Pinnacle West Capital Corp (PNW) 2002 Q3 法說會逐字稿

Welcome to the Pinnacle West Ital. Corporation earnings conference call. During the presentation, all participants will be in listen-only made. Afterwards, we will conduct a question-and-answer session. At that time, if you have a question, press one, followed by four on your telephone. This conference is being recorded, Monday October 28 of 2002. I would like to turn the conference over to Rebecca Hickman, Director of Investor Relations. Please go ahead, ma'am.

Thank you. Good morning and thank you for participating in our conference call or webcast to review third quarter results and recent developments. This call is being webcast simultaneously on our website, www.pinnaclewest.com, and replay will be available on the website for the next 30 days. Replay of the conference call will also be available through noon on November 4, by calling 800-633-8284 and entering code 20942020. I have with me, Bill Post, Chairman and CEO, Jack Davis, who is President and President and CEO of Arizona Public Services and Mike Palmeri.

Bill will give a brief overview of three announcements we made in the last weeks. Mike will review the variances for the quarter after which Jack will update the status of regulatory developments. Bill will wrap up with financial outlook and summary. Before I turn over to the speakers, I need to cover details with you. The investor section of the website contains information on earnings variances and operating statistics for years 1999 through 2001 and through the third quarter of 2002. The information was also filed with the SEC as 8-K this morning. To help you quickly navigate this extensive information to understand our quarterly results here are a few tips. Comparisons of the operating statistics for the quarterly year-to-date and 12-month period ended September 30 in 2002 and 2001 are contained in PDF file and summary tab of the XL file. Detailed earnings information are also included on the website. There is a lot of other information on the website to help you with projections and further analysis. You will find this information helpful in understanding our results.

Second, please note all references to per share amounts will be after-income taxes. Next, is my responsibility to advise you this call will contain forward-looking statements based on current expectations. 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 forward-looking statements. Please refer to our 2001 annual report on form 10-K and 2002 form 10-Q, which identifies some important factors that could cause actual results to differ materially from those contained in our forward-looking statements. Finally, this call and the webcast are property of Pinnacle West Capital and copying, transcription, retransmission or rebroadcast of the call without Pinnacle West's written consent is prohibited. Over to Bill Post.

Thank you. I would like to thank you for taking time to join us today. Subsequent to and consistent the 8-K. we released 10 days ago and discussed on October 18, we have made three recent announcements. First, we increased common dividend. Second announced corporate realignment and this morning we announced third quarter earnings. I would like to review the three items and Mike and Jack will discuss the detailed earnings variances and recent regulatory developments and I will close with financial outlooks and other comments. Last week our Board approved common dividend increase of 10 cents per share, bringing total indicated annual due to $1.70 per share. I believe our dividend is one of the strong investment characteristics of our company and we intend to continue to grow our dividends. Future growth will be dependent on a number of factors, including pay-out ratio trends, free cash flow and financial market conditions.

The second announcement made last week was corporate realignment. The new structure separates regulated operations from Pinnacle West units. Jack Davis will be responsible for utility operations at APS and Bill Stewart will be responsible for unregulated activities, including power marketing and trading and energy services. This structure reflects regulatory environment and tomorrow's wholesale markets while positioning the proven leadership and expertise of our company. Now, I would like to review quarterly earnings. Our reported earnings for third quarter were $1.19 per share compare wide $1.77 a year ago, decrease of 58 cents per share.

Two items included in our reported earnings affect the comparison of quarterly ongoing earnings power. First, this year's result include severance charge of $25 million or 18 cents per share, related to the voluntary workforce reduction we announced in July. Second, last year's results reflected after-tax loss of $12 million or 14 cents a share, related to cumulative effect of accounting change required by SFAS 133. We believe most analysts exclude those two item necessary comparing operating earnings for the quarter. On that basis, operating earnings for third quarter were $1.38, compare wide $1.99 a year ago, decrease of 54 cents per share. The decrease in earnings for the third quarter was expected and affected by several major factors we have been discussing during the last year. The major factor that is reduced earnings were lower contributions, severance cost related to voluntary workforce reduction plan announced earlier this year and higher costs per purchase power and fuel. Also, as expected, these reductions were partially offset by absence of high-rate reliability cost incur indeed summer of 2001. I would like to review the major factors with you.

We stated a year ago we did not expect to be able to repeat third quarter 2001 results because of the collapse of the western wholesale power market. Those changes have been evident throughout the last year as prices have fallen dramatically and participants have exited the market. Results for power marketing and trading activities were down. These activities contributed $44 million of pre-tax gross margin or about 31 cents a share before operating expenses during the third quarter. Results are down 59 percent, compare wide 108 million a year ago because of the state of western wholesale power markets. Our marketing and trading group continues to deliver results through creativity and execution within the strict risk management parameters that we have established. As previously announced, we expect to reduce workforce this year up to 8 percent with associate of up front cost of $37 million pre-tax, or 26 cents a share.

In the third quarter we reported severance charge of $25 million pre-tax or 18 cents per share for the program and we expect to record additional charges later this year as the workforce reduction and finalized. We continue to expect our cost management program to produce annual savings and pre-tax operating expenses of approximately $30 million beginning in 2003. Our cost for purchase power and gnarl gas were higher in the quarterly comparison by $24 million or 17 cents a share. These costs were higher than net hedged costs for last year's quarter because hedges for reportive periods were put in place at different times. Cost increases include the effect of required mark to market adjustments for certain natural gas and power hedges for delivery in 2003 and 2004. As forward-market prices continue to be lower than our committed cost. You may recall that we incurred significant cost in 2001 for summer energy reliability for retail customers in Arizona. Costs were down $39 million pre-tax or 28 cents a share in the third quarter compared with a year ago. Reduction reflects $15 million of replacement power cost due to fewer unplanned outages and lower market prices and $24 million of lower operations and maintenance expenses related to generation reliability, plant outages and maintenance costs, primarily in the form of portable generators leased in summer of 2001. Obviously beyond those four major factors there were a number of other factors affecting the quarter. Mike Palmeri will review the factors with you now.

Thanks. I will focus my prepared comments on the key earnings variances for third quarter. I would be happy to answer questions regarding the quarter, nine months and 12 months ended during the Q and A session, as well. I would like to clarify up front any time I refer to per share effects those amounts represent diluted earnings per share after taxes. Quarterly results. As Bill stated net income for the third quarter of 2002 was $100.9 million or $1.19 per share. This compares unfavorably with $150.1 million or $1.77 a share for

the third quarter of last year. The major factors impacting the variances in the quarterly gross margin comparison can be broken into two categories, electric retail business segment and the power marketing and trading segment business, including APS Energy Services, our competitive retail unit -- including competitive retail unit. The retail segment representing more traditional snapshot of regulated retail and behole (ph) wholesale business including wires and generation activity. The explanations are part of the 8-K filing this morning and include additional information to help you better understand our regulated and unregulated businesses. Total pre-tax electricity gross margin or revenue net of purchase power and fuel costs was $506 million versus $582 million in third quarter of last year. The power marketing and trading segment contributed $64 million of the total reduction in gross margin of $76 million, due primarily to lower prices in wholesale power market.

Retail segment gross margin was down $12 million, due to several factors, including mild weather of 10 million dollars or 7 cents, retail price reductions of $9 million or 6 cents, lower hedge management margins partially offset by lower purchase power and fuel costs due to lower spot market prices of $14 million or 10 cents. The change in mark to market for hedged natural gas and purchase power cost for future period deliveries of $10 million or 7 cents and finally, other miscellaneous factors that approximated 6 million or 4 cents. Those gross margin decreases were partially offset by higher retail sales volumes due to customer growth and higher usage excluding weather effects of $22 million or 15 cents. Lower replacement power costs due to lower market prices and fewer unplanned outages of $15 million or 11 cents. Let me explain the decrease in contributions from our power marketing and trading business segment in more detail. As you can see on page 5 of the summary section of the quarterly statistics, the total gross margin for the power marketing and trading business was $44 million or 31 cents a share this quarter, compare wide $108 million or 76 cents per share a year ago. The decline of $64 million or 45 cents a share is primarily linked with reduced opportunities in other power, marketing and trading at the parent of 44 million or 31 cents per share and at Arizona Public Service of $32 million or 22 cents per share. In general, the total variance can be attributed to lower mark to market gains for future period deliveries. This change was expected and later reduced profit opportunities resulting from lower price volatility and reduced power party liquidity.

Before I continue discussing other earnings drivers, I would like to point out customer growth in third quarter was rate of 3.1 percent. As previously indicated, customer growth as slowed compared to long-running growth rates. However, 3.1 percent is strong is represents three times the national average. Customer growth, combine wide usage grew at 5 percent for the quarter. Going forward, we expect customer growth to continue at about 3.1 to 3.2 percent for 2002 and to begin to increase to 3 and-a-half to 4 percent for 2003 and 2004.

We currently estimate retail kilowatt hour sales growth of 3 and-a-half to 5 and-a-half percent for 2002 to 2004. For the quarter, our earnings were impacted by the following items: operations in maintenance expenses were lower by $6 million pretax or 4 cents per share due to completion of the 2001 summer reliability program, which resulted in higher expenses in the third quarter of last year of $24 million pre-tax or 17 cents per share and lower miscellaneous costs. The savings were partially offset by cost associated with the voluntary severance plan of about $25 million or 18 cents per share.

Interest expense was higher at about $8 million or 6 cents per share due to combination of higher balances at the parent and Arizona Public Service, as well as lower capitalized interest. El Dorado reported losses of $13 million in the current period, or 9 cents per share. The loss was related to El Dorado not investment. Nac (ph) contracts for nuclear storage and transportation. This loss was related primarily to two specific underwater contracts through June of 2002. El Dorado accounted for its investment in NAC through the equity method, which acquired earnings of losses in the Other income and expense line. Beginning in the third quarter of this year, El Dorado assumed controlling interest in NAC and began to fully consolidate NAC's statements. El Dorado has stepped in to stabilize the situation and we do not anticipate significant operating losses at NAC beyond the current year.

Finally, SunCor's earnings contribution was down $3 million or 4 cents per share. We expect SunCor to contribute earnings in the range of $20 million in 2002. Thereafter, we exaccelerated asset sales at SunCor to double earnings contribution for period 2003 through 2005. This concludes my formal remarks for the third quarter earnings comparison. For further information and analysis, details of earnings and variances for the three, nine and 12 month periods ended September 30 are available at our website along with other information. I would turn over to Jack Davis.

Thank you, Mike. I am going to provide a brief update on regulatory developments with the Arizona Corporation commission. There are four major issues of note. The recent track A order, track B proceedings and pending financial implication and general rate case we filed in 2003. On August 27, commission voted on the track A order with reversed direction from competition rules adopted in 1999. Track a order recognized significant risks related to allowing -- existing western wholesale market and possible effects on reliable cost-effective service free customers. It stopped transfer of APS generation assets to unregulated affiliate and changed requirements for power purchase. It is in consistence with settlement approved by the commission. The track A decision essentially defined APS as vertically integrated utility with 4000 megawatts of long-term purchase contracts.

It also established for the time being 1800 megawatts of power plants we built in Arizona under our unregulated affiliate Pinnacle West Energy, will be required to (inaudible) to provide energy to ACS. We asked the ACC to reconsider the track A decision as required first step in the appeal process. On October 17, the commission denied reconsideration. We expect to pursue a remedy for the damages we have and expect to have as a result of the commission reversal of their policy. We currently envision pursuing derivatives through the courts and 2003 general rate case.

Let me turn to track B. Track B is the portion of the ACC generic proceedings on electric restructuring addressing procurement requirements for purchase power. Since early summer ACC staff conducted series of workshops involving APS merchant generators and interested parties. Under the proposal, we believe APS will be required to competitive bid about 1500 megawatts of energy on peak. The solicitation is to commence by March 1, 2003. Most decisions would be at APS's discretion, for example the form of procurement process, whether auction or rfp (ph). The products should be block or slice the system and contract duration. The staff also proposes that Pinnacle West Energy would be able to bid. As proposed by staff, track B would involve staff and independent monitor and cost recovery would be determined later. In addition to the staff workshop process, the commission will conduct hearings to make final determination on the track B proceedings. The hearing is scheduled to begin on November 21. Between now and then, APS will file energy requirements and the parties will follow testimony.

The next issue is our pending financial application. By the way of background, under the ACC competition rules and settlement agreement, both approved by the commission in 1999, we were to move APS generation assets to an unregulated affiliate Pinnacle West Energy. We obtained investment grade ratings for Pinnacle West. The track A decision to reverse course on asset transfer left open among other things financial status of unregulated generation assets. Shareholders paid through 234 million write-off and other items for structure that would permit investment grade financing for unregulated generation. The financing application in part is alternative form to financial structure and would provide a financial platform equivalent to investment grade for unregulated assets.

We are asking the commission to allow us to maintain credit worthiness resulting from the settlement agreement. We have asked the commission to approve APS issuing up to $500 million in debt and lending proceeds to Pinnacle West Energy with the parent company. APS guaranteeing $500 million to Pinnacle West Energy or combination of the two not to exceed $500 million in the aggregate.

The lone and guarantee would be use to refinance portion of the bridge debt the parent company incur to fund Pinnacle West Energy construction of new generation to serve retail customers in Arizona. The commissioners expressed interest in dealing with the manner in a timely manner. A hearing will begin January 8, 2003. Under 1999 settlement agreement we are required to file by June 30 of this year and will make the filing in the second quarter. Through this filing, we expect to recover costs incurred and comply with the ACC electric competition rules and our 1999 settlement agreement and result of the decision to reverse course on asset transfer. The decision regarding existing unregulated generation in Arizona could be addressed, as well. We will update the cost of service and rate design.

We have assumed the decision on the 2003 rate case would be made by ACC by end of 2004. Finally, I would like to review upcoming election for the Arizona commission. There are currently three elected commissioners, all republicans and one of existing seats is up for election in November. Additionally, two new commission seats will also be filled. These new seats were created two years ago through ballot proposition. Thus, in January, ACC will expand to a five-member commission. Six candidates are running for these three seats. The candidates include the incumbent, Commissioner Jim Irbin (ph), Republican, two other Republicans and three Democrats. We do not take a position on candidates. We believe we will work with whichever of the candidates are elected. We have begun meeting with the candidates to make sure they are up to speed on the issues relating to our company before they take office this concludes my prepared remarks on pending issues. I will turn back to Mr. Bill Post.

During second quarter earnings conference call, I explained we expected to be involved in proceedings until sometime in 2004. As Jack has explained that is still true. I also explained although we had significant regulatory challenges before us, our company performance was very strong and I expect to achieve several positive regulatory decisions before the expiration of settlement period in July of 2004. That is also still true and we remain committed to achieving constructive overall outcome in regulatory proceedings. I would like to address our financial outlook in form of earnings and liquidity.

As you may be aware, late last Friday, SFAS emerging issues task force voted to rescend EITF 98-10, which governed accounting for trading activities. However, the decision is not available in writing and details and transition are not yet clear. For those reasons, financial outlook I will give on this call has not been update to reflect EITF's decision late last Friday. To the extent possible, we will evaluate the effect of that decision for inclusion in our 3rd Quarter10-Q. From here on I will repeat those I made on October 18, during the analyst conference in Phoenix.

First, our earnings outlook. Our outlook for year 2002 has not changed since we released second quarter earnings. More specifically, although I am not providing point estimate, I am not uncomfortable with reasonable range around $3.46 per share before deducting one-time severance cost for voluntary work forecast reduction we announced in July. As I stated, we expect the up front cost related to workforce reduction to be up to 37 million pre-tax or 26 cents per share. I want to be clear to our knowledge, analyst estimates for the quarter or year have not been adjusted to reflect the severance charge.

For 2003, we see comparable earnings to those we expect to report for 2002. After reporting the severance cost. Although we see strong operating performance in APS, our regulated business, two factors are expected to completely offset other earnings growth in 2003.

First, as we previously discussed and reported in our OCI disclosures, early in 2001, due to anticipated high gas prices and possible shortages, we hedged our gas volumes and prices for 2003 and 2004. These gas hedges add $20 million after tax to our anticipated 2003 cash gas fuel expense, using today's forward-gas curve. The second factor is related to pension and associated benefits. We now expect our 2003 expense for pension and OPEC to be 10 to 15 million after-tax above 2002 levels due to recent declines in the investment markets and our related funds. In unregulated businesses, including unregulated generation, power marketing, SunCor, El Dorado, APS Energy Services and the holding company, we see flat earnings in the aggregate in 2003 compared to 2002, comprising 10 percent of the total about the same proportion as 2002.

The most significant change is an aggressive effort to approximately double earnings for SunCor in the '03 through 05 period, compared with the approximately $20 million Mike talked about expected for 2002 through accelerated asset sales activities. This acceleration will provide $80 to $1000 million per year of cash distribution to the parent over this three-year period. For 2004, we see strong performance without offsets expect indeed 2003, producing earnings growth for 1996 through 2001 of 9 to 10 percent. 2004 is a long way out, but APS retaining ownership of generation, revenue projections and earnings stability become more predictable, giving greater certainty to the years. Regulated earnings are anticipated to produce 90 percent of the total and unregulated activities are expected to contribute the balance.

These earnings projections are based on continuation of the rate plan included in settlement agreement, approval by commission of financing request in a timely manner, track B issues being revolved by the commission in a form reasonably similar to that proposed in the initiation, but not completion of a full based rate case for 2003, as a result of the commission's reversal of its direction on asset transfers and competitive bidding. As Jack said, we would not expect a decision on the rate case until the end of 2004. We have not adjusted our outlook for the possible impact of the EITF's decision to resend (ph) 98-10 on Friday.

As far as the rate basing, for purposes today and to provide conservative picture, we have assumed they stay unregulated. We expect to finalize the treatment in the 2002 base rate case. This decision will be predicated in part on the pending financial request and track b decisions. Now, I would like to discuss liquidity, which is significant short-term issue. I believe the commission will deal with this issue in a timely fashion, giving us time to replace the debt due in mid-2003. In August 27 meeting on track A, both chairman Mondale (ph) and commissioner Spitser (ph) made positive comments concerning expedited treatment of this matter.

I believe the commissioners will act responsibly to reverse the commission's 1999 decisions on our settlement agreement and the competition rules. As Jack said, we expect to pursue remedy for the damages we have and will expect to have as a result of the commission's decision reversal. We currently envision pursuing remedies through the courts and 2003 base rate case. Recently, there has been speculation concerning our need to issue equity. Assuming we are able to achieve favorable and timely regulatory decision, we do not believe additional equity would be needed to support our current credit ratings. We have had ongoing discussions with the credit agency and they are following us closely. However, in a scenario where the commissioners fail to address the impact of the competitive direction and our 1999 settlement agreement, we would anticipate taking the following steps to the extent necessary in priority order, first the reduction of capital expenditures through plant delay and cancellation, sale of non-core assets and finally issuance of new debt and if appropriate, new equity.

Although it would be inappropriate to discuss specific numbers for each category, we estimate some steps to approximate the total current debt of the parent company which totaled a billion dollars as of September 30, 2002. We believe even in this worst case scenario common dividend would remain in tact. It is certainly true we have significant regulatory issues to address. It is also true we have been very successful in managing our regulatory challenges over the last decade and fully intend to keep it that way. We remain committed to serving our customers and making money for our shareholders by capturing the growth in regulated business, capitalizing on opportunities in unregulated business and managing overall risk of our company. I apologize for the length of those comments. As you know, we had extensive discussion in the analyst meeting and want to make sure for the parties unable to attend that, they had the chance to hear that presentation. That concludes our remarks.

Thank you. Ladies and gentlemen, if you would like to register a question, press the 1, followed by 4 on your telephone. You will hear a prompt to acknowledge your request. If the question has been answered and you would like to withdraw, press 1, followed by 3. If you are using speakerphone, lift the handset before entering the request. One moment, please for the first question. Our first question comes from the line of Scott Pearl with Credit Suisse First Boston. Please proceed with your question.

Hello. Good morning. Question on the NAC charge -- I guess the $13 million. Could you give more color on what went into that and how to think about not going forward as far as exposure to similar tech charges?

Well, we do view the situation as unique. We had a couple of unique contracts that were basically of a fixed rate variety. We got in a situation at the company where they outsource a lot of the servicing of the contract. And actually, it was poorly written contracts. But, the risks were mounting and we got to a situation where we were behind our performance. We appear to have the correct actions in place. This is not a problem that is symbolic of all of the various transactions at the company. We are back on track in correcting a lot of the steps there. The reason obviously we are getting our arms around things there, but don't feel this is widespread and would necessarily be on going operating losses going forward given there is two specific contracts that are now the source of the approximately and we have taken a lot of actions to correct those two projects.

Is your exposure capped on those contracts? With the charge that you have taken or --

I think we are getting close to that point. We could see an additional charge in the fourth quarter are, but are not talking big numbers from this point forward.

Other contracts with this exposure, are these the only two?

No similar problems in the other contracts.

Great. Thank you very much. Second question, just on the gas hedges, we keep talk being mark to market and I know we talked about increase in cash cost for next year and there was language about mark to market impact for gas hedges. I am trying to understand as far as the gas hedges you have in place when those hit the income statement. Is that some hitting this year and next year or is it being mark to market and more coming in this year?

Okay, Scott. I think most of the hedges we have in place qualify for hedge treatment and would flow in over time. The charges we incurred in the current quarter were really the ineffective portion of our gas hedges. We just simply mark those to market in the current period and that is what the differentiation is.

Okay. So, as far as the $20 million you mentioned for next year and the cash cost, is that $20 million also going to hit the income statement or different from that?

That is our expectation.

Income statement amount?

'03 over '02.

Okay. Last question just on the ECC. Can you just remind us how the -- how it works as far as the chairman? Is that appointed by the governor or how does that work as far as the selection of that body?

That's a vote they take amongst themselves and the history has been that that changes on an annual

or every two-year basis. And the current chairman, I believe has been in that position for over a year, almost two years. But, it's not appointed by the governor, it is literally a vote they take amongst themselves.

Okay. Thank you very much.

You bet.

Next question from the line of Terry Shoe (ph) with J.P. Morgan. Please proceed with the question.

Terry Shoe (ph): If you could clarify again, what happened on Friday? I didn't quite catch that, something regarding part of your settlement, '99 settlement was impacted. I didn't hear correctly what happened on Friday?

Let me comment briefly and I will ask Jack to take a shot at it. Track B process continues and the staff issued their report on track B their second report on track B. Jack.

They issued a preliminary report about a month ago. Filing by the staff was final report on track b and what it essentially does is allow Arizona Public Services to redetermine the amount of power to be bid and the way in which we bid it. The two manners in which we were talk being bidding is either the term of (inaudible) process or auction process. Also, we filed -- will be filing next week the amount of megawatts to be bid for the year 2003 and right now it looks to be approximately 1500 megawatts.

Terry Shoe (ph): Okay, just clarifying on the form, nothing changed in the track b final report?

That is correct.

Terry Shoe (ph): Also, when you talk about having some of the issues addressed either in your '03 rate case or through the courts, are you talking about specifically when you had to take the charge when you moved your generation assets into the non-regulated some-odd million to try to recover that? I think, bill and I talked at eii (ph). Can you maybe review it again? I am confused.

It would include the 234 million. It was a write-off we took in 1999, matching the cost against an expected wholesale price. Of course, we are not going to go into that market, then that comparison is no longer relevant. It would also include potentially other items, as well. We have, for example, the cost associated with the movement toward the competitive transition rules and the incurred cost we had for many things, IT and others. We would ask for those in the 2003 base rate case. That is our current plan. As I mentioned, as I result of the denial of our request for reconsideration of track A, would also be going through an appeal process. It would be our intent to pursue those principally before the commission and those issues before the commission at least in parallel with, but as a primary attract to deal with them at the commission first, if that is possible.

Terry Shoe (ph): Right.

While keeping all of our options open, that is exactly right.

Terry Shoe (ph): But, you're not going to file anything for now, legal case?

Before the commission, we would not expect to make the filing until the first half of 2003. We wouldn't expect, as Jack said, outcome through 2004, at the end of 2004.

Terry Shoe (ph): Right. So, if you do file a legal case, it is a ways off? You -- your first resolving regulatory issues through the rate case, that is right?

-running for the three positions at the Commission have been involved to some extent or another, each at different degrees, on these issues. One of them is a legislator and has held hearings on this subject. So, I would not see a significant delay. We have had some conversation with the staff about that. I would not see a significant delay as a result of that.

Terry Shoe (ph): One other clarification. The hearing is on January 8th?

Yes.

Terry Shoe (ph): Then the commission, could you remind us the process after that?

Hearing January 8, the hearing officer will issue a proposed order. I would expect a decision in February.

Terry Shoe (ph): Thank you.

Our next question from the line of Jason West with Deutsche Banc. Please proceed with your question.

I just want to get more color. Looks like the marketing and trading business posted a decent quarter despite the problems or difficult market you have out there on the wholesale side. Just want to know what the drivers were? I think it was $44 million of gross margin?

Jack.

Yes. They have posted a reasonably well quarter that is essentially coming from all own generation and deals in the quarter.

So, the decent amount of origination in the quarter. Is this type of run rate something you are assuming for next year? It seems a bit high, I guess.

I would say this point in time, it would be difficult to anticipate that kind of run rate. I think as Bill Post stated before, we look at power marketing as primarily risk management tool and the fact we have been able to take advantage of the market opportunities the last couple of years is important. But long-time run rate at that is not one that I would predict.

Right. One separate topic. Bill, could you talk about the corporate reorganization you guys announced earlier this week or last week, just sort of what the emphasis was to put that in place?

Sure, the driver was really the regulatory decision builds within Pinnacle West, the separate entity of APS with own generation and own vertical generation. As a result of that change, we have been working for years, over five, to functionally organize inside Pinnacle West around various functions. As a result of that decision, it is critical that APS be independent in terms of its ability to be able to deal with all of the issues from a regulatory standpoint. That was the driver behind the organizational change.

But, this doesn't change your view on possibly moving the unregulated generation into APS at some point?

No, that is not something you can predict as a result of that organizational change. It really was one to establish all of the appropriate functions within APS.

Okay. Thanks a lot.

You bet.

Next question from the line of Paul Patercon (ph) with Deplen Rock (ph).

Paul Patercon (ph): Something on the regulated side. Could you give me an idea about the last nine months what the regulated Roy Roe (ph) was at the Arizona Public Services?

To refresh your memory, knowing you, you already know. That was established in 1999 at 11.25 percent. And we don't have a full cost of service. We're going to be preparing one for the test year 2002 to be included in the 2003 base rate case. But, we don't have a fully developed and allocated cost of service number to be able to give you a valid roe.

Paul Patercon (ph): Okay. Since they're complicated, it is not as simple as looking at amount of equity at Arizona Public Services and how much net income is, right? I mean, would that give us an approximation?

You are right. It's complicated. That is the reason we don't have it to give you t. requires full cost of service. We also had accounting changes during that period and have organizational changes during the period. So, I wish I could give you a number. We are working on it.

Paul Patercon (ph): I hear you. Clarification. When you mentioned that your guidance doesn't include the changes that happened on Friday regarding 98-10, could you give us an idea about what your expectation is for 98-10 in terms of contribution or lack there of in 2003?

I do follow you. Again, I'm sorry to answer both questions the same. I will answer that one with the same I don't know. We have to get more specificity (ph) around that decision late on Friday. We don't have anything in writing on that. How that will impact contracts or impact mark to market on both balance sheet and income statement accounts going forward, I don't know right now. As I mentioned, we will do our best and hopefully receive that instruction this week. We will do our best to do what we can in the 10-q.

Paul Patercon (ph): Great. Thanks a lot.

Our next question comes from the line of Kit Kinlig (ph) with Morgan Stanley. Please proceed with your question.

Kin Kinlig (ph): It is actually (inaudible). Could you provide more detail on the earnings in the nonreg (ph) operations in '03? I know that is the $20 million loss from the NAC contracts that rolled away. SunCor will be up a little. How much will be offset by marketing and trading and what is APS ES going to do?

Let me start with the end point, which we see for the total collection 2003 versus 2002 of staying about the same. We see SunCor, as I mentioned, with significant increases. We see Pinnacle West Energy Corporation, because of the full year of red hawk unit one and two and addition of West Phoenix unit five in summer of 2003, with declines. We see APS Energy Services staying relatively flat. And Power Marketing down I believe Mike had it down a little bit. But, frankly, that would probably be okay, too.

Kin Kinlig (ph): Okay. I mean, we can look at it as market of trading will offset any gains from SunCor and El Dorado in '03?

If you take the whole piece, one thing that will be important is, as you know and as we just discussed. The interest cost associated with the unregulated generation of the parent. Going to commercial operations for those Red Hawk units and west Phoenix units, we expect increase there. You have ups and downs in all of the pieces. We think that next year will be approximately equivalent to this year.

Kin Kinlig (ph): Okay. Thanks very much.

Ladies and gentlemen, if there are additional questions at this time, please press the one, followed by the four. Our next question comes from the line Scott Pearl. Please proceed with your follow-up.

Thanks. Just want to clarify on $7 million of other expenses related to net investment losses, what that item is and how you think about that going forward?

Could you give us more on that?

Sure. In your page six of your earnings variance explanation you talked about at the bottom of the three-month comparison operating expense decreased $7 million due to miscellaneous nonoperating costs of five cents, I guess.

Scott, that has to do with a number of different income types of things like deferred compensation plan, funding and basically thinking of it as miscellaneous losses. That Other expense line also includes a piece of El Dorado's other income and so, we have a few minor losses still at El Dorado that fell in down there. If you look at the first page, you see El Dorado had a total loss of $15 million for the quarter. You have a couple of million following through down there, as well.

Okay. But, as far as where that falls into year-over-year comparisons, these are things you don't expect to be recurring or -

Not something new that would factor into the year-over-year that Mike gave everybody at the analyst conference and has been on the website.

Okay. One other question I just wanted to try to understand on here where you talk about the sales from Pinnacle West Energy into APS as far as the agreement between those two entities. I am just trying to get an understanding. Is that market price or some type of -- just trying to understand your allocation between the two.

What that was, we went into this year actually late last year when we made the filing at the commission in October of 2001, that was a filing that had a purchase power agreement with sales from Pinnacle West Energy for all of the generation back into APS on a total cost basis. Fundamentally cost of service basis with 11.25 percent return on equity embedded in that. It was basically a cost structure and the contract was consistent with the filing we made in October. It goes through the end of this year.

Okay. So, this would be more of a cost of service on the cost of these new gas plants where you were talking about cost of service on the whole system?

That is correct.

I guess next year it is up in the air as far as where that comes out depending upon the bid?

Exactly right.

Thank you.

Our next question comes from the line of Elizabeth Nobel (ph) with Vanguard.

Elizabeth Nobel (ph): Could you comment a little bit on the market place in regard to what happens in March? For example, who might be other suppliers of power and where else might power from Pinnacle West Energy go in the event they are not the high or best bid?

This is Jack. The bid in March -- I can't predict who the bidders may be. Certainly the bidders would likely include the entity power plants around Palo Verde such as Duke, Centra and Pinnacle West Energy to the extent those parties do not bid or do not -- are not the chosen bidders within APS auction, they would have access to other markets such as Southern Nevada and California. And for all I know, they may have other displacement contracts to put in place. I am not aware of any.

Elizabeth Nobel (ph): Thank you.

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Ladies and gentlemen, that does conclude your conference call for today. We thank you for your participation and ask that you disconnect your line. (Normal Termination.) The call ended at 10:59.