Pinnacle West Capital Corp (PNW) 2003 Q1 法說會逐字稿

Good afternoon, my name is Trinece, I will be your conference facilitator.

At this time I would like to welcome everybody to the Pinnacle West conference call. All lines are placed on mute to prevent background noise. After the speakers' remarks there will be a question-and-answer period. During this time, simply press star then the number 1 on your telephone keypad. If you would like to withdraw your question press star, then the number two.

I would now like to turn the call over to Rebecca Hickman, Director of Investor Relations, please go ahead.

Thank you. Good morning everyone. Thank you for participating in this conference call or our webcast to review our first quarter results and recent developments.

This call is being webcast simultaneously on our website, www.pinnacle.com and a replay will be available on the website for the next 30 days. The replay of the conference call will also be available through next Friday, May 9 by calling 1-800- 642-1687 and entering access code 983-3252.

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

Here's an outline of our call's topics. Bill's going to give you a brief overview of our earnings for the first quarter. Then Don will review the primary earnings variances for the quarter as well as other financial issues. After which Jack will update you on the status of regulatory developments and some of our operational results and finally, Bill will wrap up with financial outlook and strategic summary.

Before I turn the call over, I need to cover a couple of details with you. First, our company website contains extensive supplemental information on earnings variances and quarterly operating statistics to help you easily locate all the new information posted today, we've created a quick reference menu 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 to per share amounts will be after income taxes.

Next, it's 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 MDNA in our 2002 annual report on form 10-K 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 webcast are the property of Pinnacle West Capital Corporation and copying, transcription, redistribution, retransmission, or rebroadcast of this call in any way without Pinnacle West's written consent is strictly prohibited. At this time, I'll turn the call over to Bill Post.

I want to thank everybody for taking your time to be with us today.

We had a very good first quarter from an operational standpoint. We continue to demonstrate operational excellence in all aspects of our core business. We resolved major issues related to our liquidity and any regulatory uncertainty, and our financial strength.

And first, I'd like to talk a little bit about earnings. Our net income for the quarter was 28 cents per diluted share, and although lower than last year, in fact, these results were slightly above our expectations. And we remain on course for the annual estimate I provided you three months ago. That is a reasonable range around $3 per share.

We're also on track to achieve 90% of these earnings from EPS. With the remainder coming from our unregulated activities including power marketing. Donald Brandt's going to discuss earnings comparisons with you but I would like to highlight just a few things.

As we expected, marketing and trading activities declined from a pretax gross margin of 40 million in 2002, to 19 million for the first quarter of 2003. This comprises about 60% of the decrease in earnings compared to last year. As you can see, from the data provided on our website, the change in electric mark-to-market gains were up $31 million due principally to the weak wholesale electric market here in the West. SunCor's program is on track.

As we discussed last Fall, we expect them to contribute approximately 40 million in earnings this year with cash distributions to the parent in the 80 to $100 million range. This program to increase asset turnover at SunCor also added a new line to our income statement, income from discontinued operations net of tax, which is almost entirely comprised of the sale of a water company SunCor sold in the first quarter for $55 million.

As you know, NAC recorded significant losses at the end of 2002 related to a contract cancelled by Maine Atomic Power Company. I'm pleased to tell you they reached a shelter on the contract dispute and as a result, we've reversed 5 million of pretax losses we recorded last year.

We also renegotiated the other significant contract that contributed to NAC's 2002 losses that we talked with you about in our last meeting, and we expect that contract to be completed by July. I'm confident we have put these contract issues behind us and we do not expect losses from NAC in 2003.

At this point, I'll turn the call over to Don. As I said, he's going to give you a detailed review of our earnings variances. Don?

Thanks Bill and thank you for joining us this morning.

This morning, I'll cover the more significant earnings variances for the first quarter. You'll be able to find greater detail and analysis' our earnings variances on our website. After this call, Becky and Lisa would be happy to assist you in navigating our website. I'll also provide an update on several other topics, SunCor of real estate activities, Arizona's economic outlook, energy marketing and trading in our liquidity and capital structure.

Before turning to our first quarter results, though, I'd like to point out that any time I refer to per-share effects those amounts represent diluted earnings per share unless otherwise noted in my references to dollar amounts of revenue, gross margins, and expenses represent before tax effects. With that housekeeping taken care of, I'll turn to our 1st quarter results.

We reported net income of $25 million or 28 cents a share, for the first quarter of 2003. This compares with net income of 54 million or 63 cents a share for the first quarter 2002. Bill has already summarized the key financial factors affecting the quarterly financial results. I will provide you with additional context.

First quarter electric gross margin was $329 million as compared to $358 million in the first quarter of last year. $21 million of the $29 million decrease was related to our marketing and trading segment. The gross margin decline was driven in large part by changes in the mark-to-market on our trading portfolio. Specifically, the decline was related to less new deal origination and lower margins.

The new deal volume is an outcome of the reduced number of credit worthy counterparties and the resulting lower market depth and liquidity.

Gross margin from our regulated electric segment was down $8 million, the favorable impact of customer growth of 7 million for the quarterly comparison was offset entirely by three factors: Higher hedged gas and purchase power costs of $8 million; retail price reductions of $5 million; and the negative impact of the warmest winter on record of $6 million.

As a reminder, we told you in October 2002 that we expected the 2003 earnings of the regulated business to be impacted by higher hedged gas and purchase power cost of approximately $59 million after tax. The higher fuel-related costs in the quarter were in line with our expectations for the year. The weather was the unexpected factor.

O&M expense for the quarter was higher by about $16 million primarily due to three factors: First, the timing of scheduled fossil plant overhauls added $7 million which is expected to reverse in the second quarter of 2003. Second, pension and other retirement-related costs increased $6 million and third, O&M expense attributed to the in-service generation plants add $3 million. In addition to their impact on O&M costs the newly in-service generation lands added fixed cost to the quarter of approximately $10 million on an after-tax basis.

Regarding NAC, the reversal of losses discussed by Bill added 3 cents per share to first quarter earnings. Excluding this 3 cents per share increase, our quarterly results were solidly on target with our plan for the quarter.

Now for an update on SunCor's real estate activities. SunCor recorded net income of about 6 million for the quarter which includes a $5 million gain on the sale of the water utility company. This gain is reported as discontinued operations on our consolidated income statements.

In light of our ongoing efforts to accelerate asset sales at SunCor, we continue to expect SunCor's earnings in each of the years 2003 through 2005 to be about double the $19 million SunCor earned in 2002.

Income from discontinued operations of $14 million for the 12 months ended March 31, 2003, reflects the gain on sale of the water utility company and a gain on the sale of the a retail center in the second quarter of 2002. The gain on the sale of the retail have had been reported as continuing operations in previously issued 2002 financial statements.

But now, consistent with the provisions of statement of financial accounting standards Number 144, it has been reclassified as discontinued operations. Going forward, SFAS 144 will likely require portion of SunCor's real estate activities to be reported as discontinued operations.

We currently estimate that 20 to 40% of SunCor's net income in 2003 will be accounted for as income from discontinued operations. However, the ultimate accounting will depend on the specific properties sold. As always, if you have any questions, Becky and Lisa would be pleased to walk you through the intricacies of financial reporting for real estate activities under SFAS 144.

Now, turning to Arizona's economic outlook in 2003, our state's economic recovery appears to be on track with our expectations for a gradual acceleration of growth through year-end. Arizona's payroll job growth for year to date February 2003 was 1.1%, which represents about a 2% improvement compared with the prior period. We previously indicated that customer growth had slowed compared to our historical growth rates of approximately 4%.

Customer growth for the first quarter 2003 was 3.3%, which reflects a slight improvement from year-end 2002. We estimate population inflows should remain steady at 2 to 3% as continued demand for housing with job growth returning to positive territory.

Manufacturing, particularly the high-tech. sector appears to have stabilized. However, we don't expect sizable new investment in 2003. The apartment and office markets continue to be the weak real estate sectors. Going forward, we continue to expect customer growth at about 3.5% annually through 2005. We currently estimate annual retail kilowatt hour sales growth of 3.5% to 5.5% through 2005.

Now, turning to energy marketing and trading, our marketing and trading group's primary focus is to actively manage our fuel and purchase power risks. APS's energy needs are approximately 80% hedged for the year 2003.

As Jack will discuss later in more detail, we are in the process of procuring a portion of APS's power needs through the Arizona corporation commission's mandated track B processes that underway.

Forward gas and power prices have increased since last Fall. However, from a consolidated Pinnacle West perspective, we estimate that the majority of any higher cost will be offset by higher margins in our marketing and trading segment on their sales of excess generation.

With respect to managing our credit risks, we continue to take steps to manage our exposures to noninvestment-grade counterparties, particularly those that are susceptible to further downgrades or defaults. More than 85% of our counterparty exposure is related to companies rated investment grade by one or more of the credit rating agencies.

Of the remaining exposure, roughly two-thirds is related to nonrated counterparties and one-third is to sub investment grade companies. In the nonrated category, our largest exposures are to ISO's and cooperative power agencies.

Finally, turning to our liquidity and capital structure, and starting with APS, we expect the utility to continue to fund substantially all of its capital expenditures with net cash flow from operations. APS currently has no short-term debt and is actually in an invested position of approximately $100 million. We continue to expect APS to be in a strong liquidity position throughout 2003.

Pinnacle West had short-term debt balances of approximately $100 million at year-end 2002, and currently has about 300 million of short-term debt outstanding.

During 2003, our short-term debt balances are expected to increase as we complete the construction of West Phoenix 5 and continue the construction of Silver Hawk. Pinnacle West should end 2003 with short-term debt balances in the $150 million area.

SunCor continues to accelerate the sale of assets to provide cash distributions to Pinnacle West. The sale of the water utility in the first quarter resulted in $25 million of positive cash flow, based on asset sales in progress. We're very confident that SunCor should be able to deliver cash distributions this year on the high end of our previously disclosed range of 80 to $100 million.

The recent ACC order that allows APS to issue up to 100 -- or excuse me, 500 million of debt, and enter into a four-year inter company loan with Pinnacle West Energy, has become final and no longer subject to appeal. We plan that APS will be in the debt capital market sometime in the next few months.

The intercompany loan proceeds will be utilized to repay the 475 million of debt maturing in July and August of this year. In addition, Pinnacle West also has a $215 million note maturity in February 2004. We have in place the financial flexibility to fund this redemption. In terms of capital structure, we expect our year-end 2003 debt ratio, including the PaloVerde sale lease back to approximate 54%.

In summary, our quarterly results were in line with our expectations. Our liquidity situation is sound, and we remain conservative in our approach to energy markets and risk management. I will now turn the call over to Jack.

Thanks, Don. I'm going to give you a brief update today on regulatory developments with the and you understand corporation commission and a summary of our recent operations.

I'll begin with the regulatory developments. They are currently three regulatory issues that are either pending or in development that I'd like to touch on.

First, the competitive solicitation process for APS's purchased power as required by the ACC track B order. Secondly, our proceeding to establish certain rate adjustment mechanism, and lastly the general rate case we will file by June 30th as required in the 1999 settlement agreement.

Moving to the track B process, most of you know that the ACC approved on February 27th the established a competitive procurement process for APS's power. The process is generally referred to as the track B process and applies to power purchases beginning July1st of this year.

Beginning this year, we are required to solicit competitive bids for approximately 2,500 megawatts of capacity, including 800 megawatts of must-run generation and 4,600 gigawatt hours of energy. That represents 18% of APS's retail energy needs.

In the future, the bid amounts for each year will grow as our customers' needs grow. Here's the status of the process: We issued a request for proposals in March. In the RFP we described the time frames for which the bids could be submitted. We indicated that we prefer bids for all or part of a time frame from 2003 through 2006. But also, we would seriously consider longer term proposals.

In the RFP we described the types of energy products that we prefer the bidders to include in their proposals. For example, the types of energy might be on-peak, super peak, or off peak or a bidder could offer capacity with dispatchable energy from specified power plants. And the energy could be supplied through such methods and forward contracts, options or other means such as exchanges.

The flexibility in the bidding process should allow us to select the suppliers, products and delivery methods that can best meet APS's needs. We must evaluate all bids without giving preference to any potential affiliate bids, however, we can decide not to accept bids on three criteria: If they are unreliable, uneconomic, or unreasonable.

The bids we received recently in the process of evaluating them is underway. The evaluation process involves a number of APS people as well as the commission staff and an independent monitor. We expect to announce the winning bidders by the end of this month.

Now, let me turn to the adjustment mechanisms I referred to earlier. A document is currently pending with the ACC related to the design of certain rate adjustment mechanisms for APS. These would allow APS to recover several types of costs in a timely manner. The most significant of these would be first purchase power and fuel cost; second, cost associated with complying with the ACC competition rules; among other things, this category includes costs of preparing to transfer our generation out of APS as previously required by the commission.

We filed our proposed design of the mechanisms with the commission last year as required by our 1999 settlement agreement. In a sense, the adjustment mechanism proceeding is designed to allow the commission to make the policy and procedural decisions in advance regarding these clauses.

Essentially this means determining how they should be structured and implemented without determining any specific amounts to be recovered. A hearing on the adjustment mechanisms was held early last month we anticipate receiving the ALJ's recommendation in a final commission order sometime this summer.

The actual implementation of adjustment mechanisms would be part of APS's 2003 general rate case which I will discuss in a minute. Therefore, a decision in the adjustment mechanisms proceeding would not affect APS customer rates until the commission makes its decision on a general rate case.

Now, let's talk about the general rate case. As I have said, we're required to file the case by June 30 and we expect to make that filing in late June. As part of this filing, we will seek recovery of costs we have incurred in complying with the commission's electric competition rules in our 1999 settlement agreement. We will also seek recovery of costs we have incurred as a result of the ACC's track A decision in 2002.

As you may recall, the commission reversed direction in the track A decision by requiring utilities to keep their existing generation. It had previously required regulated utilities such as APS to divest their generation either through an affiliate or to a third party.

The major items we expect to include in the filing are: Updates to overall cost of service including cost of capital, fuel and purchased power; rate-based treatment for existing unregulated generation Arizona, which is currently dedicated to APS's customers and owned by Pinnacle West Energy, commonly referred to as reliability assets; recovery of the $234 million write-off we recorded as part of our 1999 settlement agreement; recovery of costs of complying with the ACC's electric competition rules, including those we incurred in preparing to transfer APS's generation to Pinnacle West Energy. And of course rate design changes.

Based on the ACC's track record in hearing and deciding rate cases we expect a decision -- excuse me -- we expect a commission decision on the 2003 rate case around 2004, the end of 2004.

Now, I would like to brief review some of our operations. The first quarter continued to be a very good quarter operationally. We continue to see significant growth in our retail service territory.

During the first quarter, our customer growth grew about 3.3% compared with the first quarter of 2002. Our growth continues to be about three times the national average. Our focus of operational excellence and efficiency is ongoing.

In the first quarter, new ratings from JD Power & Associates ranked APS number 1 among investor owned facility in the West. The wholesale power markets in the West continue to provide opportunities for our power marketing group and our unregulated generation. However, these opportunities must be weighed carefully against additional credit risk. Prices firmed somewhat during the first quarter but we continue to see a reduction in the wholesale market counterparties.

Overall, the market's lost depth and liquidity compared with conditions a year ago. As Don said, our efforts are still focused on managing risks associated with wholesale power sales and procurement.

Our power plants performed superbly in the quarter. This time of year is when we schedule most of our maintenance on the plants and also we did not have any significant unplanned outages. The nuclear and coal capacity factors were about the same as last year's first quarter. The amount of electricity produced by gas plans was almost four times the output a year ago primarily because of new efficient capacity available from the Red Hawk units placed in service last summer.

The spring refueling and maintenance outage at Palo Verde #3 has gone very well. It returned to service on Wednesday which continues our track record of completing these outages in about 30 to 36 days.

Our construction activities are also on track. First, the construction of West Phoenix Unit Number 5, 530-megawatt plant remains on track for commercial operation this summer. Construction of our 570-megawatt Silver Hawk plant in Southern Nevada is progressing for a summer 2004 start date are construction plans also included the development of a new 500,000 volt transmission line this summer.

In Arizona, transmission to major load areas is limited and can be constrained at times delivering power from new power plants. Our any line is critical to ensure reliability in 2003. It extends from the switch yard from the Palo Verde line to the southwestern edge of the metropolitan Phoenix area.

At the federal level, we are continuing to work with our other utilities in our region to form the West-connect RTO. We're active participants in the FARC standard market design initiative and congressional debate over the energy bill, all of which have been in the news recently.

In summary I continue to be proud of our operational excellence. I also assure you we will continue working with our regulators to constructively address regulatory issues. That concludes my remarks, now I will turn the call back over to Bill.

I'd like to add a if you comments to the Plan B process. Pinnacle West incarcerate provided a bid as permanented by the ACC order defining the process.

As Jack said, evaluation process is underway. We expect to announce the results of the process by the end of May after all the bids have been evaluated and appropriately negotiated. Codes of conduct for the process are stringent and we have strictly adhered to the commission's we requirements that APS treat all bidders in a non discriminatory manner.

Because the process is in progress, and because of the codes of conduct, we will not be able to provide any additional information at this time.

In summary, we are a vertically integrated regulated electric utility. We've consistently met the challenges of providing reliable service in an area with customer growth that is at least three times the national average. As Jack said, we're on track for commercial operation in West Phoenix and we expect to complete this unit at or below our budgeted estimates.

As he said, Silver Hawk is also on schedule. APS energy services has over 400-megawatt of capacity sold in California and depending on the future of California of regulatory structure, Silver Hawk may be supplying some or all of their load in California. We explained over a year ago that regulation would be taking a greater part of our attention. It has.

And as Jack described, we expect that to continue as we return to a fully integrated electric utility. That's our meeting with you last Fall where we outlined our liquidity and regulatory plan, we have achieved successful results in each of the targets to date. We've had a solid track record of working with our regulators.

We've effectively navigated the recent abrupt change in the direction of competition in our state, we've managed market risks very well, and provided our customers the capacity to meet their growing electric needs while reducing their prices. Through these efforts and others, we remain tenaciously focused on making money for our investors. That concludes our prepared remarks and now we'd be happy to answer all of your questions.

At this time, I would like to remind everyone in order to ask a question, please press star, then the number 1 on your telephone keypad. We'll pause for just a moment to compile the Q&A roster. Our first question comes from Jeff Gladersleeve with Argus Research.

Thanks, it's Jeff Gildersleeve, how are you?

Good morning, Jeff.

I wanted to clarify a few comments under the energy marketing and tradeing, we're speaking about track B issues and how the higher costs will be offset by selling excess generation. Could you just clarify those comments for me?

Yeah. My point there, Jeff, was that we have seen both the price of electricity and gas market prices move up from what they were last year.

And any potential, I mean, we think it's reasonable that some of that will translate through the ultimate outcome of the track B process but we're confident on the other hand with both the capacity and energy we have available from our units that we'll be able to take to that excess generation to market. We'll make up for most of if not all of that cost increase coming out of marketing and trading. The point being Pinnacle West consolidated perspective it ought to be pretty close to a push.

Okay. So in other words, you're saying there's sort of an inherent natural hedge there?

Yes.

Okay. And thank you. Secondly, just again looking at the rate mechanisms, I think that the second regulatory issue discussed here allowing you to recover costs, purchase power and other, the decision is expected this summer. Do you have any sort of more dates that we could be watching for in that process?

This is Jack. At the present time, I can't give you a better date specifically but as I mentioned, we've had the hearing and the ALJ's opinion will probably be out this summer. And then from there, it will be in front of the commission to make it into an order.

Either way, though, the decision will not be populated with numbers so the results of the decisions won't have impact on rates until conclusion of the general rate case at that we're going to file June of this year.

I see. So it's more of a structural process which will be then put into the general rate case?

Yes, that's correct. Right now, we're just talking about structure. The numbers won't come out until the 2003 rate case completion.

Okay. Thanks and last one, this in regards to earnings, you said you feel on track for the year. I wonder if you could just discuss sort of the items versus '02. Obviously there's more O&M with the plants and some depreciation. And if you could highlight what might be offsetting some of those pressures?

I'm not sure I understand your question. Could you give me a little more?

Yeah, I mean, I'm just looking at where the quarter end up, and you commented that you felt that it was on track with the range or the sort of guidance that you've provided before. And I was wondering, it seems like as you've explained before, there's several sort of negative cost pressures through the year with new plants coming on line and O&M and depreciation.

I'm just wondering if you could highlight some of the positive or offsetting events that we might look for?

Sure. Well, the -- as you know, we've never provided quarterly guidance. And what we do instead is to try and provide pretty detailed quarterly categories, categorizations of expenses on the website so so we've really tried to provide as much fundamental history as possible possible.

Now, with that said, we've talked generally that we expect a very weak electric wholesale market, we expect increases as a result of the impact of pension that we talked about some six months ago really in terms of the overall increase on pension, and on the positive side, as we've said and as Don described, we continue to see pretty significant growth here in our service territory. Our customer growth is still significantly above average and we've seen some slight decline.

But overall, still very positive growth in terms of the performance of Arizona in terms of its continued significant growth. The impact of the decrease in the continuing decrease, regulatory assets and the amortization there, so the regulatory asset amortization in the schedule that was put together back in 1999 continues to decline. That is a positive.

And then, of course, the one-time losses that we took due to NAC last year. Those are three, I would say, major positives and, Don, you might want to add something. I think we've got to factor the continuing benefits of the savings we achieved through the voluntary separation plan last year.

We've been extremely successful in limiting the amount of backfill that continues with producing from that program alone savings of $30 million. And the SunCor earnings that we expect to continue to be twice what they were, double the $19 million they were last year. And we're really confident on the results that SunCor's going to deliver this year.

Great, thank you very much.

Does that answer your question?

Yes, it did. Thank you very much.

Your next question comes from Tom O'Neil of Lehman Brothers.

Good morning.

Hi, Tom.

Just three questions. I just wanted to clarify the SunCor expectations. Are you including the portion that could potentially be discontinued operations, the 20 to 40% in the 40 million and the 2003 reasonable range around $3?

We are, Tom.

Okay. And then what -- is it possible to provide just a rough range of what level of marketing and trading either pretax or net is embedded in that 2003 reasonable range?

Well, we've -- as you know, one of the things we've done is tried to give you a sense of the total number from a standpoint of APS. We do see APS excluding power marketing providing about 90% of that $3 estimate around some reasonable range, around that $3 estimate.

So the if you take all the other pieces, SunCor, APS energy services, power marketing, put them phoning, we see those contributing in total about 10%.

Okay. Last question is just about permanent financing at the parent company. It's, I think you still have about 325 million of long-term debt. Is the 150 million of short-term debt is that sort of a permanent number we should think about that will stay at the parent, and is that it?

Yeah, pretty much that's it.

Okay. Thank you.

Thanks, Tom.

Your next question comes from Greg Gordon of Goldman Sachs.

Most of my questions have been asked and answered. A couple of incremental ones. The reversal, I know it's only 3 cents but the reversal of the NAC losses, that was not in your $3 guidance, right? So that's a little bit of a help relative to the $3 earnings guidance?

Well, Greg, our guidance was a reasonable range around $3.

I hear you, it's only 1%.

Yeah, the point being the quarter excluding that number, we didn't need that number to make the quarter, but around our estimate, 3 cents is kind of static electricity.

Every little bit helps.

I must tell you, I think more than the 3 cents is the theme of NAC in terms of being more monitor. We think we have the arms around it with the two contracts we've been able to renegotiate, we're comfortable those contracts are behind us and we're moving ahead.

And no more losses going forward in.

Right.

The second thing was for Jack, just give us a better understanding of what type of decision will come out of the cost recovery case.

Will it be a decisional framework, or will we get a decision from the commission that says yes, we believe that the company should have a mechanism to recovery post costs on a certain basis or no, we believe the power costs should be at risk for post costs? What exactly will we get as your expectation that we'll get out of the commission that will then be put in as finalized in the general rate case?

Greg, I would answer this question this way: The expectation is that we would get structures under which we could recover costs but I can't tell you with 100% certainty that we won't also get additions that say there's certain kinds costs you can recovery and certain you can't.

Right now you're totally at risk; correct?

That's right, for fuel and purchased power, as we have since 1986 we're at risk for those costs through the completion of the filing of the 2003 rate case.

Right. So anything that you get would obviously be an improvement.

That's correct. And that kind of falls into what Don said earlier about the offset of off-system sales margin set against any increased costs we have on track B because we are at risk for those things. So anything we would get would be incrementally better.

The last question, you said APS was effectively 80% hedged to the summer, track Bprocess will be done shortly. Does track B get you 100% hedged or is there a certain amount of capacity and energy that you will remain at risk for through the summer?

Greg, the results of track B will put us at 100%, including reserves through this summer -- actually, through 2006 approximately based on present load forecast. Without revealing of the details we're going through right now, there are certain kinds of contracts that were presented to us that would be tolling arrangements, which means we bring the gas.

I thought of one more question: You did have the warmest winter on record as per your comments earlier. Yet you were still able to hit, you know, an earnings number for the first quarter that was -- puts you on track for your guidance.

Was thereanything in particular that happened that was a -- an offset to that that leaves you on track or had you built wiggle room in for expectation of weaker weather?

Well, Greg, I think a variety factors. The operational performance, the plant performance was superb in the first quarter. That had a positive effect. We presume that much going forward.

The cost performance, our cost reduction programs had come through. There were -- as you go through our website detail, you'll see a variety of pluses and minuses. But net-net, things worked out to the positive and pretty much offset the effect of that weather.

Okay.

Back to your first question, Greg, on NAC, weather was 4 cents and to the negative and NAC was 3 cents to the positive. So if you want to take those two, they would offset each other.

Great, thanks.

Thanks, Greg.

Your next question comes from Scott Pearl from CSFB.

Just wanted to understand, I wanted to confirm, it's the 28-cent number that was consistent with your expectations, is that correct?

Yes.

With that, and and sort of the percentage that that represents of this year's earnings of about 9% or so, if you just look historically, you generally averaged sort of 17, 18% of your earnings in Q1. I'm just trying to understand, you know, for the $3, how and why I guess the earnings pattern has changed from what we've seen historically.

The vast majority of that is the, in the power marketing. I would direct you to the website where it shows the gross margin, particularly I would look at mark-to-market and the way we have broken out historically power marketing in terms of the change in mark-to-market.

If you look at the mark-to-market additions in the first quarter of 2002, it was in the range of $40 million. The highest quarter we had for the entire year was, my memory is 44 million in the third quarter.

It's really unusual to have significant winter transactions in the range of $40 million. So that pattern really wasn't anticipated to be repeated. And when you look at the change in the condition of the market over the last 12 months, even if you normalized 2002, we believe that it would put even more pressure in terms of the earnings on power marketing into the third quarter as opposed to the first. So about, like I said earlier, I think about 60% of that variance was due to power marketing.

And in particular, the mark-to-market piece and we believe that a more normalized look is along the lines of where we are this year.

Okay. I guess with power marketing, though, only 10% of the earnings essentially of the company, though, still would have expected the pattern to be a little bit more towards the historical but --

But in the first quarter of 2002, it was much greater than 10%. That's really what's -- that's really what was unusual, is the contribution in 2002.

Uhm-hmm. And so basically a lot of what we may have erroneously assumed was going to be in Q1 is going to be in Q3 as far as getting to that $3.

We haven't changed our total power marketing contribution number that is embedded in the $3.

We should look to see that in the third quarter basically?

Right. That's also along the lines of what we talked to you generally about the power markets and as we have discussed, and as I'm sure every other company that you talked to has discussed, we continue to see deterioration there. We expected to see continued deterioration.

And with the real estate sales as well, obvious that, you know is a significant piece as well, the shape that we expect to see that in the third, and I guess fourth quarter as far as figuring out what the shape of the rest of the year looks like?

I don't want to give you the impression it's all in the third quarter it's spread over the whole year. But we have more in the third quarter than we do in the other three.

Okay. That's helpful. On the generation margin, the sales from -- sales of -- I guess it's sales of excess generation, the gross margin of, I think goes up about $3 million versus 2 last year off the website, this is generation sales other than native load from a gross margin standpoint, I would have expected to see that a little bit higher year-over-year just given prices and the additional generation that you have online. And maybe I didn't interpret correctly some of the explanations that Jack and Don had given.

But could you just, I guess, again go through I guess why we wouldn't have seen more in the first quarter from the additional generation that you've had and that seems to be running in terms of gross margin or maybe it's classified in a different area?

Well, actually we saw a substantial movement in price as both gas and electricity, right towards the end of the quarter. There wasn't that much of a dramatic change early on in that quarter.

Also, Scott, this is Jack. Also, again remember that those units, Red Hawk that came online, were actually dedicated to APS's load in the first quarter so they would not be first serving APS's load and then secondly selling off system.

Okay. I guess with -- just with the weak weather year-over-year I would have thought you would have had additional margin that would have come from your base load sales that sell off system in addition to maybe a little bit out of those gas units given the -- the spark spreads that we seem to be seeing quoted for out there.

You know, if you take a look at the comparison of offsystem sales that we show on the website, and see that the volumes went up, we're up three times in volumes.

But if you look at the margin effect, you can see that we ended up with the contribution in terms of total margin only increasing a million dollars or so.

Uhm-hmm.

Although we had a three-fold increase in volumes, the margins declined and the spark spread declines.

It's basically the increase in gas prices squeezing into margins?

It's the decline, the spark spread the difference between the electric price and the gas price and that comparison from '02 to '03 because the -- both the volumes and the revenues increased and the overall price of those revenues increased. All of that was an increase. But the margins actually declined.

Okay. Thank you. Thank you very much.

Your next question comes from Terri Shue of JP Morgan.

Yeah, hi. Just talking about the rate case which will -- you'll be filing, you said, within a few months with a final decision towards the end of '04; is that right?

Yes, Terry, we'll be filing the case at the end of June and we expect to have a decision by the end of '04.

Right, right. So it's too early to talk about details, what you'll be asking for in the general rate case and such.

But broadly speaking, when you look at underwriting earning power in '05, and look at the APS equity base now and add back the generation which you hope to bring back in to rate base, broadly speaking, can we say, let's say, $27 per share in APS book value and perhaps an 11 to 12% or 11-plus% ROE with your current year ROE being impacted somewhat by your purchase power costs et cetera so that the theoretical earning power is north of $3 from the utility alone. Is that a okay way to look at it, broadly speaking?

This is Jack, I'll let you handle the finance part of it, but I kind of laid out in my prepared comments the things we're going to ask for which would include bringing in.

Right.

-- units and updating all of our costs including return on equity.

Right so. So that -- would you disagree with that broad view in terms of just looking at what is the earnings power, long-term earnings power of APS? Which is really the bulk of Pinnacle West?

Don, do you want to take at that answer?

Well, let me take a shot at it, Jack. I think in a general sense, yes. Let me go to kind of the fundamentals.

I must tell you Terry I'm pretty optimistic about our ability to be able to prove our historical actions since 1999. I think we have done a very, very good job of meeting the needs here in Arizona. We've protected our customers from the kind of problems that existed in California.

And I believe, as we go through that proceeding, we're going to have a very positive case in terms of proving what we've done historically.

I also believe that reliability, not historical reliability, but going forward reliability's going to be an issue. And then there we're going to have a very good story because as the loads continue to grow and we continue to see growth, as we expect to see price decreases in California, and the elasticity effect of that, as we continue to see increased consumption throughout the West, I think reliability will start to become more of a concern on the supply side from an Arizona state perspective.

And then finally, I think all the uncertainty surrounding generation, the ownership of generation, financial strength of the owners of generation, and the horizon in terms of new plants and weather those new plants without any additional plants will be valuable in terms of being able to meet the kind of load growth we have in Arizona as we deal with this over the next 18 months are going to be significant factors. So underlying the algerbra that you described in terms of earnings growth, I believe is a very strong theme and thrust over the positive performance our company's had.

I ask that question because if you look at your stock price it still in a way sells at a discount relative to underwriting power and financial strength, your good dividend record and your ability long-term to grow you're dividend because for all the reasons we know, the liquidity's scarce and importantly, the regulatory proceedings, and the issue of all this excess capacity in your service area.

So the commodity price risk. So that if you can get that behind you and going out with your solid balance sheet, which no one seems to appreciate, looking at your equity ratio, that the earning power will be more visible. Is that a fair way -- I mean, that's why I asked that.

I think it is, Terry. Because if you look at the last six to eight months and the challenges we faced that we talked to you about last Fall, as I mentioned we tackled every one of those and produced successful results there.

So, now our focus can be on that long-term value issue and before the commission through a process that's going to show that not only did we do very positive job in terms of meeting all of the requirements that were placed upon us during very volatile times, both in the electric wholesale market and from a growth standpoint here in Arizona, we're also going to be able to show that we're the one that's going to be able to supply the reliability needs for our customers going forward.

And I think that will be a very strong foundation to deal with many of these issues in an environment that's different than the comparison and contrast to the energy debacle in California.

I suppose it's way too early to tell from your initial discussions with the commission and new member and such, how things will play out.

Is that a fair comment? That we'll get some hints this summer? With the track B, how cooperative and how constructive they are but really we won't really know for quite a while, but so far you're, I don't know, discussions with them or any kind of contact has been positive. Is that one way to look at it?

Well, we haven't had any discussions or contact with them but I can tell you in terms of the case that we're putting together. It's a substantive cases that going to cover a broad range of issues both from a historical standpoint and a going-forward standpoint. It's a very strong affirmative case.

But fair to say we won't know for sometime other than what we learn this summer about track B?

Terry, let me add, too, one important thing, we're coming off the heels of the decision on the financing application. And we had a strong working relationship with the staff and worked out a solution to that that ultimately was adopted by the commission and puts a very large uncertainty behind us.

I ask that because I don't know how one gets hints.

Like what could they say with track B that would cause concern or cause us to feel better? I mean, what kinds of outcome can come out of it, as you said, it's more structure and mechanism, what kind of costs can be recovered, what kinds can't be.

So far they've been constructive. But with many terms and conditions. They -- I mean, they're careful in all of their wording.

That's true, you're right.

Okay. So basically we should continue to see constructive action but any hint, hardly, right, this summer?

Terry, I can't give you a hint, I don't have one. The only thing I can tell you.

Not from you, but from them, actions on their part that would cause you concern or no concern?

Well, I would put it in the context of what we've seen over the last six to eight months with this new commission. I think you see a commission here who is really broad in terms of their perspective which includes financial strength of the company. And I think they are very thoughtful in terms of dealing with these issues.

I think they're going to see for the first time a very comprehensive filing that's going to show the substance and the importance of our ability to be able to continue to meet the energy requirements in Arizona.

When you put this together with what's going on at FERC, what's going on if the Congress, the uncertainty that exists in California from a regulatory standpoint, I believe we're going to be able to prove that the way to achieve the best outcome for our customers is to continue the very positive path we've been on.

Okay. Good enough. Thank you.

Your next question comes from Zach Schreiber of Ducane

Hello?

Hello.

Hi. Just I guess just a question on the track B and not going into, you know, confidential negotiations but going based off the legal document which the commission, I think, posted on February 27. And your own comments that you have to evaluate the bids without giving preference to your on affiliate on three criteria, you can reject them if they're unreliable, uneconomic or unreasonable.

Also, tying that into your questions about the wholesale market, and some of the credit issues there, how do you deal with the credit issues of some of the counterparties that are bidding into the APS RFP?

When I look at and follow the energy RP, these creditor issues have, become a thorny issue, I'm curious how you deal with them.

This is Jack. You're correct, the credit issues are thorny issues.

But the way we've handled them in the track B process so far is we're using the EEI standard form purchase agreement and in that agreement there are two kinds of credit provision. Number 1 is the initial amount that's called, and the initial amount that is based upon the highest credit rating of one of the three credit agencies and it meets certain standards. If they don't, they come up with an initial amount of cash or letter of credit. So that's the initial amount.

And then secondly, there is a margin account such that if the price of the product is more or less than the market price, then the successful bidder either puts money into this margin account or we give money back through the margin account, depending on the ratio of the price of the contract to the market power.

So right now, I feel very comfortable without going any farther than this, I feel very comfortable that we've successfully addressed the credit issue. But I would agree it was an issue in setting up our process.

Great. And all the bidders have been comfortable working within the terms on that?

I will save on that for later, but I'll say it was an issue.

Okay. Now, on track B, and your guys' preference for contracts through '03 -- I mean from '03 to '06, number with you, how can you enter into longer term contracts beyond sort of, you know, the '04, '05 period when you don't really have in place a fuel clause mechanism and you're not automatically guaranteed recovery or do you think that these track B costs will be recoverable no matter what kind of fuel adjustment mechanism is ultimately put in place?

In the standard form -- this is Jack. In the standard form contract which we put out which we have a regulatory out clause, and what it says is if for some reason these contracts we entered into are not approved by the commission for recovery, then we can exercise a regulatory out clause for periods beginning after 2006.

Is there going to be, then, a subsequent regulatory proceeding to approve the contracts that you enter into right after the winning bidders are announced in late May or will that happen years later?

Well, the actual recovery of the costs for power procurement will be part of the power procurement and fuel cost proceeding I talked about and also part of the 2003 rate case.

Okay.

When we talked to you last fall, our goal was to file the full rate case in April or May of this year. We have extended that to the end of June in order to incorporate the results of track B in that proceeding.

Right, got it. And just following up on your statements for the full year, for the full year you said that off system steal sales benefit should offset the higher gas prices at APS.

Is that under the assumption that the higher gas prices only hurt you for a half year? and that the offsystem sales help you for a full year, i.e. that the higher gas costs stop hurting you once you file the general rate case?

I think you said you bear the fuel costs 1986 through the filing of the 2003 general rate case. I want to know what your assumptions were.

No, Zack. Back up a little bit. I said that we were about 80% hedged for APS's energy needs. And basically the 20% differential is roughly equivalent to the track B process.

Got it.

And the point being for the balance of the year, any potential price increases we see coming through to APS as a result of track B we would expect to be able to offset at a so little consolidated level through off system sales.

Thank you for the clarification.

I was wondering for those of us who don't live in Arizona, and try our dammedest to understand some of the configuration issues, can you explain to us this translation line you're building, when it will come on line and what kind of impact you think it will have in getting load into the Phoenix load pocket?

The line is a 500 KV transmission line from Palo Verde down to the Southwest Valley and it is ahead of schedule and will be in service June 1 of this year.

It will add approximately 12 to 1300 megawatts of transfer capability into the Phoenix area, we own half of that transfer capability capability and Salt River Project owns the other half.

So to put eight different way for Arizona Public Service it will an increase of somewhere between, say, five and 650 megawatts of increased transfer capability from outside the load pocket area.

And that's an open access line on the FERC order 088?

Certainly all transmission lines are under open access under that, but I'm sure you've been following, one of the big issues is native load preference requirements. Right now, we exercise those requirements.

So can you use that transmission line for some of your projects in the desert to meet your native loads exercising your native load preference rights?

That line will be used to transmit in winning bidders' contracts to serve our load.

Sites APS's right, not the other's right, correct?.

Yes.

Okay. And I guess the fine question Jack and Bill, you've been very accurate on the direction of power prices. I can remember a meeting back in, I think April of 01 of 01 '01 where you told us you thought prices were coming down.

Where do you see power prices and gas prices? Where do you see this constant enigma of these evolving western power markets heading?

Jack you want to take that, first?

I guess from a overall perspective, I think there will be downward pressures generally on power prices through, say, the year 2005.

Referring back to Bill's earlier comments about turn around in the economy, the fact that there won't be any new -- I don't believe there will be any new merchant power plants built, and so I think in the 2005 time frame you're going to see a reversion of the price curve back to a much higher price.

In terms of gas, I think it would also have some upward pressure on that, but I see spark spreads actually widening significantly in the 2005 and beyond time frame.

Time frame between now and 2005, I think there will be some wideening of the spark spread but there will be downward pressure because of the state of the economy.

But I'll tell you, remember, California's about 40% of the western load. Once California's economy turns around, if it happens before 2005, that will be a significant plus for generators.

Got it. Thanks so much.

If you like, I can add a little to that. My sense is you put all of those things Jack talked about together, if you give consideration to what's going on in Congress and the fight between FERC and Congress over how far and how fast they're going to go in this area, if you look at the reregulation of the West, Senate bill 888 in California, what we're doing in our state, what New Mexico's doing, I think we're moving much, much more towards reliability from a regulatory perspective.

And what I mean by that is maybe comparable to a decade ago when we were looking at IPP-like markets, pocket-like markets. Much more disaggregated wholesale, electric wholesale market compared to an all-pervasive electric wholesale market where you have access throughout a broad region.

I think with all the efforts underway, I think we're moving towards much more of a pocket-like market and generalities are difficult in that kind of an arrangement.

Yeah.

But overall, I would say the future is much more positive than negative in terms of price.

I guess that kind of triggers one last question, I apologize.

In Arizona right now you have a state that's sort of betwixt and between, with not operating under 99 restructuring settlements, other companies doing that, and the pendulum of the state swinging saw say towards reregulation, do you think that the policy makers in the state are comfortable operating with one company operating under the 99 restructuring settlements and one operating in sort of a reregulated framework?

I look at that just a little differently, if you don't mind me changing your question a little bit. I see track B and competition deregulation as synonymous. Put another way, I think the commission's way of dealing with competition is track B.

Uhm-hmm.

So it really gives APS the method under which the deal with this competitive market. And I don't really see the other components of the 99 settlement agreement that don't apply to us. I don't see them applying to anybody else.

So I think track B is really going to be the method that is going to be used in Arizona for private utilities to deal with competition for the near picture.

Got it. Thank you so much.

Your next question comes from Jason West of Deutsche Banc.

Just a couple quick ones. Can you guys hear me?

You bet, Jason.

One, were there any coal-fired generators that put in a bid for track B?

Jason, this is Jack. At the present time, I can't reveal who bid or what kind of bids were given to us.

Right. Okay. But do you know of any that would be in that region available or, you know?

We really can't say.

I can't say.

Okay. And then another question, I think earlier when you guys gave the '03 outlook you had talked about retail growth and sort of the 3.5 to 4% range. Which obviously offsets some of the weakness and some of the higher costs.

Given the weak retail growth in the first quarter, do you guys need, like, a higher number for the rest of the year to sort of meet your guidance or is there other things offsetting that?

We're pretty much on track there. If you take into account weather.

Okay. And then one other one. You had said that you expect APS energy services to be down about half in '03 versus '02.

Still do.

You still have that factored in?

Yes.

All right. That's all I had. Thanks.

You bet.

Your next question comes from Jonathan Arnold of Merrill Lynch.

On the NAC contract settlement, you'd referred to having a second contract, which I think was going to be done by hopefully July. Would that have a similar gain associated with it? Is that baked into the numbers?

No, Jonathan, it wouldn't.

Thank you.

Your next question coming from Daniele Seitz from Smith Barney.

Two questions. One is, I was wondering if you had in your assumptions you already assumed that you are going to be in the winners in the track B type of lottery, and I was also wondering, or do you assume -- do you make assumptions and then plan for future contracts?

And the other question has to do with the transmission lines. How much of an investment was that and is it automatically interred into rates as you complete it?

Well, let me take the first question and Jack can talk to you about transmission. As to the first question, we used the forward curve at the time at which it was really towards the end of 2002. That's the foundation for our estimates for the earnings guidance for 2003.

Uhm-hmm.

And we have not changed that. So it wasn't tied to track B, it was really tied to the forward curve when we put those estimates together. As to transmission, Jack, you want to comment on that?

Yes, Danielle, the transmission line that's coming in service in June is Arizona public service this year is around $80 million in the line and the substation regarding putting in the rates, that will be part of our rate case information we file in June.

So we'll be asking to put that $80 million investment along with other investment into rate base in the 2003 rate case filing.

Uhm-hmm. Okay. And I'm assuming that the capacity that you want to be rate based is the same capacity that is in the track B bidding system as well, and so I'm sorry, I'm sure everyone has understood this whole thing.

But does that mean that actually in your case you cannot bid for more than the year or are you assuming that one folds into the next one when you want to rate-base it?

Well, the line itself will be included in the rate base request we make in 2003. The purchased power contracts that come out of track B will be part of the 2003 rate asking also.

As I mentioned earlier, in the contracts that we will eventually sign, there's a regulatory out clause that said if we can't get approval for these contracts or any why it is that extend beyond 2006, APS can exercise an option to get out of the contracts.

Okay.

And Daniele the two numbers do not match. They're really two different numbers. The amount that we will be looking for in terms of megawatts, in the base rate case would include about a thousand megawatts at red hawk two units at Red Hawk, West Phoenix 4 and 5 which total about 700 in total, and about a little over 100 megawatts at a Suarro Unit South of Phoenix.

Those are what we refer to as a the reliability assets, generation built to serve APS's customers.

Ah-huh. And your participation in track B can be anything? Obviously, you're not telling. I mean, all of it is not on the table.

Most of those are true. We're not telling and it can be anything.

Okay. Thanks.

Your next question comes from Theresa Ho from Banc of America Securities.

My questions were asked and answered.

Your next question comes from Michael Goldberg of Luminous.

Hello?

Hi, Michael.

Hi, how are you? I wanted to ask about reliability portion. When you say 800 megawatts, how much are you assuming in terms of gigawatt hours?

Michael, this is Jack. I don't remember exactly off my head, but the number of hours is somewhere around 400 hours a year. It -- but at varying megawatt levels.

So about 400 hours in terms of capacity.

Yes.

I guess besides West Phoenix, is it possible to say what other plants can even potentially compete for that RMR portion?

Michael, obviously there are more than just the West Phoenix plants in the RMR area, there's our own Pocatillo plant over near Arizona State University.

In our request for proposals on the track B process we asked parties to provide us, if they wanted to make an RMR bid, and to do that, they would have to get transmission from a third party, most likely Salt River Project or western area power administration. And to do that, if they did that, they would be adding costs to their bid price.

I think without going any farther, this will all become very much clearer when we reveal the track B bid winners.

Okay. Just a follow-up to that. I guess without securing any rights, none of the Palo Verde plants can really apply for RMR, out of the plants you mentioned, West Phoenix and the other ones, does the total megawatt capacity of those add up to over 800, just out of ones that you kind of mentioned? Do they add up to 800 or is there some competition there?

No, they all add up to at least 800.

Is it significantly higher than 800?

Well, let's don't get confused must-run with normal generation. Must run plants only have to run for a short period of time and will probably be things like combustion turbines. Plants like West Phoenix, 4 and 5, the new plants because we're more efficient will be running most of the time.

Uhm-hmm.

Anyway.

Okay. And just when you guys talk about 15% reserve I assume that's on a megawatt basis, not megawatt hour basis right?

Yes, based on a megawatt basis.

Is there any kind of way to predict how much of extra megawatt hours you may end up taking and that you generally sell back into the market?

Well, with a 15% reserve margin, the way a reserve margin is defined is that's the amount of margin we build above our peak hour of the year.

Uhm-hmm.

So if you want to -- I guess if you had a load curve for Arizona Public Service load, you could figure out how much energy that involves. The difference between a load energying a megawatt hour energy is frustrated by a 15% reserve margin.

Remember, reserve margins are peak hour numbers.

Okay, and when you guys talked about 90% of your earnings coming from APS, assuming that corporate kind of negative 10, 15 cents or around that number, when you speak of 90%, is that 90% of operating units or 90% of the $3?

90% of the $3.

Uhm-hmm. So I guess the operating units add up to more than $3 and then 90% of. Okay.

Then just one more question. I think when I was out West for your last year's conference, in discussing your combined cycle plant, the Red Hawk, if I'm not mistaken I think you might have mentioned something about different water supply that that plant has versus nearby plants that maybe Duke and [INAUDIBLE], I think have. Is it possible to remind me if there's a difference in water supply or if they're taken from the same pond?

No, they're not taken from the same pond. The other units are all groundwater units. Our unit uses effluent water, so it's treated effluent from the cities.

Is there kind of which one's more cost competitive of or which one's preferential?

I don't know what they're water costs are.

Do you feel like you've made the right decision, though?

Oh, yes.

Okay. Thank you very much. Take care.

Your next question comes from Jim von Reisman from JP Morgan.

Can you hear me?

Hi, Jim.

Hi. Can you talk a little bit about the doings on on Capitol Hill right now? We've had a couple of days to look at what's what the Senate's saying. Can you give us your thoughts there.

You bet, if you asked me that a week ago, I would have said the likelihood of getting a bill would have been pretty low in terms of probability. In the last few days up until yesterday it looked like the probability had increased pretty significantly.

My sense is that it's very dynamic and I'm still not real optimistic that we're going to end up with legislation going to the President. I think many of the other issues that are pressing may take precedent. Things like tax relief, may take precedent over energy title.

The movement with the Senate, I think now is going to really be in competition with those other issues and then of course have to go to conference. I don't necessarily subscribe to the fact that just because it's made it through the committee, that that guarantees we're going to get legislation. I think there's quite a political to climb and I'm not sure we're going to get legislation here.

Is it politically prudent for Congress to actually act on an energy bill or even one with an electricity title?

Well, Jim, my opinion is that the driving force here to great extent has been the White House. I'm not sure that the Senators or for that matter the Congressmen get a lot of personal political gain out of energy title.

But there's been historically significant desire on the part of the White House and the Secretary to get energy legislation. But when you look at many of the other things that are faced by the Congress, as I mention, the tax issues, I think one of the pressing issues is going to be the appointment of judges, which has sat there really without an awful lot of attention for a long time.

And my personal belief is many of these other issues are going to be in competition with that energy title. And I'm not as optimistic as others that it's just going to go through and we're going to have a bill.

Let me ask this same question a different way: Is it more prudent for the White House to go after market design and encouraging the right development out of that or is it more prudent for them to go after energy and legislation?

Well, I was -- as we've all seen the white paper that just recently came out of FERC, I think that's much more in line with the dialog that's occurred in the last six months of Congress than the history of FERC prior to that.

So it looks as if there has been some diminishment of the passion to aggressively move forward from a FERC standpoint. So I think that might have significant play here.

And it may give it what it would otherwise have, in terms of maybe a little more motivation. That effort may decrease some of the motivation.

Okay. Thanks.

Your next question comes from Casey Tyson of Miller Management.

Hi, it's actually Mark Miller. A question on your California energy sales. I'm just wondering if there are any transmission bottleneck issues. And if you could address how you're sending the power to California right now.

Well, Mark, if I gave you the impression that all that power's coming from here, I gave you the wrong impression. That power is basically California power.

What I said is as Silver Hawk goes into commercial operation and if we're permitted to extend and we're successful at extending some of the contracts as it goes through the change of regulatory structure in California, a market for Silver Hawk could be the capacity that we have in California. It's not today.

Okay. Well then with that backdrop what are the contrains, if you were going to try to sell power into California for transmission?

There is transmission available from Southern Nevada into California. When you look at the -- all of the -- I'm not sure how I can answer that question quickly.

When you look at path 15 and all of the other constraints in California, those constraints are real and they're considered in the process that we have with each of the customers and the supply that we align ourselves with in order to be able to meet that demand. So I'm not sure I can give you a simple quick answer though that.

No problem. The last thing on El Dorado, are you winding it down.

Yes, we have been for several years. The only substantive investment that we have in El Dorado is NAC.

The two, the investments in the Suns and Diamondbacks, is that something that gets moved, stays at Pinnacle West somehow or do you liquidate those, is there a market for them and with the Suns particularly do you have a gain in that, if you are going to liquidate that?

Given what happened last night -- (laughter). Just kidding. We have those valued at zero on our books. The investments we've made with the Suns and Diamondbacks started as community investments not financial investments. We own a small percentage. I would put that in the community investment category. As far as the Suns, you're right.

But that market is so difficult and so impacted by what's happening in the economy, it's kind of a unique market. And from our standpoint, has been and continues to be for the most part, a community investment.

Now, I understand that. I'm more towards the direction of with NAC, you had a $5 million gain on this contract settlement. If you sell the Suns or Diamondbacks is there that type of gain associated with this, is it much smaller, insignificant? That's what I'm trying to get at.

I wouldn't count on any earnings contributions from either of them. Let me if you don't mind, make a comment about the $5 million gain. It's not really a $5 million gain. We had reserved a loss and it's less of a loss.

I remember. Thanks.

Your next question comes from David Grumhoss of Copia Capital.

Good morning, how are you.

Hi, David.

Quick questions around the rate case. First, the rate adjustment mechanism order that you're awaiting, do you need to have that in hand before you can file a rate case?

This is Jack. No, we do not.

Okay. So you can just proceed with it and work around it? I guess?

That's correct.

Okay. In terms of the -- you mentioned sort of an end of '04 likely conclusion for all of this. Do you see any hope of getting an earlier settlement or is the complexity and the number of issues make you think you're going to have to go all the way through the process.

I would say once we file the case that opens up lots of discussions and I certainly wouldn't throw it out.

Okay. So despite the complexity, you do think there's something you might look to try and deal with, if things fell into place?

As Jack said, settlement's always an option. The only thing I would add is that we are dealing with a new commission and many of these issues are new in terms of both the process and their substance.

And my expectation would be is that we will need to go through certainly a major part of the process in order to get these issues understood on the part of the commission. Before we could really get too involved in settlement discussion on an issue-by-issue basis. But settlement's always an option.

Okay. But it sounds like you maybe sort of, you know, mid-'06 or mid-'04 as opposed to thinking anything really quickly could happen given complexity. Is that a fair way to characterize it?

I don't know if I would give you a prediction of mid-'04 but I would say certainly as we go through '03 and start to put issues together, I think there will be much more focus on the issues than the overall settlement but you never know.

This is a new commission and with the relatively new staff and as they deal with these issues, it's really going to depend on that process.

What I can tell you is we are not depending on settlement to reach resolution of this. And as I mentioned earlier we've a very strong affirmative case.

Okay. Great. Thank you.

Your next question comes from Philip Adams from Bank One Capital Markets.

Morning.

Good morning.

In marketing a and trading, I'm struggling with how to think about the huge increase in volumes and revenues and yet the huge decline in margins. And I guess the reason why I struggle with that is some notion about the profit potential relative to potential risks.

What should I be looking at that can give me some comfort or is there a change in the profile or the nature of the business that is either more or less risky than has been in the past?

Let me talk about the data first and then come back to the philosophy, second. I would direct you to page 4 of 43 on our website.

Okay.

Which outlines specifically the gross margin for power marketing and breaks it apart between various categories, mark-to-market, et cetera.

Okay.

That website also has data for each of the quarters year-by-year as Becky said back to 1999. So I would point you to that.

And I think that that is useful in getting a hand about not only what it's done to us historically in terms of power marketing and how we've performed but also on a going-forward basis given what we've talked generally here about the theme in terms of power marketing.

Now to kind of the theory of that, as Don and Jack and I have all said, we continue to see an erosion, a disintegration in the electric wholesale market. And we don't see, I don't see any near-term change there that's going to make that more liquid. Both in terms of the regulatory structure behind it and its practical operation.

So I don't see significant movement in the near term term to improve and develop a broad-based liquid wholesale market in the West.

Okay. I'm looking at that page. And, you know, it's other electricity, marketing and trading, I guess is where you make most of the margin.

But I guess what I'm struggling with is as you grow this volume, with shrinking margins, are you left with, I don't know how to describe it, but, you know, like open positions to riskier customers or customer concentrations? What are some of the ways that --

Sure, let us talk about that for a moment. What, Philip, I think what you're seeing is fairly obvious. The margins slinging and that's in effect two factors, the lack of depth and liquidity and the credit profile of the market.

We have the power marketing team here and the risk management group have been exceptional in their ability to navigate some difficult waters over the last particularly year to 18 months relative to credit exposures. And the fact that we have such a small component in the range of eight to $12 million with exposures to troubled credits, and that's broadly diversified within that $12 million, we remain, if anything, more stringent in doling out credit.

So, I think to maybe answer your question on point, is we at no time perceive any additional risk in how we've conducted the business. The market as a whole has substantially greater risk, but we've been very careful about who we do business with as a result the trading partners that we feel comfortable doing business with has substantially decreased.

We're at the, I hate to use the we are, the cream of the market but the margins are pretty darn skinny. Very substantially greater rewards, potential rewards to be gained, but one would take on substantially greater risk. And that's just not -- we have no appetite for that whatsoever.

That has been the perspective that we've had with our power marketing from the beginning, has been not speculative trading, but risk management. And I know that's the common thing for people to talk about today, but that was our strategy from the beginning.

And we have stuck with that strategy throughout all of the change over the last three or four years. The only other thing I would point you to is the footnote on that page, it just shows where we stand at the end of the quarter in terms of mark-to-market and how we expect that that will roll off in the next few years.

Okay. I see that. Thank you very much.

You bet.

At this time you have no further questions.

Well, if I can just make a final comment. Thank you all for your attention. We appreciate your time at this very busy time and to the extent we can provide any and all information, please give Becky a call.

We are strongly working diligently to try and provide as much historical information to you as we can. Thank you for your time.

Thank you everyone for being with us.

This concludes today's conference. You may all disconnect.