Pinnacle West Capital Corp (PNW) 2003 Q4 法說會逐字稿

At this time I would like to welcome everyone to the Pinnacle West earnings conference call. (OPERATOR INSTRUCTIONS) Thank you. Ms. Hickman, you may begin your conference.

I'd like to thank everyone for participating in this conference call for our webcast to review our 2003 earnings and recent developments.

This call is being webcast simultaneously on our website, www.pinnaclewest.com, and a replay will be available on the website for the next 30 days. A replay of the conference call will also be available through February 5th by calling 800-642-1687 and entering access code 4861194.

This morning I have with me Bill Post, our Chairman and CEO; Jack Davis, who is our President and Chief Operating Officer and also President and CEO of Arizona Public Service; and Don Brandt, CFO of both Pinnacle West and APS.

Here's an outline of our call's topics -- Bill is going to provide an overview of the year; then Don will discuss the primary earnings variances and other financial topics; after that, Jack will update you on the status of regulatory developments and some of our operational results; and finally, Bill will wrap up with our financial outlook and a strategic summary. Before I turn the call over to our speakers I need to cover a few details with you.

First, our website contains extensive supplemental information on earnings variances and quarterly operating statistics. To help you easily navigate all the new information posted today, we have a quick reference menu on the website for the current quarter in the quarterly statistics section under investor information. The website also includes comparative quarterly information back to 1999 for your detailed analysis later.

Second, please note that all of our references today to per-share amounts will be after income taxes and based on diluted shares.

Third, our comments this morning will include certain non-GAAP financial measures, as defined under SEC Regulation G. A reconciliation of the non-GAAP financial measures to the relevant GAAP measures is available in our earnings release, which you can find on our website under Pinnacle West News or in the Form 8-K we filed this morning.

It is also my responsibility to advise you that this call will contain forward-looking statements based on current expectations, and the Company assumes no obligation 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 2003 Form 10-Q which identifies some important factors that could cause actual results to differ materially from those contained in our forward-looking statements.

Next, in order to allow more people to ask questions, I would like to ask each of you to limit yourself to two questions when it is your turn. If you have more questions, you may ask after another person has had a chance to ask a question.

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 will turn the call over to Bill Post.

I also like to thank everyone for taking your time to be with us today.

Our operational performance was strong in 2003. It was marked by a number of accomplishments, as well as a number of challenges, and I would like to highlight a few of those with you this morning.

First, growth in our service territory remains remarkable. Our peak load grew nine percent and our customer growth continues at a pace about three times the national average. We met the challenges of one of the hottest years on record by focusing on reliability and top tier customer service.

We reached several regulatory milestones -- the ACC approved a $500 million financing application related to the Pinnacle West energy generating plant; we completed our commitment to reduce our retail customers' prices by some 16 percent over a ten year period; and we filed our first general rate case since 1991, as required by the 1999 settlement agreement to cover increases in costs for providing reliable service to our customers.

Palo Verde marked its 12th straight year as the largest power producer of any kind in United States. We also successfully completed the replacement of the steam generators at Unit 2, as planned and on-time. It was the first the steam generator replacement at the site and the Palo Verde employees were exemplary in every phase from its planning to completion.

We placed (ph) West Phoenix Unit 5 and a new 500,000 volt transmission line of service, providing more resources to meet our customers' growing needs.

We also faced challenges, as the western wholesale energy markets deteriorated significantly. And we also experienced unplanned plant outages.

SunCor solidly completed the first year of its three-year accelerated asset sales program with earnings of $56 million. And we increased our dividend for the 10th consecutive year.

Don will give you the details on our financial results for the fourth quarter and for the year. Then Jack will update you on the pending regulatory issues and details on our operations. Don?

Thanks Bill. This morning I will address our 2004 financial results and the primary earnings variances for the fourth quarter and the year 2004 -- excuse me, 2003.

In my comments whenever I refer to amounts in millions of dollars, I will be referring to amounts after income taxes, unless I say otherwise. After this call, Becky and Lisa would be pleased to assist you in navigating the detail available on our website.

I plan to spend most of my time to talking about the year as a whole. However, I would like to give you a quick recap of our fourth quarter results as well.

We reported net income of $49 million or 54 cents per share for the fourth quarter 2003, an increase of 130 million or $1.49 per share compared to the fourth quarter of 2002. The quarterly comparison was affected in large part by a change in accounting and several onetime items that were booked in the fourth quarter a year ago.

The accounting change related to our adoption in 2002 of a new accounting standard for trading activities. The cumulative effect of adopting this change was $66 million or 77 cents per share.

The onetime items totaled about $60 million or 70 cents per share in the fourth quarter of 2002. They consisted of -- one, the write-off of Red Hawk Units 3 and 4 of $30 million or 35 cents a share; two, the NAC related charges of 23 million or 27 cents per share; and three, a voluntary severance charge of 7 million or 8 cents per share.

The fourth quarter of 2003 benefited from income tax credits of 12 cents per share.

Ongoing earnings for the fourth quarter of 2003, excluding these unusual items, reflected a decrease of $6 million.

SunCor contributed earnings of 39 million or 43 cents per share in the fourth quarter, representing an increase of 29 million or 33 cents per share.

Other noteworthy factors favorably affecting the quarter were hotter weather of 9 cents per share, retail customer growth of 5 cents per share, offset by increased purchase power and fuel costs of 23 cents per share, new power plant costs of 14 cents per share, lower margins in our marketing and trading segment of 12 cents per share and higher replacement power costs for plant outages of 8 cents per share.

Turning to the factors affecting our consolidated results for 2003, we reported net income of 241 million or $2.63 cents per share for the year, an increase of 92 million or 87 cents per share compared to 2002. Consistent with my earlier comments regarding 2002's fourth quarter, 2002 annual earnings were adversely affected by the change in accounting and the same onetime items, and 2003 benefited from income tax credits. Excluding these unusual items, our 2003 ongoing earnings were down $1.12 per share.

SunCor solidly met its 2003 earnings targets through the accelerated asset sales program. SunCor's earnings for the year increased $37 million or 38 cents per share. The key factors underlying our earnings include the benefits of customer growth at 32 cents per share, regulatory asset amortization of 19 cents per share and a favorable weather factor of 9 cents per share. Excluding the effects of weather, our retail sales growth was 4.2 percent for the year, representing a significant improvement over last year's growth of 3 percent.

The trends for the second half of 2003 picked up significantly, with retail sales growth of 5.1 percent as compared to 3.1 percent in the first half of 2003. We expect this improved trend to continue into 2004.

Also, APS's return to the more traditional AFUDC method of capitalizing interest and equity costs associated with regulated construction projects added 12 cents per share.

We recorded income tax credits related to prior years of $17 million or 19 cents per share for 2003. As a reminder, our October 2003 guidance included 15 cents per share of tax credits.

These positive factors were somewhat offset by the following items. Our marketing and trading segment gross margin was down sharply, declining 56 cents per share from 79 million to 28 million. As shown in the operating statistics on our website, pre-tax gross margin for marketing and trading was $47 million for the year compared with a margin of 132 million in 2002. The primary reason for the decline is a reduction in marked-to-market gains of 38 cents per share and lower realized margins of 21 cents per share. As we mentioned in our last earnings conference call, the decline in marked-to-market gains is largely related to less liquidity, reduced volatility and fewer credit worthy counterparties in 2003 compared to the market environment of the year ago. As an indication of this market environment, our new deal volume for future delivery was down 65 percent from a year ago.

Higher prices for hedged gas and purchased power negatively affected the annual comparison by approximately $36 million or 39 cents per share. New power plant costs, net of associated fuel savings, of 33 cents a share, a retail price reduction of 1.5 percent or 18 cents per share and higher pension and other benefit costs of 18 cents per share also negatively affected earnings.

Finally, replacement power costs related to unplanned outages decreased our earnings $28 million or 31 cents per share. As previously disclosed, the majority of these costs were related to an extended outage at our Cholla plant.

Now turning to SunCor in more detail, SunCor reported net income of 56 million for the year. The favorable results were primarily driven by the sale of three properties -- a water utility in the first quarter of the year, and a commercial property and an equity interest in a residential development at Litchfield Park, a suburb of West Phoenix, in the fourth quarter. We expect SunCor's earnings to remain strong through 2005, consistent with their three-year accelerated asset sales program. As expected, 10 million or about 18 percent of SunCor's earnings were reported as income from discontinued operations. Importantly, SunCor achieved its target of distributing 100 million of cash to the parent in 2003.

Turning to our marketing and trading business, our marketing and trading business is predominantly a risk management tool related to our regulated business. Consistent with our previously disclosed plans, by mid-December of 2003 we had successfully hedged 75 percent of our 2004 natural gas and purchase power risk relative to price.

In response to market conditions in the fourth quarter on non-asset related commodity trading business was down-sized and essentially eliminated. On the other hand, we remain committed to our wholesale origination and APS Energy Services retail commodity businesses. Originating both wholesale and retail structured transactions has been consistently profitable, with very modest manageable risk attributes. However, due to current market conditions, consistent with our October guidance, we expect that 2004 contributions from newly originated wholesale structured transactions will be negligible.

Now I will turn to the credit rating agencies and our liquidity position.

In December we met with both Moody's and S&P to provide an update on our financial and regulatory situation. Our ratings remain unchanged with a stable outlook. As expected, the agencies are closely following the outcome of the rate case.

The parent company issued $165 million of two-year floating-rate notes in the fourth quarter. This issuance essentially pre-financed the repayment of $250 million of Pinnacle West notes coming due in February of '04. These new notes are callable at par in November 2004.

The parent company also successfully completed a $150 million bank revolver in the fourth quarter. As a reminder, the $125 million interim liquidity line with APS was never drawn on and expired in December of last year. The parent now has 275 million in bank lines, which back-stops our $250 million commercial paper program and provides general liquidity.

Both Pinnacle West and APS ended 2003 in an invested position -- the parent at about $80 million and APS at about $110 million. Both companies' liquidity positions are solid.

I will now turn the call over to Jack.

Thank you Don and good morning everyone. Today I'm going to give you a brief update on regulatory developments with the Arizona Corporation Commission and a summary of our recent operations. I will start first with the regulatory front.

In November the ACC approved several rate adjustment mechanisms we had requested for implementation through APS's pending general rate case. Therefore, the adjustment mechanisms will not affect customers' rates until there is a final order in the rate case.

As currently approved, the most significant of the adjustment mechanisms will allow recovery of changes in purchased power costs, but not changes in fuel costs. The other adjustment mechanisms that were authorized in our 1997 include items such as costs associated with compliance with the ACC's (indiscernible) competition rules.

The ACC reserves the right to amend any of the adjustment mechanisms during the rate case. As a result, we intend to request reconsideration of the fuel adjustment mechanisms during the rate case.

APS's rate case is by far our most prominent regulatory activity. We filed the case in June. I won't spend time in my prepared remarks reiterating the major provisions of our filing, which most of you already know and which are described in our third quarter 10-Q. Here is a summary of the process as has transpired so far, and the upcoming key dates.

A procedural schedule for the rate case was established in August and modified slightly earlier this month. Since August we have been in the discovery phase of the case. We responded to numerous data requests from the ACC staff and interveners as they have been preparing their initial direct testimony. That testimony should be filed next Tuesday, February 3rd. After that discovery will continue in several rounds and rebuttal testimony will be filed by us, staff and the interveners. The final testimony will be filed April 16th and the hearing is scheduled to begin on April 26th. Based on the procedural schedule and the existing ACC regulations, we expect that the ACC will be able to make a decision on the rate case by the end of this year.

We know many of you will be interested in the staffs' and interveners' initial reaction to our rate case and those reactions will be reflected in the testimony that we will file next week. We expect our testimony to be voluminous. In most cases -- in every case it must address all aspects of the case, from revenue requirements and the rate return to the design -- to the rate design by customer class.

Now I would like to talk about the RFP process we have underway. We issued a request for proposals in December for a long-term power supply resource at the beginning -- in mid-2006 or 2007. The request was for at least 500 megawatts of long-term power supply resources with a minimum bid size of 25 megawatts. Our preferences are to buy existing generating plants or enter into purchase power contracts for at least 20 years that are backed by specific generating units.

Although one of the major provisions of our rate case is treatment of the power plants built by Pinnacle West Energy to serve our retail customer, our projections show that in addition to those plants alone -- our projections show that those plants alone will not be enough to cover our needs to reliably serve our customers in the future. Hence, we have a growing-short position. Therefore, we decided to issue and RFP to determine whether long-term resources might be available for us to buy economically to reliably serve our customers.

For example, our short position grows to more than 1,000 megawatts by 2006. We believe it's prudent to prepare now and we believe some plants in our region may be sold in the not too distant future.

APS received responses to the RFP last week. As requested by the ACC, we filed a summary of the proposals with the Commission earlier this week. We also filed the summary and the 8-K yesterday.

Here's a brief summary of the bid results. We received thirteen proposals from nine bidders totaling approximately 6,800 megawatts. All of the proposals involved natural gas-fired generation resources with APS and its customers bearing fuel price risk in one form or another. None of the proposed purchase power agreements includes a fixed-price bid. APS has calculated to levelize (ph) prices in the proposals at a range of around $65 to $160 per megawatt hour over the lives of the proposed assets or purchase power agreements. Finally, I must emphasize that many factors could affect the final pricing on the proposals.

Because we have entered into confidentiality agreements with the bidders, I cannot give you any specifics beyond the summary we have filed. If you would like more information today, I suggest that you read the summary of the proposals that were filed with the 8-K yesterday.

An intervener in the rate case representing certain merchant generators filed a motion with the ACC in December related to the RFP. The intervener asked the ACC to delay the rate case hearing for four months to permit the results of the expanded RFP to be considered in the rate case or to bifurcate the rate case to separately consider issues regarding Pinnacle West Energy assets.

Three weeks ago in response to the intervener’s motion, the Administrative Law Judge who is presiding over the rate case modified the procedural schedule to extend it (indiscernible) days. The scheduled that I already described for the rate case is the revised schedule.

Finally, concluding my regulatory comments, on Tuesday the Arizona Court of Appeals issued its decision on in appeal an the ACC's electric competition rules that have been pending since early 2001. The appeal was filed by the ACC and other parties after a lower court ruled that the Commission's competition rules were unconstitutional and unlawful. As a result of the 1999 settlement, APS was not a party to this litigation.

It is a complex opinion that is almost 90 pages long, but based on our initial review the Court of Appeals' opinion invalidates certain aspects of the ACC's competition rules. In addition, it does not appear to have any negative implication to APS's rate case. It will most likely necessitate additional proceedings at the ACC. And further, we believe -- we will not be surprised if this decision was appealed by the ACC or another party in the case.

Now I would like to briefly review some of our operating activities. I will focus these comments on the fourth quarter operations.

As Bill, growth in our retail service territory continues to be enviable. Our customer growth continues to be about three times the national average. We focus on customer satisfaction and exceptional operational performance throughout our organizations to serve that growing customer base.

Our retail sales increased almost ten percent in the fourth quarter compared with the fourth quarter of 2002. Almost five percent of sales growth was driven by favorable weather and about five percent was driven by customer growth and increased usage by our customers.

Looking at our power plant performance, the capacity factor for nuclear plants was 72 percent during the fourth quarter compared to 87 percent for the whole year. The major factor that affected the nuclear operations was the planned refueling outage for Palo Verde Unit 2 during which we replaced the steam generators. The outage was our first steam generator replacement outage and it was completed successfully as planned.

Our coal plants operated at an average capacity factor of 74 percent during the fourth quarter.

As we disclosed, we experienced certain unplanned outages at our generating plants. The most significant of those outages was the Cholla 3 outage caused by a generator failure in August. We completed the outage in that plant in late November.

Red Hawks 1 and 2 each operated at a restricted output level about 37 days in October and November to correct an equipment designed effect that I discussed with you last quarter. The outage was requested by the equipment manufacturer.

Construction of our Silver Hawk plant in Southern Nevada is still on track for commercial operation beginning this summer.

As I said in the third quarter conference call, I'm confident that our generating unit management practices are solid. Our power plant employees successfully completed the outages whether they were planned or unplanned. Our power plant operations have resumed their excellent performance records since the outages were completed.

In addition to the activities at the Arizona Corporation Commission that I discussed earlier, we're actively participating in federal development such as RTO standard market design (ph) and energy legislation.

In summary, we are tenaciously working to maintain our exceptional customer service and operational performance and to constructively address regulatory issues at the state and federal levels.

That concludes my prepared remarks, and now I will return the call back over to Bill.

Our earnings guidance has not changed. Last October we provided you earnings guidance for 2003 and 2004 and for the foreseeable future beyond the decision in our pending rate case. Details on our guidance and the major underlying assumptions and sensitivities are described in the 8-K we filed on October 6th.

Overall, our rate case is clearly the most significant single factor affecting our outlook. We have a solid track record, but are working with our regulators toward constructive regulatory outcomes and we're intently working to achieve an outcome that will cover the costs of providing reliable service for our growing customer base and provide a fair return to our shareholders.

Besides the rate case there are many facets of our business on which our employees focus successfully everyday -- providing top tier customer service; maintaining or improving operational excellence; managing the risks of our business; controlling costs; and list goes on. I believe our customer growth of about three times the national average and the related potential for earnings and dividend growth are distinguishing characteristics of our company. We will endeavor to continue to capitalize on these advantages.

That concludes our prepared remarks and we would be happy to answer any of your questions.

(OPERATOR INSTRUCTIONS) Ted Hein (ph), Smith Barney.

Actually it is Greg Gordon. Obviously the numbers continue to be messy as we transition to a little more stable regulatory profile post the rate case, so let me ask you a forward-looking question, a little bit more in detail to the extent you can on the results of the RFP. You guys attempted to give us a flavor for what the all-in cost of the bid looked like, and I think you said it was $65 a megawatt hour to $160 a megawatt hour, making some assumptions and filling in the blanks on the bids that you got. When we look at the underlying cost of operating the plants that you are requesting to rate-base at the return that you're requesting, it would seem to me that your at or -- the cost of operating those plants, including that return, looks like it is at or below the price of the bids as you have described them. Is that a fair statement or is it more complicated than that?

I guess the one thing I've got to caution you on is the numbers included to you in my summary are levelized costs and the numbers that you're probably looking at in the rate case for our fee weight (ph) units are annual costs.

So the costs that you quoted in the 8-K were not sort of annualized twelve-month costs; they were just the costs for the periods in which they bid?

Yes. They were they were normal present worth levelized costs over the life of the asset or contract.

Thanks guys.

Paul Patterson, Glenrock Associates.

Does the FERC have to approve putting these plants back into the rate base? And is there any concern from some of the comments that have been coming out in some presentations and what have you at FERC with respect to market design and competition or concerns about competition about putting these plants back into rate base?

It is our belief that when we moved the Pinnacle Western Gas under Arizona Public Service that we would have to get FERC approval. It is a possibility. I should remind you that in terms of Pinnacle West energy assets, they have always been shown in any kind of market analysis we've done as being included within Arizona Public Service. The second thing I would like to point out, which I think makes us different than others, is that it's the results of the Track A decision that have us in a bifurcated mode here. All we're trying to do is get our (indiscernible) plants back into the long haul together.

Okay, so just a follow-up on that, in other words you don't believe that there would be -- that the FERC would hold this up it all?

No, all I'm saying is we think we're different than the other cases that are in front of the FERC. These plants were never built to be in the wholesale market and the only reason they're sitting out by themselves today is because the track B decision actually bifurcated them from the APS generating plants.

They are also owned by you guys as well, which I do not know that would change in terms of market power if it was in rate base or not, per se. But I guess that's another issue. Okay, that's about it.

Tom O'Neill, Lehman Brothers.

A question on the PWEC (ph) segment or a couple of questions. For the second half of '03, while you're operating under Track B it looks like you lost $9 million. And I guess maybe you can just help us think of it on an annualized basis; is that a number that we can in any way double or perhaps a little bit worse than double for a full year impact of what Track B contract would look like?

Tom, I think that certainly with respect to the second half of 2003 you had an indication of what that particular half looked like with the PWEC units under the Track B contracts to APS in the fourth quarter and the PWEC contracts selling into the market in the fourth quarter. But I think if you think about those timeframes, they're probably somewhat indicative for the near-term as long as (technical difficulty) conditions are the way they are. I wouldn't necessarily just double them and say that that's 2004. You also need to remember that Silver Hawk is going to come on line in mid-'04.

I'd be cognizant of the fact if you look at the third and fourth quarter that's not 50 percent of our year. As you know, because of (multiple speakers) the summer, you've got much more significant impacts in the third and fourth quarter than you do in the first and the second.

Right, which might make it a little bit worse than annualizing it.

Yes, if you just double it.

Second question on the RFP. Could you just talk about the gas price assumption you used in deriving those prices that you talked about and how it compares to the gas price assumption you made in your rate case filing?

I don't recall off the top of my head the number we used in our rate case filing, but it is in the rate case file, so you will know what that is. And I think the one that we used here for the natural gas would be similar to that number.

Okay. One last question, if I could. Do you have the net equity at SunCor at year-end 2003?

We don't have the balance sheets all audited yet.

Thank you.

Jason West, Deutsche Bank.

One question on the tax gain you guys recorded in '03; how was that allocated to the segments on a net income basis?

That's a good one. I don't think we've got that right at our fingertips here, but if you want to try Becky after the call, we can get that information put together.

I can follow-up with you.

I noticed you guys recorded some income from El Dorado this year, I believe. Is that a recurring sort of number? How should we think about El Dorado going forward?

Yes, that's a recurring number.

Thanks.

John Hanson (ph), (indiscernible).

I've got a question. I know 2003 wasn't all it could have been because of some of the outages you had at the generating facilities. What's the outlook for outages look like here for 2004?

The outages for 2004, obviously we don't plan any large unplanned outages like we had in 2003. And I should remind you that the one large one we had at Cholla 3 was -- Cholla 3 is back online and operating fine. Our outage scheduled for 2004 is similar to what it was in 2003, except for we had an extended planned outage in 2003 for the replacement of the steam generators at Palo Verde 2. We do not have a steam generator replacement plan for 2004.

So that means you have quite a bit more of that base load generation available?

Yes.

If I could add to that, we do plan to replace the steam generators in Palo Verde's Units 1 and 3 in 2005 and 2007.

You also did an up rate on Palo Verde, is that right?

What we did is we replaced the steam generators in Unit 2 and the low pressure turbine, and as a result of that the unit will get about 100 megawatts additional generation, and of course we will get 29.1 percent of that.

You will have some or megawatts to sell with -- what kind of variable costs would go with that?

It would be the same as the variable costs that would be with the base.

There's no additional cost associated with that other than the fuel --?

(multiple speakers) additional fuel cost, of course.

Great, so that's a fairly low number. Coming back to the RFP, we talked about how those units would compare in the rate filing. Is there anything else about the aspects of those in terms -- of you mentioned some things about credit ratings and all that. How might the Commission view those kind of proposals versus what you've got with your in-house generation?

You're asking me to speculate on that and I can't do that.

All right, sir. Thank you.

Danielle Seitz (ph), Metcore Financial.

I just was wondering if the dates of the final decision on the rate case are certain at this point or is it still very not quite sure?

For some reason you kind of broke up right at the beginning.

I was just wondering -- the rate case -- the final decision on the rate case, is there now a more certain date or is it still uncertain?

We believe, based upon the decision and the most recent decision from the Commission where they dealt with the intervener’s request to delay the rate case that Jack talked about, we do believe it's going to be possible for the commission to deal with this before the end of the year.

Okay. And the degree -- I understand it's qualitative, but it's definitely more sure that it was a few months ago, I guess?

I think as we move more towards the testimony next week and then the hearing in April, you're right; the certainty for that increases. But I think the fact that the Commission looked at the whole schedule and put together the schedule just three weeks ago to deal with this, I think it does start to increase the certainty towards that. Our sense is that it's going to be possible for the Commission to make a decision before the end of the year.

How does the election play in that timing? Obviously would it be easier after the elections?

We have a five-member elected Commission in Arizona, and because of some of the changes dealing with term limits and some individual commissioner issues in the last year or so we have four of those five commissioners that are up for reelection in November of this year. As you look at the schedule and you lay out the schedule against the procedural requirements that the Commission has, our sense is that we will have a hearing, we probably get a proposed order somewhere around the fall time frame and then a decision towards the end of the year.

Thanks a lot.

Teresa Ho, Solomon Brothers Asset Management.

I was hoping that you could elaborate on the bid results that you just mentioned on be search and proposal as it relates to the first auction that you have for Track B. I seem to recall in the first auction I think you had made some comments that you were somehow surprised with a few bids and also the credit-worthy nature of those bids. Could you sort of compare the two results?

I guess the best way to do this is Tract B results were what they were and we were surprised at the number of people who did not bid.

What I would like to point out on the recent RFP is, should I say, the quality of the 1,600 megawatts that we mentioned. In our summary, on page 2 of the summary we kind of describe the 1,600 megawatts. I want to make it clear that not all that is steel (ph) in the ground. The 1,600 megawatts is a combination of power plants that are presently built, power plants that are under construction, purchase power agreements and in some cases just development rights or raw land from undeveloped projects. In fact, one of them is actually a sale from an unidentified asset.

As I think we mentioned in our summary, several of the parties in the bid process are not credit-worthy parties.

Could you elaborate? I'm sorry, I don't have the summary in front of me. What portion of the megawatts actually are not credit-worthy?

We didn't break down the number of megawatts that was or were not credit-worthy.

Maybe I'll just take the rest of it off-line in terms of the summary. Thank you.

At this time there are no further questions. I would like to turn the call back over to Ms. Hickman.

Thank you all very much. We know it's a very busy time. And as we have said, our company remains very focused on the rate proceeding that we have in front of us. And we continue to aggressively provide reliable service to our customers and our focus is going to be, and continue to be, aggressively on this rate case. Thank you very much. We appreciate your time.

Thank you everyone.

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