Pinnacle West Capital Corp (PNW) 2002 Q4 法說會逐字稿

Good morning. My name is Amanda. I will be your conference facilitator. At this time, I would like to welcome everyone to the Pinnacle West earnings conference call. All lines are on mute to prevent background noise. After the speakers' remarks, there will be a question and answer period. If you would like to ask a question, press star, the number 1. If you would like to withdraw, press star, then the number 2.

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

Thank you. Good morning, everyone. Thank you for participating in this conference call or webcast to review our 2002 earnings and developments. It is being webcast and a replay will be available on the website for the next 30 days. A replay of the conference call will also be available through February 11th by calling 1-800-642-1687 and entering access code 7575985.

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, and Don Brandt, our CFO. Here is an outline of our call's topics. Bill is going to give you a brief overview of the operations and earnings for the year 2002. Don will review the primary earnings variances for the quarter and the year, as well as other financial issues. After which, Jack will update on the status of regulatory developments and some of our operational results. Finally, Bill will wrap up with the financial outlook and strategic summary.

Before I turn the call over to our speakers, I need to cover a few details with you. First, the investor information section of our website contains supplemental information on earnings variances and operating statistics related to the years 1999 through 2002. The information was also filed with the SEC this morning in an 8-K. To help you quickly navigate this extensive information on the website to understand our quarterly results, here are a few tips.

Comparisons of the operating statistics to the fourth quarter and full year ended December 31, 2002 and 2001 are contained in a PDF file and a summary tab in the Excel file. Detailed explanations of our earnings variances with reconciliations to last year's period are also included on the website. We believe you'll find this information very helpful in understanding our results. Much of the other information on the website can help you later with projections and further analysis.

Second, please note that 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 it place undue reliance on these statements.

Please refer to the MD&A in our 2001 annual report on 10-K and our September 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 webcast are the property of Pinnacle West Capital Corporation, and copying, transcription, redistribution, or rebroadcast of this call without written consent is prohibited.

At this point, I'll turn the call over to Bill Post

Good morning, everybody. Thank you for taking your time to be with us this morning. First, 2002 was a good year for us in our core operations. At our foundation, we are vertically integrated, regulated electric utility. That business met the challenge of providing reliable service in an area with customer growth three times the national average.

Our operating performance was outstanding, and although our consolidated financial results are below last year as we expected, we improved our core regulated electricity business at APS, from $139m in 2001 to $198m in 2002. We achieved about $60m before the accounting change in our marketing and trading segment in a very depressed market. We increased SunCor's earnings by $16m over 2001, due to the acceleration of our asset sales.

We met the highest customer demand in our history with customer growth three times the national average. We set new power plant operating records, including a 94.4% capacity factor at Palo Verde, its best ever. We lowered our prices again. When combined with this year's decrease of another 1.5% in July, we will have given our customers a total reduction of 16% over the last decade, meeting the commitment we made and putting our company in a position that is unmatched in our industry.

We improved our customer service to the first core tile in the country, and we increased our dividend for the ninth year in a row. We did this by changing the regulatory direction of our company. As you know, our regulatory tasks are not complete. We expect to be involved in significant regulatory activities for the next two years or so. It is inherent in the nature of our business, and we have a solid track record of working with our regulators.

Let's review the earnings for 2002. Our reported income before the accounting change for 2002 was $2.53 per diluted share, compared with $3.85 for 2001 and in line with our guidance. As we have previously indicated, our reported results for 2002 include a number of items we consider to be unusual to our business, and nonrecurring in nature. These nonrecurring items total $1.03 per diluted share and consist of 26 cents to our workforce reduction, 35 cents a share related to our cancellation of the development of the Red Hawk units 3 and 4, and 42 cents a share related to losses at NAC, one of El Dorado's investment.

The 2001 results also included reserves for our exposure to Enron that totaled 15 cents a share. Therefore, our 2002 ongoing earnings would have been $3.56 per share in 2002 compared with approximately $4 in 2001. The decrease in our operating earnings was expected. We've been discussing the major factors affecting 2002's operation since the third quarter of 2001.

Principally, lower contributions from power marketing and trading offset in part by the absence of the reliability cost occurred in the summer of 2001. As we've progressed throughout the year, we discussed our improved results at SunCor and APS Energy Services as well as other factors that affect the earnings comparison, such as customer growth and weather decreases.

Before I turn the call over to Don, I would like to talk to you briefly about NAC and SunCor. Regarding NAC, as we have already disclosed, we recorded losses in 2002 totaling some $36m after tax, or, as I said, 42 cents a share, that are primarily related to contracts with two customers. We work closely with NAC to identify and quantify the issues in and have recognized our expected losses on these contracts, the majority of which relates to a contract with Main Yankee power company that was terminated in mid-January.

We believe we have reserved our exposure with respect to these contracts in all material respects. As a result, we consider these charges to be nonrecurring. Furthermore, although we currently do not expect NAC ongoing operation to have future adverse impact on the result of our operations, we will continue our assessment of NAC, and I can't guarantee that NAC won't have any future losses.

SunCor was a success story in 2002. As a result of SunCor's accelerated sales asset program that was announced in October and will be carried through 2005, SunCor reported earnings of $19m in 2002, and remains on track to approximately double its earnings in 2003 and maintain that level in 2004 and 2005. We also anticipate SunCor will distribute cash to the parent this year, totaling approximately $80m to $100m. We expect that contribution annually in both 2004 and 2005.

At this point, I'd like to turn it over to Don to review our detailed earnings variances.

Thank you, Bill. My comments this morning will cover the more significant earnings variances for the fourth quarter and the year. In addition, I will update you on several relevant topics, the economic outlook for Arizona, pension expense, and pension funding requirements for 2003, mark to market balances and expected roll-offs, our risk management efforts, and liquidity.

I remind you that extensive detail and analysis of earnings variances is available on our website, and after this call, Becky and Lisa will be available to assist you in navigating through the website's financial detail. Any time I refer to per share effects, those represent diluted earnings per share, and unless otherwise noted, my references to dollar amounts of revenue, gross margin, and expenses represent before tax effects.

Turning to our fourth quarter results, the company reported a loss, before an accounting change, of $15m, or 17 cents a share for the fourth quarter of 2002. This compares with income of $36m, or 42 cents a share for the fourth quarter of 2001. Bill has already discussed the various nonrecurring charges affecting our 2002 financial results. The impact of these charges in the fourth quarter totaled 70 cents per share, which consists of 8 cents per share for severance charges, 35 cents per share attributable to the Red Hawk unit cancellations, and 27 cents per share related to NAC charges.

Fourth quarter electric gross margin was $370m as compared to $344m in the fourth quarter of last year. The marketing and trading business was responsible for substantially all of the $25m increase. The M&T group had increase sales at APS Energy Services of $7m, increased generation sales of $6m, lower mark to market reversals of $8m due to the adoption of EITF 0203 and the absence of a 2001 charge of $8m related to prior period mark to market Enron contracts.

Gross margin from our regulated electric segment was, essentially, flat. The benefits of fewer unplanned plant outages, lower replacement power cost, and the absence of 2001's $13m Enron related charge were offset by higher hedge gas and electric prices and electric rate reduction in one of the warmest winters in many years.

SunCor contributed $14m of gross margin reflecting a $5m improvement coming from increased asset sales. On the expense front, in addition to nonrecurring charges, O&M expense was higher as a result of higher pension and OPEC cost, the commencement of Red Hawk unit 1 and 2 operations, and other miscellaneous costs.

Now, returning to results for the year 2002. 2002 electric gross margin totaled $1.65b as compare to $1.72b in 2001, for a decline of $73m. The regulated electric segment added gross margin of $112m or 79 cents per share. Lower replacement power costs, combined with fewer forced outages, added $127m, or 90 cents per share.

Growth fueled by more than a 3% increase in customers added $38m, but was more than offset by retail price reductions totaling $28m, and a $27m negative impact from milder weather. Gross margin of $132m in our marketing and trading business reflects a decline of $185m, or a $1.31 per share.

The majority of the reduction in margin in the M&T group is related to decreased power prices and liquidity in the western whole sale markets. Specifically, lower generation sales of $66m, and lower trading activity, net of mark to market reversals. For the year, SunCor contributed about $31m, or 22 cents a share in gross margin, reflecting an increase of $16m, again, primarily due to increased asset sales.

Regarding 2002 expenses, other than the nonrecurring items, the elimination of 2001's portable generating units reduced O&M expense $30m, while commercial operation of Red Hawk 1 and 2 increased O&M expense and depreciation expense by $4m and $12m respectively. Regulatory asset amortization declined $30m as prescribed in the 1999 regulatory settlement with the Arizona Corporation Commission.

Turning to our economic outlook for Arizona in 2003, we expect Arizona's growth to accelerate modestly as national economic conditions improve. Estimated population inflow should remain steady at 2.8% to 3%, and will support continued demand for housing as job growth returns to positive territory. The weak real estate sectors continue to be in the apartment and office markets. Manufacturing, particularly the high tech sector, appears to have stabilized. However, we don't expect new sizable investment in 2003.

We previously indicated that customer growth has slowed, compared to our historical growth rates of approximately 4%. We closed 2002 with customer growth at 3.1%, which is still a very strong, three times the national average. Going forward, we expect customer growth to continue at about 3.5% to 4% annually through 2004. We estimate annual retail kill watt hour sales growth of 3.5% to 5.5% through 2004.

Regarding pension expense and related 2003 funding requirements, the company's cash pension contributions for 2003 are currently projected to be approximately $50m, which is at the lower end of our previously disclosed range of $50m to $80m. This current projection is still somewhat preliminary; however, it is based on actual investment returns for the year 2002.

As you well know, the combination of falling interest rates and adverse investment returns in recent years has created a difficult environment for pension plans in general. In 2002, the company booked approximately $27m of pension and OPEB expense. We now estimate pension and OPEB expense to be $56m, reflecting an increase of $29m.

Turning to a discussion of mark to market issues, as you know we implemented EITF 0203 in the first quarter of 2002. As a result of the switch to accrual accounting, we estimate earnings in the next several years will benefit by 15 cents per share. At December 31, 2002, the accumulated mark to market balance of net gains was $41m. We estimate that the future realized gains, or roll off, will be $4m in 2003, $10m in 2004, and $27m in 2005, and years thereafter.

Now, turning to our risk management efforts, actively managing our fuel and power risk, continues to be a key focus of our marketing and trading group. For 2003 and 2004, we have hedged over 80% of our projected natural gas supply to meet native load requirements and are substantially hedged on all our needs for the next six months. Pinnacle West as a whole has sufficient generating capacity to support a 20% reserve margin for the summer of 2003.

With respect to managing our credit risks, we continue to take steps to manage our exposures to non-investment grade counterparties, particularly those that we believe are susceptible to further downgrades or default. More than 90% of our total counterparty exposure is to investment grade companies. After considering collateral held by us which constitutes cash and letters of credit, the $18m uncollateralized exposure to non-investment grade counterparties is less than 4% of our total counterparty exposure. Approximately two-thirds of this exposure rolls off within the next 12 months.

Finally, turning to liquidity and capital structure, and starting with APS, we expect the utility to fund substantially all of its capital expenditures with net cash flow from operations. At year-end 2002, APS had no short-term debt and was in a slightly invested position. APS should remain in a strong liquidity position through 2003.

Pinnacle West ended 2002 with short-term debt balances of approximately $100m. During 2003, we will increase our short term debt balances as we complete the construction of west Phoenix five and continue the construction of silver hawk. Pinnacle West should end 2003 with short-term debt balances slightly higher than the beginning of the year, assuming the successful completion of the $500m inner company loan financing.

We have planned for the repayment of the following soars of maturing des, $225m of Bank Bridge debt that comes due July 30, 2003, the $250m of floating rate notes that come due August 1 of '03, and $25m private placement notes that come due December 17 of '03. In addition, Pinnacle West has $215m of 4.5% notes that mature in early February of 2004.

In terms of capital structure, Pinnacle West actual debt to capital ratio was 56% in September 2002, excluding the Palo Verde tool sale lease back. We expect our year-end 2002 reported debt ratio to have improved to approximately 54%.

I'll now turn the call over to Jack.

Thank you, Don. This morning, I'm going to provide a brief update of our regulatory developments with the Arizona corporation commission and give you a summary of our 2002 operations. As Bill mentioned earlier, we are at our core a vertically integrated electric utility. With that business, comes the challenges of working with regulators and interveners.

The year 2002 was quite a year from a regulatory stand point. As the commission reversed its generation regarding divestitures and requires APS to keep its existing units. There are currently five regulatory issues of note pending in development. Our appeals in the track A order, the track B proceedings, our pending $500m financing application, the proceedings to establish rate adjust meant mechanism for purchase power, and the general rate case we will file by midyear.

As many of you know, the commission voted last summer in its track A order to change the direction on the rules adopted in 1999. Among other things, the track A order stopped a previously required transfer of APS generation assets to an unregulated affiliate and changed the bidding requirements for power purchases. That order is also inconsistent with our 1999 regulatory settlement with the commission.

The track A decision redefined APS as a traditionally vertically integrated utility with 4,000-megawatts of rate based generation assets. It established for the time, that 1800-megawatts with the power plants in Arizona, Pinnacle West Energy, made competitive bid to provide energy to APS, at least until the commission decides where those should be included in the APS rate base. Following the ACC's denial last October of our request for them to reconsider the track A decision, we filed appeals with the Superior Court in Arizona and the Arizona Court of Appeals.

In December, we agreed with the ACC staff on principles resolving issues with the track A appeals. The principals for resolution establish an important agreement between APS and ACC staff that would be appropriate for the ACC to consider three matters in the upcoming rate case. First, the generating asset to be included in APS rate basin including the question of whether the Arizona currently owned by Pinnacle West Energy should be included in the APS rate.

Second, the appropriate treatment of the $234m write-off we agreed to as part of the 1999 APS settlement agreement. Third, the appropriate treatment of costs APS has incurred in preparation for the previously recorded transfer of APS's generation assets to Pinnacle West Energy. We further agreed that we would voluntarily limit issues of appeals in track A decision and the three issues. To those three issues, upon issuance of a final decision, it is no longer subject to appeal. Approving the $500m application with appropriate conditions.

Under those circumstances, we also agreed that we would first present the three issues to the ACC for consideration prior to me attempt at judicial resolutions of such issues. We believe the principal for resolution are a significant step toward consideration by the ACC of these critical issues.

Let me now turn to track B. Track B is the portion of the ACC's generic proceedings on electric that is addressing procurement requirements for purchase power. Following a series of workshops involving us and various other interested parties, the ACC staff prepared its report and recommendations on track B. On the staff proposal, we believe APS will be required to competitively bid about 2500-megawatts of peak capacity this summer.

Most actual procurement decisions will continue to be at APS's discretion. For example, the procurement process was an RFP, the products to user with a block or system type of bid, contract acceptance and contract durations. The staff also proposes that Pinnacle West would be able to bid. As proposed by the staff, the track B procurement process would involve staff and an independent monitor.

The commission held a hearing on track B issues in late November, and we received the administrative law judges' decision last Thursday, January 30. The target is March 1, 2003 for the process to begin. However, the ultimate date for beginning the process will begin on the timing of the commission track B decision. The ACC has schedule an open meeting on Friday, February 21, to consider the track B issues. This schedule came out last night around 5.00.

Our preliminary review would indicate that the ALJ's recommendation basically adopts the ACC position. However, the recommendation is still being analyzed. We do have some concerns about apparent inconsistencies. We intend to sleek clarification on the issues and the recommendations which we'll be filing on February 10.

The next issue is the pending financial application. We have a $500m financing application pending with the ACC related to the to the finance of the unregulated generation assets. Stated simply, we are asking the commission to enable us to complete financing the plants with the same creditworthiness that would have resulted from the implementation of the APS's 1999 settlement agreement in accordance with the original terms.

The loan and our guarantee would be used to finance the bridge that occurred, to fund Pinnacle West to serve APS's retail customers in Arizona. The commission held a hearing on a financing application in early January. The ACC staff has recommended the commission approve APS's request subject to several conditions which are generally acceptable to us. These conditions were described in an 8-K filed in mid-December.

We currently expect a recommendation from administrative law judges around the first part of March, which is consistent with getting commission approval in the first quarter. Furthermore, the commissioners have previously expressed interest in dealing with this matter in a timely manner.

Now, leading to adjustment mechanisms. The final matter that's currently pending before the ACC is a rate adjustment to allow APS to recover power supply cost, cost associated with complying with ACC competition rules and the cost of the ACC mandated benefit programs, such as environmental portfolio standard. We filed our proposed the design of the mechanisms with the commission last year, and a hearing on this matter is scheduled to begin April 2. The implementation of the adjustment is part of the general rate case the APS is required to file by June 1 of this year.

Turning specifically to the general rate case we'll make by midyear. Through this filing, we expect to seek to recover costs we have incurred in complying with the ACC competition rules and our agreement as a result of the track A decision. Consistent with the principles for resolution of track A issues, we expect to file for the rate case of our existing regulation in Arizona, recovery of the $234m write off, and recovery of costs of complying with ACC's electric competition rules. Including those we prepared to transfer APS generation to Pinnacle West Energy. Of course, we'll update our cost of service and rate design.

We have assumed that a decision on the 2003 rate case will be made by the Arizona Corporation Commission by the end of 2004. Finally, on the topic of issues related to the Arizona Corporation Commission, it expanded from three commissioners to five effective January 6 of this year. We now have five Republican commissioners. They are Jeff Hatchmiller and Mike Leeson. Both were former state legislators and have some experience related to the energy industry.

Thus far, both the new commissioners have been working hard to understand the issues they will be facing at the ACC. Also in the last election, Jim Urban was elected to another four-year term, after which he will be term limited. In a recent event, Mark Spitzer was elected replacing Bill Mundell. We have a track record with the commission and will do our best to continue working with them effectively.

Let me turn to operation review for 2002. In terms of operation, the year 2002 was a successful year if our in our energy operations despite western wholesale being down 75% from the levels in 2001. We continued our focus on operational excellence and efficiency. In mid-2002, we announced a voluntary workforce reduction as part of our cost reduction program and recorded several charges of about $36m pretax during the second half of the year. We expect to see these operating savings from our overall cost reduction program in the neighborhood of $30m pretax beginning in 2003.

The whole sale power market in the west continues to provide opportunity for our power marketing group and our unregulated generation. Our focus is more on the risk associate with power sales and procurement. We see reserve margins in the southwest in the 15% to 20% range in the next several years.

We continue to see significant growth in our retail service territory which we met reliably in 2002. It grew 3.1% and the demand was 1600-megawatt are or 2%, to a new record for the company. Our power plants performed superbly. The plant at Palo Verde was 94.4%, which continues to compare favorably with the national average around 90%. Similarly our co-plants operate at 80%, again well above the expected U.S. industry average of 65% to 70%.

This steam for Palo Verde have arrived and we're preparing for this fall, during which we will replace the generator with the new one. We expect it to fall 75 to 80 days long, compared to normal refueling of 36 days. We bought more than 1100-megawatts of new generation on line at Red Hawk, on time and on budget, primarily to meet our growing energy needs for our customers. The construction of West Phoenix Five of 530-megawatt plan remains on track for commercial operation this summer and construction of you are 570-megawatt plant in Silver Hawk, Nevada is progressing to a summer 2004 start date.

Transmission remains a hot issue in Arizona and the west, in general, and throughout the country. In Arizona transmission to the major load centers is limited and can, on occasion, be constrained in delivering power from new power plants. We are building a 500 KB line to the southwestern edge of the metropolitan Phoenix area, which is critical to insure reliability to our customers this summer. We also have other significant transmissions planned in the next ten years to keep pace with increasing customer demands.

On the regulatory front, we are active leaders to form West Connect, the southwest RTO which received a favorable preliminary declaratory order is now in the task of development phase. We also plan a key role in the west side effort known as seam steering group of the western inner connection. To resolve seams issues between the three RTOs, in the west and develop a business among the RTOs for a smooth transition to wholesale competition.

Finally, we have been frequent and passionate contributors to the nationwide debate on market design, which is SMD, a proposal we believe is seriously flawed in its present form in which FERC is now reconsidering. In summary, I am very proud of our operation performance, and we will continue to work with our regulators to constructively address the regulatory issues. That concludes my prepared remarks.

I will now turn it back to Bill.

Last week, we announced that Bill Stewart will retire in December. We will miss him in our day to day operations. However, we'll continue to reap benefits from Bill's input as a Pinnacle board member. The depth of management has been under Bill's report, Jim Levine has been a with responsibility for Palo Verde for a number of years, then with responsibility for all of the fossil will plants as well. I'm confident in Jim's leadership for our generation float, both regulate and that currently unregulated as we continue to consolidate our generation necessitated by the track A decision in 2002.

Marketing and trading unit is being relocated to APS but will may under the guide an of Dave Hanson, who in turn will report to Don Brandt, Chief Financial Officer. Don had responsibility for marketing and trading at Amron prior to joining us at Pinnacle West.

Next, I'd like to review our financial outlook with you. Don has discussed our liquidity. I'll discuss the earnings and dividend outlook. The recently updated our earnings guidance for 2003 and stated we expect our consolidated earnings per share to be within a reasonable range of $3 in 2003.

Let me explain a little bit what I mean by reasonable range. As you know, we have not historically provided explicit earnings guidance because we believed and continue to believe it may be misleading to do so, particularly with the changes in our industry. I believe the directional guidance is more appropriate at than single point estimates. Therefore, that is why we have described our estimates to be embedded in a reasonable range.

As Don has described, we estimate the net income for 2003 in our regulated utility business will be favorably affected by the benefits of strong customer growth of 3.4% and lower operations and maintenance expenses resulting from our cost reduction program that Jack discussed from 2002.

We expect the positive factor will be offset by natural gas price for our power plants related to the hedging of gas volumes in 2003 and 2004, higher operation and maintenance expense related to pensions and other post employment benefit and higher purchase power prices, as well as the impact of the 264 basis point differential proposed by the ACC staff and the application partially offset by the effects of recorded trading on the accrual method in accordance with EITF 02 - 03.

On a per share basis, the year to year comparison will been affected by 6.6 million common shares late last December. We realize that our dividend is a very important characteristic for our company, and we're proud of our record of paying dividends to our shareholders. Over the past five years, we grew our dividend at an average annual rate of 7.2%, ranking us number 1 in the industry. We will continue to put strong emphasis on you are dividend with future levels and growth for our dividend based on a number of factors relating to financial market conditions.

In summary, from an operational standpoint, we had a very good year in 2002. We demonstrated all aspects of our core business. We reliably served the needs of our customer base which grossed three times the national average. We ranked in the top quartile nationally for customer satisfaction. Our power plants operated efficiently, well above industry averages.

We continue to focus on cross management. We have been successful in managing our regulatory challenges over the last decade and we 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 our regulated business, maximizing the value of you are unregulated business, and managing the overall risks of our company.

I appreciate our patience in listening to what certainly has been a fairly long prepared remark discussion here this morning, but we felt it very important to give you as much information as we can, not only about 2002 but that information about 2003. That concludes our prepared remarks. We'd be glad to answer your questions.

At this time, I would like to remind everyone, if you would like to ask a question, press star, then the number 1 on your telephone key pad. We'll pause for a moment to compile the Q&A roster.

Your first question comes from Andrea Feinstein with Angelo Gorman.

Hi. Just a couple quick questions. First on the NAC review. You mentioned that it's still ongoing. Can you give us parameters as to if there is a capped total exposure that you see for Pinnacle West from NAC and some sense of timing as to when that review might be completed? Then could you also address the current state of negotiations with Main Yankee regarding that contract.

First, as I said, we are comfortable that we have reserved what we believe to be the costs associated with those two contracts. As we look forward, we do not see any significant additional material losses coming from that. As I said earlier, from our stand point, as we look at the future there in terms of NAC, again, given the reserves we have taken, we're comfortable based upon what we know today, that that covers any anticipated losses.

Now, with that, as I said earlier, I can't guarantee you that we might not have some going forward, but based upon, as we look at it today, we do not anticipate any future material losses. As to the discussions ongoing with the customers, that's not something that I can really speculate about. We are having discussions and we expect to continue to do so.

Okay. And just one follow up on my first question and then a separate question all together. You did mention specifically that you are continuing to review the NAC business as a whole. Is there a sense of the time line for completion of that review so that you can come back to us and say, you know, we've, basically, locked at everything and we feel comfortable we have our arms around everything incremental to those two contracts?

Well, as to those two contracts, as I said, it's going to be an ongoing process

I'm sorry. Maybe I was unclear. I mean related to the rest of the portfolio absent those two contracts.

I think that's an ongoing process

Separately from that, within the 25-megawatts you expect to competitively bid, can you remind me how many megawatts are related to must run type units and give me more clarity on how you see that plague out as a part of the track B?

Sure.

Yeah. Of the 2500-megawatts, somewhere in the neighborhood of 400 to 600-megawatt been would be reliability must run. Because of the must run it deems it wouldn't have competition. That's one of the things we're trying to clarify in our exceptions

Okay.

Your next question comes from Greg Gordon from Goldman Sachs

Good morning, guys. Two questions. First on the regulatory front. You have a lot of issues pending. Has there been any formal indication from the commission at this point whether they were going to head down the path of going to a commission decision on all these issues or if there's a chance, at this point, for some sort of settlement on one or more of those outstanding issues?

Well, let me address it first, Greg. Then, I'll ask Jack to do the same. We're in a situation, as you well know, where we've got, as you mention, a lot of issues before this commission. I think it's going to be very difficult to try and achieve any kind of settlement in the near term there. Certainly, that's something from our stand point we would like to see at some point and it's something we've had significance success within the past.

But, from my stand point, as we go through each of these issues that Jack mentioned, each of the five areas, the level of detail in each of these is such that I think it's going to take more of an approach that is outlined procedurally as the commission has dealt with these. So, at least from my stand point, although eng there's always an interest to do so, I couldn't tell you that I would expect a settlement in the near term.

Okay.

Greg, this is Jack. I have nothing to add to that. As I mentioned in my prepared remarks, we did receive last night a date for a resolution of the track B issues.

Okay. Great. Second question was, as we look at your overall guidance, which is the -- reasonable range around $3, is there an implicit expectation of an ongoing loss at El Dorado either from NAC or other assets that are still held there? Can you give us a review of what else other than NAC is still an investment?

In El Dorado there is no other significant investment around the NAC we've mentioned. As I mentioned before, we don't anticipate any future losses. Again, with the caveat, I can't guarantee that

Thanks very much.

Your next question comes from Terry Shue from J.P. Morgan

Hi, Bill. On the date for the track B, I missed that. When is that?

It is February 21

What date is that? That's the beginning of more hearings or when is the resolution on track B?

Terry, we have the preliminary ALJ's opinion that came out last Thursday. The February 21 date is to have a vote and resolve the issue

That's a decision date.

That addresses the various issues you've talked about, including, importantly, the write-off amount, the cost of deregulation, the purchase of power costs, et cetera, and whether or not the plans can be included in rate base. All those issues will be resolved?

The February 21 is just to track B, which determines the amount of megawatts we have to buy from the open market. The other items you mentioned, for instance, the adjustor, the hearing begins April 7. All the other issues related to rate basing the Pinnacle West --

Right. Those are part of the general rate case?

That's correct. That would be filed by midyear

Okay. So the only thing that the track B or the February 28 is with regard to the bidding?

That is correct.

And the bidding, is it just for this coming summer, or is it for going forth?

Well, the way the order is written, it is up to us. It would be for several years. We're trying to determine what several years means

As you said, the ambiguity is exactly what it means, must run part of the recovery, et cetera. Is there a risk in terms of not being able to recover your purchase power cost as it applies to the current year?

The fuel and purchase adjustor hearing that will be heard on April 7 is a recovery of cost that is are incurred after the '99 settlement elapses

Okay. So, when does a decision on that come out? I get the dates a little mixed up? If it comes out after the summer peek, peak months, how do you decide as far as recovery? It's a post 2004 amount?

Yes. It is a post 2004 amount. As it relate to a decision, with the hearing being April 7, I think we would be lucky to get a decision within a six-month time period

Really, the summer months for this summer, it's really not at issue?

That is correct.

Sorry about the confusion. With all the different dates and different tracks. Okay. Thank you.

Your next question comes from Philson Yim with Morgan Stanley.

Good morning. Could you talk about the earnings contribution on unregulated assets out there, also about the economics we're seeing in the region, so forth.

Sure. Relative to the power marketing group, we've started to see, in the last two months, power prices firm up somewhat in the west, and we're anticipating, anxiously anticipating developments in the summer. I think we have some unique opportunities. Obviously, credit is an issue and a lack of liquidity in the market.

Conversely, transparency has disappeared, and we think that will contribute to widening margins. It's still pretty speculative going forward over the next year as to how we see developments in the western power markets, but we think we're positioned pretty well as asset back trading organization. That wasn't too fashionable two years ago, but it is today. We're optimistic going forward, but cautiously optimistic

Okay. And maybe you could talk about with the auction slated to start here shortly. If you see any other competitors. You think Pinnacle West Energy, do the unregulated assets have the competitive advantage in that auction?

We think price wise they're extremely competitive and positioned well geographically. There will be other competitors in there. There are pluses and minuses to both sides. We think we're positioned pretty well going into it

Remind me which of the assets.

This is Jack. The assets of Pinnacle West Energy in the load pocket are Phoenix cycle No. 4, which came into service in the summer of 2002. And then West Phoenix Five, which will come into service this summer

Great. Okay. Thanks very much. Good luck, Bill.

Your next question comes from Vadula Verde with SAC Capital.

Good morning. How are you? Let's see. A couple things. In your comment, you indicated as part of the outlook, SunCor was going to, from its roughly $20m this year, you said it was going to double in '03 up to $40m and stay there for '04 and '05?

That's right

Can you give us a sense as to with energy services now being a material contributor here, what its outlook is now going forward building off of the $28m that was in this year?

As you've mentioned, we had a very good year with energy services, and in terms of our guidance, included in the $3 guidance, we've been conservative about what we think energy services could do. Specifically, we're in the range about half of that in 2003. So we've been pretty conservative there. Although, when you look at the opportunities that energy services has, we think that they remain pretty strong, but we've been pretty conservative in our financial estimate.

Okay. And if we take a look -- I want to follow up on Bill's question. You went through a series of items, most of which have to do with the utility, when you talked about the, directionally speaking, for, you know, reasonableness range of $3. For Pinnacle West Energy, what do you really consider the operating net income, then, for 2002 after removing charges and kind of what's the kind of view there within your reasonableness outlook?

Well, when you look at the total picture I described back in October where we had about 90% of our earnings coming from the regulated business at about 10% from all of our unregulated businesses. Given a range around that in terms of percentages, that's something that we see going forward.

All right. I think what I'm trying to get at a little bit more specifically is if we were to consider the write-offs for the Red Hawk unit that would end up getting Pinnacle West Energy back into the black, at least for 2002 on an operating basis. I'm wondering, directionally speaking and if we go into 2003 with that business line specifically, what kind of trend are you looking at?

Well, the best way I can answer that is to say we have put together our total forecast that is founded on the forward curve, and to go beyond that, it gets us into the situation of trying to estimate what the bid price is going to be at Pinnacle West Energy and how that's going to calculate into earnings at Pinnacle West Energy. If you look at our total company and predictions and projections we have put on the table, they're, basically, around that forward curve assumption, and so any calculation beyond that would be something we wouldn't want to get into with Pinnacle West Energy

One last question. You talked about the fuel and purchase power clause put back into place here and you'll be having hearings in April with a decision towards the end of the year. Given the cost you said of our various hedges and everything like that that have been hurting results. If you were to get an adjustment, what kind of an increase or deferral do you think is implicit in that at this point, and is that the proper way to be thinking about it?

As I stated earlier, the fuel adjustment hearing that begins April 7 are for those costs that incurred after the settlement agreement expires. It would be have any impact on the costs incurred in 2003. And the hedging, I think that Don mentioned in his prepared script was addressing 2003

I mean, is the proposal such that there would be any kind of a, you know, dead band and above that would there be an exposure company, or is it a full pass through kind of an old fashioned kind of purchase adjustment clause?

I don't know if it's old fashioned or not. The adjustment clause is one that has a base number in it. We have to periodically go back and request from the commission to change that base number. So it is not an automatic pass-through. It is kind of an adjustor where we have to go in on periodic dates and justify any adjustments to the base amount

Okay. Thank you very much.

Your next question comes from Scott Pearl, Credit Suisse First Boston

I was wondering if you could just give us a sense for how recent changes in western power prices and in spreads interact with the portfolio that you have as it relates to any long position in the shoulder out of the coal or ultimately spark spread exposure in the summer period, and with regard to the current forecast, when is that based upon the most current curves, or have you taken something that was from a period back when you announced it in October?

Okay. Let me try to go at that a couple different ways. First, if we look at 2002, I think it's important, and I would point people to the website to take a look at our off system sales, the sales for nonnative load customers. We had an increase in volume in the number of sales this year over the previous year. What we saw was a huge decrease in the average price. It went from about $110 a megawatt hour to $28 a megawatt hour. Producing for us gross margins that were down two-thirds from what we had in 2001.

So, when you look forward, in terms of the prices, it's very critical in terms of our performance. There are factors that are very significant, and, as I mentioned in terms of an earlier question, we, basically, have put together our projection on the basis of a forward curve, actually given from when we did it, the forward curves would come up a little bit since then as Don mentioned. From our stand point, that is a significant factor. As to the specifics in terms of the power marketing contracts, I'll turn it over to Don.

Relative to the contracts we have in place, we're pretty well hedged into our profit positions, and for those contracts we won't see, assuming market prices continue to firm up, a big upside. It will give us a big opportunity to trade around those positions going forward. More importantly, it will give us more opportunities in the market with additional customers and our counterparties.

Okay. Thank you. Also, you talked back in October, you just gave a broad brush sense for prospects in '04 being up on the order of 10% or so relative to '03. Do you stand by that previous statement or is there any change that's happened over the past couple of months that impacts your outlook on some of the factors that drive '04?

As to the factors in '04, they're still the ones I talked about in October. I would tell you that as we deal with many of these regulatory issues, trying to predict '04 becomes pretty difficult. As we get into the base rate case and when we come back in April, I'll be able to give you a better sense on '04. Trying to predict '04 is difficult to do.

Thanks, Bill.

Your next question comes from Zack Schreiber from Duquesne Capital. Good morning.

Good morning. I wonder if you could talk about, in general, what kind of spark spread assumption you're looking at at Pinnacle West Energy. We've kind of danced around it all during the call. Just in general are the sparks spread you're locking at for this guidance done in the mid-December time frame? Are we looking at sort of mid-to high single digit spark spread for the PWAC assets?

The spark spreads that are forecast based upon are back in the fourth quarter of '02. I don't remember the exact number. I can tell you since that time period, that have continue to flatten. Power prices have gone up, gas have gone up already. All peak spark spreads have widened. In other words, there's more period in the off-peak period than the on peak period as we see it today.

Is the on peak 5 by 16?

The on peak is classic 6 by 16.

I was just wondering if the $3 number, give or take, has any assumptions in it for lost margin related to competitive bidding from track B? Either at the APS level or effectively at the PWAC level?

As I said, we have, basically, used the forward curve as the basis for the market, and to the extent that you would calculate a lost margin, that would be offset by sales into the market. So, from our stand point, we have predicated the total forecast for the company based upon that forward curve

I agree with that, Bill. I mean, there's a definitely a margin differential between, effectively, the generation rate embedded in your rates in the low 40s, to wholesale prices, even in the upper 30s on the back of higher gas prices. I'm just trying to understand if there is any assumption from margin erosion from the track B embedded in this conservative $3 number?

If I understand what you're saying about margin erosion, the short answer is no.

So, you don't assume that you lose any load in this competitive bidding? You assume that?

No. I didn't say that. What I said is there's no margin erosion. That's different than loss of load.

So, what you assume is through a combination of whatever megawatt hours you lose, whatever the margin is that's associated with megawatt hours that you allows, you'll be able to recreate that margin through a combination of increased off-system sales and trading market opportunities?

More or less. That's the assumption we have, yes

Okay. Great. Thank you.

Your next question comes from Steven Fleishman Merrill Lynch

This question has been asked a couple different ways already. Just to fill out the picture. We have an environment in the west where gas prices have risen up and it's driven power prices. Your system sale could benefit from the higher prices. If we focus back on gas, if gas stays here at $5, what does that mean for the '03, '04 period? You said you have 80% hedged for '03? What does it mean if it stays this high '03, '04?

Let me go back a little bit back to October, and I'll turn it over to Don. You'll recall what we talked about in October was we were looking at about a $20m increase in gas prices '03 over '02 as a result of, at least in that time, money hedges. For the most part, the hedges are now in the money. So, in terms of the estimate from what we had in October to where we stand today, those hedge positions have actually improved as a result of this increase in terms of the overall price. Don?

Just to add to that, Steve, as Bill mentioned, with our position on gas, going forward with the movement in electric prices, that's very positive. If that trend continues, we're in a position to capitalize on it. Part of the uncertainty going into '03 and '04 is around the western power markets. On the one hand, we see prices firming up, depending on what happens in the summer out here. It is potentially on the positive side.

However, the concern in the back of our mind is the liquidity issue with some of the players. We have the potential to lose a number of the troubled companies over the next year or two. That will put a real dent into overall market liquidity, which is important for all the participants. So, it's trying to balance those negatives and positives. It's fairly uncertain, but I think our downside is relatively minimal, and we're positioned to take advantage of an uptick in the market, if it comes about.

Okay. Thank you.

Your next question comes from Tom O'Neill with Lehman Brothers.

I was curious if you could describe in more detail what's left at NAC and what prevents you from winding that business down?

As far as other contracts at NAC, the two contracts we've talked about are contracts that deal with the movement of spent fuel from the spent fuel pool to the above ground storage. The other contracts -- those are the only two contracts at NAC that are like that. The other contracts at NAC, for the most part, are equipment contracts and consulting contracts. In terms of the composition of the contracts, that's basically the total portfolio at NAC.

I take it the equipment contracts and consulting are in the money which keeps you from winding the business down?

They are in the money.

The second question, with regard to the February '04 maturity, how do you look to refinance that? Assuming the $500m is granted per the staff recommendation, how much debt are the rating agencies comfortable allowing you to carry at the level in investment grade ratings?

I think our presumption or going forward position is we structure that with debt issuance at APS and the inner company alone, and or the alternative fallback position is the APS guarantee of parent company debt. Either way, I think under either of those scenarios, the rating agencies are comfortable as we stand today.

Okay. Just to clarify. You have a fair amount of short-term debt you're going to take on in the middle of this year?

Yes.

At the parent level. Then you have the February maturity. After that February maturity, you'll have about $300m of debt left at the parent level?

Yes.

How much -- are you saying you're not going to put any more debt there?

That's correct.

Okay. Great. Thank you.

If you don't mind, let me add one thing to what Tom's question was. As we talked in the past, one of our principal goals is to reduce our debt level. As we talked to you, it's to move it down to the 55% level over the next few years. That remains a significant goal for us, and we are on track to do that. Sorry for the interruption there.

Your next question from Paul Patterson with Glen Rock Associates.

Good morning. I wanted to touch base with you on a quick question. How much common equity was at the utility at the end of the year?

I don't know that off the top of my head. I'll get it for you while you're asking the second question.

The second question is, I know that there's a lot of things that go out of the regular -- the calculation for regulated ROE. I was wondering if we have any better idea as to what that might be when you file in the middle of this year? Basically, that's the idea I'm trying to get, what you've been earning on a regulated basis at the utility as far as ROE is concerned?

As far as the utility is concerned, the assumption that we had in the '99 settlement agreement was 11.25%. When we put together our rate case, we'll put together a number that, basically, looks at those levels throughout the entire country. If you look at Arizona in particular, as you well know, given the fact there's only really two major utilities here and it's been a while since we've had base rate cases. There is no track record for Arizona. There are no comparables, so to speak, in Arizona that you can use. We would be looking across the country when we do that calculation.

If we get an idea about what 2002's are, do you think it's roughly in the area of 11.25% on a regulated basis?

It's in that neighborhood. The answer to your first question is 50/50

50/50?

Yes.

Okay. Great. Thank you very much.

Your next question calls from Charles Steadmetz with Steadmetz Research.

I have a really longish question, two parts. In the past you've said that you needed vigorous wholesale market to make your generation work. In view of the interest utilities such as APS in acquiring plants, bringing them into regulation, how do you see the wholesale market developing over the next several years, and how does this affect the possibility of PMW's sales above or beyond need of load?

As to the premise, as we talked in the past, we said that, really, the viability, long-term of the -- of any kind of retail competition is a function of the wholesale market, and as we have seen over the last 18 months, and as Don mentioned to you, the liquidity in that market has continued to decline.

So, as we look at the whole sale market, it's going to be spotty in terms of its development in area by area, and if you think about the fundamental policy that underlies this, we've got the driving force of FERC working with RTOs meeting some resistance in Congress. My personal belief is that any kind of legislation dealing with this subject is not imminent, and FERC will continue to go down the path of development with RTOs. We have, just as you see it across the country, we have states that are, more or less, supportive of wholesale competition, but, in some cases, not supportive of the RTO process that FERC has under way.

I could spend an hour talking to you about that question. It is a very good question. The best way for me to summarize it is I think it's going to be spotty state by state. I think it's going to be even less than regional in terms of its development, and I think individual state commissions are going to have an impact on that, just as the financial markets are going to have a significant effect on that as to whether or not there's going to be any capital to expand the unregulated, at least as currently described, the unregulated generation component. I would point out to you that although we're in a situation here in the southwest where we have a total reserve margin in the 20% range. 20% reserve margin is not significantly high when you compare it to historical levels of reserve margins.

Anyway, it's not going to take too much for that supply/demand balance to change, and if we don't find ourselves in a situation where new generations is going to be coming after 2005, which is the picture today. It locks like there's very little focus after 2005, we're going to continue to see a fairly volatile whole sale market. It is going to be spotty in terms of its development and volatile, which means there will be opportunities in individual markets, maybe not on a broad basis of a fully liquid whole sale market in the entire west, but in individual markets and pocket itself of load

and the second part, if this relates to Pinnacle? And your sales beyond your native load?

That's going to come back, basically, to what I just mentioned in terms of the positioning there for each of the markets. As you know, we would be filing in the spring a rate case that takes all the reliability assets in Pinnacle West Energy and requests rate treatment of those before the ACC. To the extent those assets are not rate based, we would be looking at markets here in the southwest

What assets in your filing in the spring, what assets would there be generating assets that you will not be requesting to put in rate base?

Only one. Silver Hawk, which is the one just east of Las Vegas.

Okay. Thank you very much.

At this time, there are no further questions. Are there any closing remarks?

I would just thank everybody for your time. We know it's a very busy time. We appreciate the interest you have in our company. We will continue to do everything we can to give you as much information about our company on a going forward basis, and I would encourage you to look at the website and see the kind of information that we've provided. Thank you very much.

Thank you for participating in today's Pinnacle West earnings conference. You may now disconnect.