the year-over-year comparison.

Fuel continues to be a dominant story for our company as it is for many others in the industry. Higher fuel costs decreased earnings by $0.80 per share, mainly due to higher prices, incremental load growth served with natural gas resources and replacement power costs. Non-cash PSA deferrals of $1.08 per share more than offset the higher costs. As a reminder, the deferrals represent the difference between the amount APS is collecting in base retail rates for fuel related costs and the amount it is currently paying for those costs. Current base rates reflect 2003 fuel costs when natural gas prices were $5.78 per million BTUs, since that time, spot prices for natural gas and wholesale power have increased approximately 40%.

At year end 2005 APS had recorded $173 million of pretax PSA deferrals. Realized savings from our hedge program reduced the deferrals by $98 million. I will review our hedge program in a moment. In addition to higher fuel and purchase power costs, a few other factors negatively impacted the year-over-year comparison. Higher O&M costs decreased earnings $0.28 cents per share. The O&M changes were mainly related to higher generation costs, including planned overhauls and maintenance of $0.13 per share, and higher customer service cost primarily related to regulatory demandside management programs, and planned maintenance of $0.13 per share. Lower marketing and trading gross margins decreased earnings $0.13 per share primarily due to lower margins on competitive retail sales by APS energy services and lower mark-to-market gains on structured trading contracts. Higher property taxes attributable to increased utility plant inservice decreased earnings by $0.07 per share.

Turning to the positive factors impacting earnings in the year-over-year comparison, retail sales growth increased earnings $0.37 per share for the year. APS's customer growth has climbed steadily since early 2004 and continues to be exceptional at 4.3%. Arizona's population and job growth rates also continue to be among the highest in the nation. The April 1st retail rate increase added $0.41 per share. Lower depreciation and amortization improved earnings a total of $0.28 per share, of which about half or $0.14 per share was due to lower regulatory asset amortization and the other half or $0.14 per share was due to lower depreciation rates, partially offset by higher plant additions at APS. Hotter weather in 2005 increased earnings $0.09 per share. SunCor's earnings included -- excuse me, including discontinued operations were up $11 million or $0.11 per share for the year. This increase is largely -- largely related to higher margins on home sales.

Turning to the fourth quarter of 2005 for a moment, actual results exceeded our expectations going into the quarter. Factors contributing to this performance include higher results from SunCor, lower than expected property tax expense, surprisingly strong fourth quarter retail sales, positive mark-to-market movements and margins provided by Silverhawk capacity and energy sales while we awaited regulatory approvals to close the Silverhawk transaction. Finally on the earnings front, our earnings guidance for 2006 has not changed.

Now I'd like to turn to our commodity risk management program. I thought it would be helpful to quickly recap our hedge positions. As of today, we currently have hedged 85% of our remaining calendar 2006 exposure to purchase power and natural gas price risk for native load requirements. Similarly, we have hedged 67% of our 2007 price risk, and about 45% of our 2008 price risk. All of these calendar hedge positions are at prices substantially below current forward market prices. For example, our 2006 positions are at prices about 35% below current forward prices, and our 2007 positions are at prices about 25% below current forwards. Based on today's market prices, our hedge positions in total have a value of just under $300 million. In terms of price, and more importantly price stability, our hedging program has and will continue to provide our customers with a tremendous source of value. In 2005 our hedge program reduced our fuel costs by $120 million. Just to put that amount in perspective, in a year of unprecedented gas price volatility, average 2005 natural gas spot prices were up 40% over the prior year, but the average price we incurred on behalf of our customers increased only 5%. In 2006 our hedge positions are expected to deliver $130 million of benefit to our customers.

Now I'd like to update you on recent rating agency actions and our financing plans. On December 21st, Standard & Poor's, citing increased regulatory risk. downgraded both APS and Pinnacle West's debt ratings. The senior unsecured debt rating of APS is now triple B minus and Pinnacle West is double B plus. S&P referenced specific concerns about the company's ability to recover in a timely manager prudently incurred fuel costs. On January 10th, Moody's placed the debt ratings of APS and the parent under review for downgrade. Fitch also placed APS and Pinnacle West securities on negative credit watch in early January, and downgraded the securities earlier this week. Both Moody's and Fitch expressed similar concerns about increased regulatory risks associated with growing deferred fuel balances and the company's ability to recover in a timely manager prudently incurred fuel costs. As part of S&P's recent actions, commercial paper ratings for APS and Pinnacle West were downgraded to A3. As most of you are well aware, both companies will face higher costs and decreased availability when accessing the commercial paper markets as a split rated borrower.

In early December, both APS and Pinnacle West renewed their bank revolvers for a five year term with better conditions, including only one financial covenant and the elimination of a material adverse change clause for borrowings. In addition, APS increased its revolver capacity to $400 million, up from $325 million. APS currently has an unused bank revolver of $40 million -- excuse me, $400 million, and the parent has an unused revolver of $300 million. Regarding upcoming long term financing needs, the parent has $300 million at 6.4% senior notes maturing April 1st. We plan to refinance the notes and are currently evaluating alternatives. APS has $84 million at 6.75% senior notes maturing November 15th. We will determine our financing plans as we get closer to that maturity date. At this point we would expect APS to be in the debt capital markets in the second half of 2006. In conclusion, as Bill mentioned a few minutes ago, in January 2006 the parent company closed the sale of the Silverhawk plant and immediately infused the $210 million of proceeds into APS as equity. I'll now turn the call over to Jack.

Thanks, Don. Today I'm going to give you a brief update on regulatory developments and a summary of our recent operations. I will start with regulatory. As many of you aware we have been very busy with regulatory issues recently. These are the activities I will review with you today. One, last week's decision by the Arizona Corporation Commission related to our PSA. Two, the updated filing of APS's general rate case, three, our filing of an interim rate request for APS and, four, the filing in the next few days for PSA surcharge application.

I will review the PSA decision first. Last summer we filed a request for a $80 million surcharge under our PSA. Last week the Corporation Commission adopted administrative law judge's recommendation that APS's surcharge application be denied solely on the procedural grounds that it was premature. In so doing, the commission found that APS is prohibited from requesting PSA surcharges until after the PSA annual adjusted rate has been set each year. The commission further found that the amount available for potential PSA surcharges will be limited to the amount of accumulated deferrals through the prior year end which are not expected to be recovered through the annual adjusted rate or APS [inaudible] surcharges previously approved by the ACC. In addition -- in addition to the decision on the surcharge application, the commission adopted two important amendments to the ALJ's recommended order.

First, the commission amended its decision that approved APS's settlement agreement last April. The amendment accelerated the date of the reset of the PSA annual adjusted rate to February 1st from April 1st each year, beginning today. It also set the annual adjusted rate at the maximum four mills per kilowatt hour today, providing an additional recovery of $14 million in 2006. This action implemented a rate increase of approximately 5%, to which we will -- which we expect to recover $111 million of APS's deferred fuel and purchased power costs over the next 12 months. As of the end of 2005, APS had recorded pretax PSA deferrals including interest totaling $173 million. By accelerating the annual adjusted rate reset the commission also made it possible for APS to file a request for a surcharge to collect the remaining retail deferral balance after subtracting the estimated amount to be collected through the four mill annual adjusted rate.

We intend to file a PSA surcharge requesting -- request with the ACC totaling nearly $60 million in the next few days. The amount represents the remainder of the 2005 retail deferrals that are not expected to be recovered due to the four mill adjusted rate. The second major amend -- amendment to the ALJ's recommended order modified the $776 million cap on the annual amount of retail fuel and purchase power costs that can be recovered through base rates and the PSA. The amendment indicates that it was never the ACC's intent that the cap would create automatic disallowances of cost irrespective of APS's efforts to contain fuel and purchased power costs. It also states that APS can continue to defer for future recovery fuel and purchased power costs above the $776 million level.

On our conference call last quarter we stated that we expected APS's retail fuel and purchased power costs to exceed the cap in the fourth quarter of 2006. Based on APS's hedged positions and forward prices as of the beginning of 2006, we estimate that APS's retail fuel and purchased power costs will be approximately $830 million for the year 2006. We were disappointed that the commission adopted ALJ's interpretation related to our PSA surcharge -- surcharge application, but we were pleased with the action to accelerate the fuel recovery and removal of the $776 million cap. Yesterday as requested by the ACC staff, we updated our general rate case filing to use a test year ended September 30th, 2005, instead of the test year ended December 31st, 2004 that was used in APS's original filing last November. In addition to the required financial schedules, we updated all of our prefiled direct testimony. The ACC staff -- staff has agreed to complete its review of the updated filing for consistency with ACC regulations by the end of February. Sometime after the staffs completes its review the ALJ will issue a procedural schedule.

You may recall that the original filing requested an overall increase in retail rates of 19.9%, or about $409 million in annual revenues. The updated filing requests a rate increase of approximately 21.3% or about $454 million in annual revenues to be effective December 31st, 2006. The major components of the updated filing are as follows. Increased fuel and purchased power costs 14%. Updating our capital structure and costs. 4.6%. Rate-based updates including acquisition of the Sundance plant, 2.2%, pension funding 1.9% and all other items net a negative 1.4%. Although the updated filing increased by $45 million from the original request, the increase is due entirely to higher fuel and purchased power costs or in the previous filing 12 -- 12% of the original filing to 14% of the original -- of the filing filed yesterday. These costs would have been eligible for recovery and future under the PSA to the extent they are not included in base rates. As a result, if ACC approves the requested rate base -- base rate base increase for fuel and purchased power costs, subsequent rate changes to the PSA would be reduced. It's simply a matter of which regulatory mechanism provides for the recovery. More details to the updated filing are included in the Form 8K we filed this morning. Finally on January 6th, APS filed an emergency interim rate application with the ACC. This request includes a retail rate increase of 14% or $299 million in annual revenues to be effective on April 1st of this year.

This request is necessary to address APS's undercollection of higher fuel and purchased power costs. It represents the fuel component of the updated general rate case we filed yesterday and would be collected on an interim basis subject to refund until the ACC renders its final decision in the permanent rate case. Through the rate increase, the base fuel rate would be increased to $0.031904 per kilowatt hour from the current $0.020743 per kilowatt hour. The change would update our base fuel rate to our estimated costs for 2006 compared with the 2003 price levels embedded in the current rates. By letter -- by better approximating APS's better fuel costs, it would allow proper matching of rates and costs. It would also decrease the amount of costs that would be deferred under the PSA. APS's emergency application also asks the ACC to remove the $776 million cap on an interim basis until the decision on the APS's request -- APS's request in the permanent rate case to remove the increases of the cap can be addressed. As I've already said, the $776 million cap was modified pending further commission consideration in last week's ACC decision of the PSA, making that request moot. Last Friday the ALJ issued a procedural order for the emergency request. The ACC staff and intervenor's testimony will be due February 28th, APS's rebuttal testimony will be due March 13th, and a hearing is scheduled to begin March 20th.

I'd like to -- to turn now to the growth in our market and meeting resources needs for our future growth. Growth in our service territory is remarkable and has been accelerating over the last two years. Population growth continues to be at least three times the national average. That growth is the foundation for our customer growth, which was about 4.3% for the year and had accelerated to 4.5% by the fourth quarter. Our retail sales increased 4.4% for the year, including a 6.1% increase in the fourth quarter. Residential sales increased 6% for the year and at 6.4% in the fourth quarter. On a weather-normalized basis the fourth quarter retail sales increased 6.2% and residential sales increased to 7.9%. Since our service territory is in a high growth market by any measure in our industry we are experienced as successfully meeting such growth.

To that end we are continuing to add long term resources. In mid-2005 we issued two requests for proposals, both in accordance with the terms of our rate settlement agreement of last April. The first RFP was for 100-megawatts of renewable resources the second, which we refer to as a reliability RFP, was for at least 1,000 megawatts of long term capacity with delivery beginning in 2007. Responses to both of the 2005 RFP's were strong. We selected a total of 150-megawatts of renewable resources and obtained the necessary approvals from the ACC on out-of-state contracts. Through the reliability RFP process we are entering into purchased power agreements with three companies, with a total capacity in the amount of 1,150-megawatts to begin delivery in the summer of 2007 with durations of nine to ten years. Recognizing that our customers' energy needs continue to grow, last week we announced another RFP which we are calling a base load RFP. Through this new RFP we are seeking proposals for long-term, unit-specific, base-load generating capacity of 100 to 500-megawatts per unit. We are requesting delivery as early as 2009 but no later than 2014.

Next I will briefly review some of our operating activities. I will focus my comments mostly on the fourth quarter and January since I've reviewed the operations for the first three quarters with you on previous calls. Looking at our power plant performance, the combined capacity factors are in nuclear units were 61% during the fourth quarter and 77% for the whole -- for the year as a whole. These capacity factors were down from 74% in the fourth quarter of 2004 and 84% for the year of 2004. The primary factor affecting the comparisons was the planned refueling outage at unit one in the fall of 2005 during which we replaced the steam generators. low pressure turbines, and pressure riser -- pressure -- pressure riser heaters in the unit. The outage was planned for 75 a to 80 days and the work was completed in 77 days. Replacing the steam generators in unit one completed the second phase of our steam generator replacement program. We will complete the program in the fall of 2007 when we replace the steam generators in unit three. The outages when we replace steam generators are little more than twice the length of our normal refueling -- refueling outages.

In the fourth quarter we experienced some -- experienced some unplanned outages time at Palo Verde units 2 and 3. The units were out of service in mid-October for nine 9 days. I discussed these outages during our third quarter conference call. As a reminder, we took the units off-line on October 11th in accordance with our technical specifications when plant engineers could not demonstrate within the required 6 hours that the original design of the emergency core cooling system would operate within acceptable limits under certain scenarios. The units were restarted after extensive analysis was satisfactorily completed demonstrating that the original design would properly function under all scenarios. Unit one has been running at approximately 25% since December 25th when we stopped power at the refueling outage due to acoustic impacts in one of the units shut down the cooling lines. We are in the process of designing remedies and we will apply them to the issue. We estimate that, to date, units 1 reduced output has resulted in incremental replacement costs of approximately $12 million after taxes. As I have said before, we are unwaivering in our commitment to safety and operational excellence.

Last quarter I explained that we have done a lot of self-assessment and industry benchmarking. and I also discussed several steps taken -- several steps we have taken to ensure that Palo Verde gets back to and [inaudible] solid operations and improve our outage performance. To remind you, these measures include we added new management at the plant specifically Cliff Eubanks, vice president of Operations. We have formed and are now implementing a performance and improvement program to look at all aspects of the plant, and lastly we reorganized the plant functions to clearly focus on the areas of responsibility, in other words operations focused only on operation and engineering focused only on engineering. Our fossil plants have operated superbly. During the fourth quarter the coal plants posted a 92% capacity factor compared with a 88% in the fourth quarter a year ago. For the year 2005 as a whole, the coal plants operated at a 87% capacity factor compared with 84% for 2004. thus exceeding our high expectations and industry average. Compared with normal operating levels this exceptional performance reduced our pretax PSA deferrals from 2005 by some $10 million.

Our gas fired plants operated at a 19% capacity factor in the fourth quarter and a 20% capacity factor for the year. As Bill said, APS ranked number 1 among investor-owned electric utilities in the West in customer satisfaction by JD Power and Associates in 2005. Employees throughout our organization continue to focus on excellence -- excellence to maintain our top standing in that survey. In summary, our employees throughout the company are steadfastly focused on providing excellent, reliable service to our customers at a reasonable prices. In doing so we emphasize efficiency and safety every day. That concludes my remarks, and I will turn it back over to Bill.

Last week the Arizona Corporation Commission took a positive step toward recovery of our deferred fuel and purchased power costs by accelerating the effective date of our annual PSA adjuster rate. More progress in this area is critical in the near term to ensure that we recover our fuel costs on a timely basis. Approval of a PSA surcharge will provide the recovery of the portion of our 2005 deferrals that were not will be recovered through the adjuster rate, and raising our base fuel rate to reflect today's cost is essential to allow us to recover our current costs. We have filed an emergency interim rate increase asking the ACC to do just that. We have been successful in working with our regulators to achieve constructive outcomes that balance the interests of our customers and our investors. We are also committed to maintaining our investment-grade credit ratings to ensure cost-effective access to the capital needed to serve our growing customer base.

We are very serious about returning our nuclear units to their exceptional record as the energy cornerstone for our company in the Southwest. I'm convinced that the issues we face at Palo Verde are being fully addressed, and we will be successful in reducing unplanned outages in the future. We will not waiver in our commitment to excellence in every facet of our business. We'll continue to focus on maintaining high levels of operating performance, improving our efficiency and innovation, managing the risks and costs of our business, providing reliable, top-tier service to our customers at reasonable prices and providing a fair return to our investors. That concludes our remarks and we'd now be happy to answer any of your questions.

[OPERATOR INSTRUCTIONS] Your first question comes from the line of John Kiani with Credit Suisse.

Good afternoon.

Hi, John.

Can you tell us how far below market the '08 hedges are? I think you mentioned '06 and '07 were 35% and 25% respectively. Can you talk a little bit about '08?

I don't have it real handy John but it is between 28 and 30% below market.

Okay. Okay, great. And then the hedges are swaps not collars, correct?

It's a combination of a variety of things, Nymex contracts and option structures.

There are some option structures in there. Is it possible, Don, to provide any type of sensitivity to the $830 million fuel and purchased power forecast fixed to changes in the heat rate, the market heat rate?

No. I -- I really don't have that information here handy.

Okay. And can -- can we at least assume though if the market heat rate declines that obviously that $830 million forecast would decrease and if the market clearing heat rate increases that the $830 would increase?

Yeah. But not by a very large number.

Okay. Great. Thank you.

[OPERATOR INSTRUCTIONS] Your next question comes from the line of Michael Goldenberg with Luminous Management.

Hi, Michael.

Can you hear me?

Yes, sir.

Just had a question and follow-up to the previous question, I think it was Dan Angus, who -- how much of your energy is hedged out in '08 and how much of your fuel needs are hedged out for 2008?

Between 20% and 30%.

20 and 30. So right now the -- the net present value of the hedges is $170 million per filing, right? Is that correct? No.

No. It's 3 -- 300, and I don't know about net present value but the current market value of our hedge positions is just a hair under $300 million.

Okay. I thought the filing said $170 million, or is that apples and oranges?

The $170 million is the deferrals from the year 2005 so those are apple and oranges.

Got you. Okay. So you -- there is $300 million of savings that you have achieved your customers. Now when those hedges expire, does that mean the commission will have to authorize another increase, or are you going to work something out as part of this rate case?

Well, we -- we described the various filings that we've made. And the -- as Jack described to you, we've got a -- we've got a surcharge filing that we'll be making in the next few days. We've got an emergency filing that we made last month that basically deals with the base fuel rate in terms of the -- the year 2006, which would be approved on an interim basis, and then affirmed in the final base rate case that we're also pursuing. So to answer your question, you'd have to make assumptions on what the outcome would be for all of those three before you got to 2008.

But assuming you get everything, you would still then, once the hedges roll off and if gas prices do not decrease, you would still need an additional increase to mark yourself to market whereas right now you are charging customers below market because you have these effective hedges in place?

Not necessarily, no. No necessarily. There could be a situation where what you say is true but it also could be a situation depending upon what the average fuel price was in 2008 compared to 2007, which includes a lot of other factors like weather, and sales growth and a lot of other things. It could be that there would be no change in prices so -- so you can't come to that conclusion without having a number of other assumptions.

Understood. Got you. Okay. Thanks.

Your next question comes from the line of David Grumhaus with Copia Capital.

Good afternoon, guys. How are you?

Good. How are you today?

Good. A couple questions for you, just wondering the press and the politicians, how they're supporting you or not supporting you with regards to the different filings and, you know, commission sort of dragging its heels on some of the -- the fuel recovery. Any comments on that?

Well, I -- I'm not sure I understand your question.

Well, I guess I'm -- is the press and the politicians been supporting you on your -- on your efforts to try and pass through these fuel costs which were in your deal, or have they been against you? Or is it sort of split, with the press one way and the politicians the other way? Just sort of interested in what the political climate is as you try and -- and get recovery on some of these things.

I'm not sure that you can come up with a generalization that's going to answer your question.

Okay.

This comes down to recovery of fuel costs. And basically natural gas prices. So it's not even just total fuel. It's basically the ones we've been dealing with so far have been natural gas prices, I think it's -- it's pretty much understood across the board that we have seen significant increases in natural gas prices, and in fact in the hearing that we had, in the surcharge proceeding in 2005 where we had several ntervenors, including the residential utility consumer office, they were all supportive and. in fact, unanimous in their position that these fuel costs should be recovered. So I don't know if that answers your question or not. But I think given the fact that we have seen significant increases, as Don described to you, in terms of natural gas prices, there is an understanding that we've got to be able to recover prudently incurred costs.

Okay. That's helpful. Next question. You know, assuming that the procedural schedule comes out in late March, early April, which I think is what you indicated, any sense of how long the case will go? Do you expect that schedule to be six months? A year? Any views on that?

Yeah. I -- this is Jack. As I mentioned in my prepared comments, we'll get a sufficiency or make sure the filings are all in order by the end of February and from that point in time the ALJ will do a procedural schedule. I mean, I guess realistically speaking we would look at a decision in the first part of 2007.

Okay. So nine months, nine to twelve months or something like that? On the -- on the schedule?

I think you'd be on the -- on the -- closer to 12 months than you would be to nine.

Okay. That's helpful. And lastly, Don, you know, the drivers going from '05, the key drivers from '05 to '06, your guidance you gave last time which you reaffirmed today was around $3. You know, I think backing out the onetimers you get around $3.25, $3.26 for this year. Obviously SunCor is coming off a little bit. What are some of the other things that will bring you down?

Again, it will be a combination of -- of fuel costs. It will be a -- will be a component, the sharing component, the fuel costs and OEM expenses.

Just taking care of the increased growth?

Yeah.

Okay. Great. Thanks for the time.

Yes, sir.

Your next question comes from the line of Steve Fleishman with Merrill Lynch.

Hi, guys. Can you hear me okay?

You bet.

Okay. The -- could Jack maybe just update again I know you did this, but I -- I think I missed some of the detail, the schedules for the interim requests and then the PSE -- PSA surcharge application?

Well, I'll start with the -- with the -- the interim request, the long and short of it is -- is a hearing would begin on March 20th.

Okay.

Okay? The PSA surcharge application, which we'll be filing in the next few days, and we're still drafting our filing, could be done in two ways, two parts. One would be the part that's not related to Palo Verde outage costs could be coincident with the conclusion of the interim rate increase, and then the part having the -- related to the $45 million of Palo Verde outage costs would be solved at the conclusion of the commission's prudence audit of Palo Verde operations.

Okay. Can you comment on -- obviously you received some -- a little bit of help versus the ALJ in this recent ruling but there does seem to continue to be a lot of -- I guess that was a three to two vote. And there was -- almost seemed to be some commentary that, all right, we let them have this but the bigger stuff's still ahead. And -- and just you -- you know, it -- it almost seems like some of the commissioners at least feel like they're -- don't seem to be blaming it just on gas, for whatever reason. So I -- I guess my question is how -- how are you addressing some of these pressures, or is there a way to make a better case to the commission than you have so far? You know, obviously these are -- these are costs you are taking on, and they are real costs but just -- just a little more color on that. Because, I mean, it was a 3-2 vote but if you listen to it it was not a pleasant two day process.

This is -- I guess I would look at the two day process at the end of the day, and the outcome for us was certainly a positive indication of the situation we find ourselves as related to fuel cost and I realize there were other comments made during the proceeding regarding to other, could I say cost issues. I think the best way to answer that question would be in our filing yesterday that we made updating our base rate case we submitted a letter in that filing going through a significant description of all the things this company has done over the last ten years to manage our costs. And so rather than just answer maybe some of the miscellaneous questions asked during those two day open meeting, Steve, we actually submitted yesterday a more in-depth -- a discussion -- discussion of how we've managed the costs over the last ten years.

Okay. Steve, if I could add one thing to that, that proceeding was a very unusual proceeding. It's a proceeding that the commission has in its rules here to have the ability to be able to deal with previous decisions so the proceeding itself was a -- really unusual, frankly pretty extraordinary proceeding that was started by the commission in order to go back and deal with the April 1 implementation date of the -- the of the PSA. So it was a --

Um-hum.

-- relatively quick and certainly extraordinary hearing in terms of -- on the part of the commission. As we went through those two days with the commission, many issues were brought forward that really dealt with things that went way beyond the scope of the specific issue in terms of the implementation date of the PSA. So, you're right, there were many comments made by commissioners in that proceeding, for which really previous evidence had never been taken or issues really hadn't been addressed before the commission. As we go forward and we deal with emergency case and the base case, we're going to be providing testimony. There's going to be evidence. We're going to be going through a process to deal with any and every single one of those issues that was brought up last week. so I don't think that you can conclude that because issues came up there on topics that were really outside the normal realm of that kind of a proceeding to deal solely with the date, that it's not something that the commission would deal with in an open way going forward, and we fully intend, and as Jack said we made a filing yesterday and we will continue to do so in dealing both with the emergency case and the base case to provide the entire story and the foundation for many of the topics that were discussed in that two-day proceeding. Now, I don't know if that's helpful or not. But I --

No, that's -- that's helpful.

I think it is important to put it in perspective and that the commission was trying to act quickly to deal with a very narrow and specific topic and, in the process that was unusual. And so I think -- I think drawing conclusions from that about individual issues that would normally be dealt with, let's call it, in a base rate case, I -- I think that would not be appropriate.

Okay. One -- one other question, just -- if I look -- the commission -- how many commissioners are up for election this fall?

Steve, there are two commissioners up for election this fall.

Okay.

Commissioner [ Inaudible ] And Commissioner Spitzer.

Okay. And then typically your other -- Governor, legislature has stayed out of all sorts of utility issues that I recall. Just are they -- has there been any interest in those areas in -- in -- well, I'm sure there's interest in what's going on with this, but just would you give any sense of their support for the company and -- and understanding of why rates are going up?

Well, let me -- let me -- let me comment on that if I could from two points of view, one is its been tradition here that the -- the legislature, the Governor and any other state agencies basically leave it up to the commission to deal with these issues, and I -- I believe that's going to be the case as we go forward. To your -- the other part of your question, is there an understanding here, I believe there is. I believe there is an understanding that it's important for us to be able to meet the needs of -- of a very significant and growing economy here. And as a result of recovery of something like fuel expenses, we -- or lack thereof -- we could impair the ability of this company to be able to meet the future infrastructure requirements of the state. This is an economy that basically is very dependent upon growth. And from the standpoint of -- of the -- of the future of our state, and -- and the impact that growth has in terms of the revenues for the state, and basically the -- the entire economy of the state, growth is -- is fundamental. So I think there is a strong understanding of the importance of growth. And a strong understanding that we need the electric infrastructure here, along with other infrastructures, but certainly the electric infrastructure in order to be able to meet that growth. As I said a little earlier, our -- our peak load grew 9% this year. We've been pushing in that range in the last two to three years 11%, 9% to 11% per year in terms of growth. So I do think there is a -- a very solid understanding of the importance of electric infrastructure, and our ability to be able to finance that is critical to the future economic growth of our state.

Okay. Bill, thank you very much.

You bet. Thank you, Steve.

Your next question comes from -- comes from the line of Zach Schreiber from Duquesne Capital.

Hi Bill, hi Don, it's Zach Schreiber. Can you hear me?

Hi, Zach. How are you?

Good. I was just wondering if we can go over the surcharge proceeding and make sure I understand it. You had spoken about, I think, $200 million or so that you were going to file for and it was the -- it was the dollars that were deferred in '05 that were unrecovered, I thought, by the four mills and I just wanted to make sure I had all that and be sure I understood it.

Zach, this is Jack. The arithmetic is like this. We had about $173 million plus or minus in the PSA deferrals of 2005.

That is the 90% after already eating the 10%?

Yeah, that's correct. That's what's already in -- that's what's actually in the deferral account and then of course the -- the PSA was approved to be effective today.

Um-hum.

And that has a remaining balance of approximately $60 million. And what the administrative law judge order states that was approved by the commission is that we can now file for a surcharge to recover that $60 million.

I'm sorry, I'm sorry what has a remaining balance of $60 million.

$60 million. And we will be doing that in the next few days.

But what -- what -- what -- where does the $60 million come from?

Well, there was -- that was the remaining deferrals from 2005 that will not be collected in the 4-mill PSA surcharge.

Got it, got it. So that is the balance after the 4 mills.

That's right.

Perfect. But -- but effectively though is -- so -- I got it. Okay. So -- so basically you got -- you got -- you got $173 million that's deferred, you have already eaten 17 of it, right? You filed for the 4 mills, that's going to get you about a $100 million so on on a annual basis. It gets you another $14 million, $15 million dollars by accelerating it by two months. On an annual basis. what's left is the $60 million, you put that in for a year for the surcharge and then you're -- should theoretically be made whole on what you already deferred, but that still does not cover you for what you would keep bleeding on a go-forward basis.

That's correct. Our PSA and the surcharge is not a forward looking mechanism. It's a remedy.

That's why it is important.

And why we filed the interim price request that we filed on January 6th which quite simply just moving up the fuel portion of the general rate case we had filed.

Right. Okay. Now on -- on the -- on the cap and I was one of those unlucky persons who had -- who had to spend two days listening to -- I guess not as unlucky as you folks who had to spend two days going through the process, but on the cap, I mean, it -- clearly it felt like they were trying to soften the cap up and not make it a hard cap and not -- and not make it automatically be disallowed above the cap. But what is the status legally of the cap right now? I mean, you're allowed to defer above it. But you're not guaranteed recovery of those costs that are deferred, they're still subject to future prudency reviews and so forth, right?

Well, first of all, Zach, the cap was eliminated.

Eliminated or you're still allowed to defer over it?

I guess it is six of one -- eliminated. I'm going to use the word eliminated,because your comment about prudence.

Exactly.

Any -- any costs we defer, whether it be the old costs under the $776 million cap or above the $776 million cap --

They're all subject to prudence --

It's always subject to the prudence determination by our commission.

So -- so basically you're saying.

Below or above.

You're saying the cap exists but it doesn't have any significance?

The cap was eliminated.

I mean they still say the cap was there but you're allowed to defer above it, we might be getting into semantics, I'm not sure.

Well I think we're getting into semantics. It has no bearing -- let's put it this way, it has no bearing on our deferral accounting.

Got it. Okay. -- and then -- and -- and then just on the -- on -- on the updated rate case, did you guys change the equity ratios? Did you change the -- the ROEs or was everything that you did in there really more related to the fuel portion and related to sort of O&M and expenses?

We -- we didn't change the cap structure or the -- the requested ROE. As I mentioned in my -- my prepared remarks, that by -- the [inaudible] change is just a -- updating the fuel costs.

Got it. And then was just wondering if we could talk about the real estate business. We sort of read a lot about real estate out here, and it seems it is slowing down, new home sales were down 9% last month. Clearly you guys are in a part of the country that has a great demographic backwind at it with all of the aging baby boomers, are you guys being impacted by everything that we read about in the newspaper that's negative? Is there anything that's going on that's sort of impacted that business since we last spoke about it? Or is it just business as usual and -- and you guys are sort of immune to all of the gloom-and-doom newspaper articles that we read out here?

Zach, let me make a couple of comments and Don can chime in if he's got anything in addition. As Jack talked to you about, we're looking at -- if you look on the electric company side, we're looking at growth in the range of 4. 5%. I believe it's reasonable to just take that 4.5% and translate it over into the population growth. So unlike some of the population estimates that you see for Arizona that are in the range of 3% to 3.5%, we're growing at I think at least a percentage point above that. So, we're probably growing in the range of 4.5%. So the market here is very, very strong. And doesn't follow some of the -- some of the leading indications that you have seen in other parts of the country. That's not to say that it's -- it's not something that we don't consider. So from -- from our standpoint, we are in a situation where we have exceptionally high growth, certainly some of the highest growth we've ever had in the history of the state. But as we look forward I don't want to give you the impression that we're just taking that 4.5% growth and then taking that into the next three years and assuming that's going to be the case. We're not doing that.

Um-hum.

Zach I can just add a little bit and I don't think it's any indication or indicative of what you saw or what you see out on the East Coast but I know our December contracts on home sales.

Um-hum.

-- were actually a little under our expectations, and I just got an update yesterday or the day before on this, but they've come back since the first of the year like gangbusters.

Um-hum.

And from a home sales front we'll have a pretty good fix on the year by the end -- you know, someone by the end of April, towards the end of April with an eight to nine -- nine month lead time to -- to close a home sale, to build the home and -- and close it.

So you'll have visibility on it by April?

Yeah. We'll pretty much know what the year is like because you can't build a home any faster than that.

Great, guys. Thank you so much for your time and for your transparency and candor during a very interesting, complex regulatory window.

Zach.

Your next question comes from the line of [Sean Burke] with HSBC Securities.

Hi, I had a couple questions about the replacement power and the situation in Palo Verde. If I understood you correctly in your prepared remarks you've got $12 million of replacement power expenses from PV 1 since the 25th of December. Could you tell me, is that as of, you know, today or trying to dimension what it is on a monthly basis.

You know, I'd rather not -- I don't have it, what is it is it on the day -- first of all, monthly basis it could vary widely with intraday replacement cost prices and load so I would hesitate to give you any predictor of -- of -- of rule of thumb kind of --

Well, in other words from the $12 million.

What's the date for that period, it is as of last night.

Yes.

Last night.

Okay.

So it's from the 25th to the 31st of January.

And am I correct that there's a -- the prudence review on just the Palo Verde expenses that the commission is looking at, is that about $45 million? Is that a good number?

The number that was mentioned in the proceeding, or the number that's for 2005 is $45 million.

Okay. So would this 12 be possibly added to the 45?

It most likely would be.

Okay. In terms of the actual steam generator that got replaced at PV 1, would it be accurate to say that it was an identical unit from the one it replaced, or were there changes to the steam generator that might have precipitated some of the problems that you're seeing?

Well, the steam generator -- steam generator that was replaced on unit one was a little larger generator than was there. It's a -- it's a twin to the ones that were replaced in unit 2. And now you -- now you want to get into the engineering aspects here. No question with a larger steam generator, the flow rates changed, in other words, a higher flow rates in the cooling system, and there are theories that say that that could be contributing to the issue, but I should tell you that in unit 2 which we also put in larger steam generators, we didn't get the same issue come forward.

So trying to make a direct connection between the two is difficult to do at this time. You -- you are dealing in the area of fluid dynamics, and those kinds of things, which is not as an exact engineering as other engineering disciplines.

Okay. Two related questions, what would be the process let's say that you get into a position where you actually have the unit ready to go at full power, how do you -- how do you dimension that with the NRC, and the second and related question is: The position of the co-owners of the plant, is there something in the operating agreement that kind of fixes their portion of the replacement power costs, or do they somehow, the co-owners somehow have a recourse back to APS if there is -- in other words, is this some kind of retroactive review that they can undertake?

I'll answer your -- your first question related to the NRC, the NRC is fully informed each and every day of the process that we're going through in order to -- to solve the issue. And so once the issue is -- is handled, they will be fully onboard with that so I wouldn't expect any delay from that standpoint. Number 2, in terms of the owners, they each have their own replacement power issues. So they -- for whatever output they're not getting from unit one, they're responsible for their own replacement costs. We don't go out to the market and replace it for them.

I understand. But do they have any -- any way, any recourse back to APS for the -- the circumstances that are causing surrounding this outage?

I would give you my engineering definition of that and the answer would be no.

Okay.

Your next question comes from the line of [Faith Clause] from Banc of America.

Good afternoon. Couple questions. First, I did listen to the ACC meetings for two days. And it -- it -- I heard you say repetitively that it was your understanding that given communication with S&P that you would require the interim rate release to maintain investment grade ratings. Is that your -- is that your premise?

Faith, Don Brandt, yeah, all else being equal, we need to remedy the situation we're in. And the interim rate relief that we've applied for is -- is the potentially most timely vehicle to get meaningful improvement in our credit metrics.

Well, you know, given the procedural schedule for the base rate case, you're not looking at -- at the earliest you're looking at first quarter and potentially giving hearings delays adding -- tacking on additional days into the second quarter of '07, so is it your understanding from your communication with S&P that they require some form of interim rate relief to maintain ratings?

Maybe I wasn't clear. Yeah. My -- answer to that's yes.

Okay.

And that's the -- the interim emergency rate application which we are expecting a substantially shorter time frame on, as opposed to the general rate case when Jack was talking about schedule earlier slipping into the first half of '07.

Now I had in my notes when you were talking about the ALJ setting the procedural schedule that hearings began on April 20th but then in Q and A you said March. Is it March 20th?

It's March 20th.

It's March 20th.

Okay. And then regarding the $300 million parent company debt maturity in April, said you're considering a number of options. Are you more likely to bring a private placement or something outside of the public market?

It's probably a little too early to call that. But that's one of the alternatives we're giving serious consideration too.

Okay. So it's unlikely to be a public offering?

Well, no. I -- you know, privates, one we're looking at and public -- public's the other one. We really haven't called that one yet. In the next three to four weeks we'll make that decision.

As far as Palo Verde and the -- operating it at low capacity until you can come up with the -- first of all its my understanding that you are going to take it down for a permanent fix, 18 months from now during the re -- the scheduled refueling outage. How will you fix it and what's the timing on an interim fix before you hit summer peak.

I guess the -- let me go back to the first part of your statement, to the extent that we -- when we have our normal refueling outage, and we put at that - put in a permanent fix, where we are right now, is looking at some interim solutions which have been proven to be of value elsewhere and our hope would be sometime in the latter part, middle -- middle to latter part of this month, those fixes would be in place and see what happens. We are always cognizant of the summertime issue and so in parallel with all this, we're also doing engineering on a permanent fix, only doing engineering right now, though.

So you're looking at an interim fix by the middle to the end of next month.

This month.

This month. Okay. And -- and what happened when you took it down and discovered that the fixes that you had come up with hadn't worked? I mean, how -- you couldn't do it quickly. I mean, I'm wondering what are your engineers coming up with that they can implement quickly on an interim basis? That's different than what you had stated as alternatives when you took it down last time.

I might add to start off with its not just our engineers; we've brought in -- we've brought in some other -- say, engineering brains to look at all these situations because this is not something that's common throughout.

Um-hum.

Even from the beginning we've been looking at several, can I say, interim fixes, and so it's not like we had an interim fix and then didn't have one. We have several we're looking at and we're engineering and as you stated, the first one we put on didn't do what we wanted it to do, so we're now we're in the process of doing another kind of fix.

Okay. Thank you very much.

Your next question comes from the line of [Danielle Fife] with [Dalman Rose].

Oh, hi, I just had a couple more questions, again, [inaudible] but most of the other ones have been answered. As far as each unit, do you compute the capacity factor for each unit, and what are your best assumptions for this year, if it is possible?

I -- Danielle, I don't have the capa-- you're talking about the Palo Verde?

Yes.

Yeah, I don't have the --

The estimates.

The capacity factor by unit sitting here in front of me.

Okay.

But our assumption for the year would be that Palo Verde would get back to normal operating cycles. In other words, a -- an outing -- refueling outing -- outage in the spring and a refueling outage in the fall, and the plants would operate in between those outages at -- at high capacity factors but I don't have those off the top of my head.

Um-hum. So you anticipate -- you do not anticipate the same numbers as the one you got in '05.

No, we do not. And we certainly do not.

Okay. When you say "normal" I don't know what normal is. I mean, normal is in the 80s?

In past our normal has been a range from the very high 80s to the very low 90s.

Okay. And you think that it's achievable in -- in '06.

Danielle, we don't have a steam generator replacement planned for 2006.

Right.

As -- as we described to you, that's a -- that's a 75 to 80-day outage so we have two normal fuel cycles, one in the spring and one in the fall for units two and three.

I see.

So when you consider those.

That's on the positive side, yes. Okay. Great. So -- so sorry. Thank you very much.

You bet.

[OPERATOR INSTRUCTIONS]

Any other questions?

Yes, sir, I do apologize, you have a question from the line of Reza Hatefi with Zimmer Lucas Partners.

Good afternoon, how are you guys?

Good. How are you?

Good. Just one question, I guess since unit one does not have a refueling outage this year scheduled, I was wondering, I heard on a different call with one of the co--- other co-owners of unit one that to fix it, it would need to be -- it could potentially be done during an outage but of course if there's no outage is it possible, I guess, that maybe it will be taken down for the 35 or 40 days, sometime during the year just to finally finish it off and fix the problems?

Reza, that's -- that's too early to make that determination.

Okay. Great. Thank you.

At this time there are no further questions.

Well, I would just conclude by thanking you for your time. We -- we know this is a very busy time for you, and we appreciate the opportunity to -- to brief you on the status of our company and all the things that we're doing, and if you have any further questions, please don't hesitate to call Becky or Lisa. Thank you very much.

This concludes today's conference call. You may now disconnect.