桑普拉能源 (SRE) 2003 Q3 法說會逐字稿

Good day, everyone and welcome to the Sempra Energy third-quarter earnings results conference call. This call is being recorded. Today's presentation will be available for rebroadcast at 4:30 PM Eastern Standard Time, running through November 13th at midnight. You may access the replay by dialing 1-719-457-0820. Again, 1-719-457-0820 and enter confirmation code 655829. Again, that's 655829. At this time for opening remarks and introductions, I would like to turn the call over to the Vice President of Communications and Investor Relations, Mr. Dennis Arriola. Please go ahead, sir.

Good afternoon and thanks for joining us to discuss Sempra Energy's 2003 third quarter financial results. A live Webcast of this teleconference and slide presentation is available at www.Sempra.com under our investor section. With us today from the Company are several members of our management team, including Steve Baum, Chairman, President and Chief Executive Officer of Sempra Energy; Neale Schmale, Executive Vice President and CFO of Sempra; Don Felsinger, Group president of Sempra Energy Global Enterprises; Ed Guiles, Group President of Sempra Energy Utilities; and Frank Ault, our Senior Vice President and Controller of Sempra Energy.

Before handing the call over to Steve for today's financial and operating update, I would like to remind you that this call contains forward-looking statements that are not historical fact and constitute forward-looking statements within the meaning of the Private Securities Reform Act of 1995. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. Future results may differ materially from those expressed in the forward-looking statements. These risks, uncertainties and assumptions are described at the bottom of today's press release and are further discussed in the Company's reports filed with the Securities and Exchange Commission. With that, I'd now like to hand the call over to Steve, who will begin with slide 3.

Thank you, Dennis, and thank you all for joining us. Before I review the results of the quarter, I want to take a moment and give you an update on the fires that stormed across Southern California last week. In total, over 700,000 acres burned throughout Southern California. In the areas served by San Diego Gas and Electric and Southern California Gas Company, over 3600 homes were destroyed and 22 lost their lives, including a fireman. This was a very difficult time for our communities and for our employees and their families. Unfortunately, 11 of our employees lost their homes to the fires and hundreds of them were evacuated.

I'm proud to say, however, that during this time of crisis our employees continue to work around the clock to provide service and information to our customers and help repair parts of our infrastructure that were impacted by the fires. Over 1,700 transmission and distribution polls or lost or damaged in the fires. We have reconnected over 105,000 customers that lost power during the crisis. Our preliminary estimate of the Company's costs related to the fires is approximately $50 million, primarily capital expenditure. We expect to recover these costs through a procedure established by the California Public Utility Commission or CPUC, called the Catastrophic Event Memorandum Account, or CEMA. The CPUC has used the CEMA procedure in previous disasters and has held expedited proceedings in order to respond to cost recovery requests. I want to acknowledge the tremendous work done by all Sempra employees during this crisis, but especially the job done by Ed Guiles and his team at SDG&E and SoCalGas.

Now let's turn to our third-quarter results. Earlier this morning, we reported net income of 211 million for the third quarter of 2003, or $1 per diluted share, compared with 150 million in the same quarter in 2002, or 73 cents per diluted share. Third quarter 2003 results reflected several unusual items. Excluding these items, Sempra Energy's third quarter 2003 earnings were 232 million, or $1.09 per diluted share, an increase of 49 percent over third quarter 2002 earnings per share.

For the first nine months of 2003, Sempra Energy recorded earnings of $415 million, or $1.98 per diluted share, compared with 443 million, or $2.15 per diluted share, during the same period last year. Excluding the cumulative impact of EITF 02-3 and other unusual items identified on slide 3, Sempra Energy's earnings for the first nine months of 2003 were 466 million, or $2.22 per diluted share, up 10 percent per share over the 416 million, or $2.02 per diluted share, earned in the first nine months of 2002.

Now let's turn to slide 4, and I'll review the quarterly performance for each of the business units in more detail. For the third quarter of Sempra -- I'm going to slide 4, Sempra Energy Utilities. For the third quarter of 2003, Sempra Energy Utilities generated net income of 173 million compared to 102 million in the third quarter last year. Excluding usual items that added a net 28 million, the utilities earned 145 million in the third quarter, up 42 percent from the 102 million earned in the same period last year. For the nine month period, the utilities reported earnings of 354 million compared to 317 million in the same period of 2002. Excluding unusual items, the utilities earned 326 million for the nine-month period, up 12 percent from the 292 million earned for the same period in 2002.

Let's turn to slide 5. Net income for SoCalGas in the third quarter 2003, was 53 million, compared with 56 million in the third quarter of 2002. Third-quarter 2003 results include a $28 million after-tax charge for litigation costs and for losses associated with SoCalGas headquarters sublease. So on a comparable basis, SoCalGas reported net income of 81 million compared to 56 million in the third quarter of 2002. The increase is due to the recording of a $48 million pretax in incentives related to SoCalGas's gas purchasing for two award years ending March 31, 2002, partially offset by the loss of merger savings. From 1998, when Sempra Energy was formed, through 2002, both utilities benefited from sharing in savings from the merger.

At SDG&E, net income for the third quarter 2003 was up sharply to 120 million from 46 million earned in the third quarter of 2002. Third-quarter results include a $65 million benefit from the settlement with the CPUC of intermediate term power contracts and a $9 million charge for litigation costs. Excluding the unusual items, SDG&E earned $64 million compared to the 46 million earned in the third quarter last year. The increase was primarily due to the CPUC approval of 18 million pretax in incentives for SDG&E's distribution operation for the two years ended December 31, 2002, and higher electric transmission and distribution revenues. The two utilities currently have $53 million pretax and performance-based ratemaking incentives awaiting CPUC approval.

I'd like to provide you with an update and some other utility developments since the close of the quarter. Our cost of service proceedings for SoCalGas and SDG&E are moving along as planned. We substantially completed our portion of the evidentiary hearings last week and expect the intervenors to complete their portion this month. Under the schedule established by the assigned Commissioner, opening briefs should be filed on December the 5th, and reply briefs filed by December 19th. We still expect the final decision around the end of the first quarter of 2004.

On November 3rd, a CPUC administrative law judge released a proposed decision that would grant interim rate relief. The proposed decision, if approved by the CPUC, would authorize the utilities to create a memorandum account as of January 1, 2004, to record the difference between existing rates and those that are later authorized in the Commission's final decision in this case. The difference would then be amortized in rates. The proposed decision is on the CPUC agenda for December 4, 2003.

On October 8th, SDG&E filed its power procurement plan with the CPUC. The plan proposes a mix of demand response and local generation assets, including energy from renewable resources, to assure grid reliability in the coming years. If approved by the CPUC, SDG&E would purchase 635 MWs, including the approximately 550 MW Palomar Power Plant being developed by Sempra Energy Resources. This plant, which is fully permitted, would be developed by resources and sold to SDG&E on a turnkey basis. In addition, subject to satisfying certain conditions, the plan calls for SDG&E to sign a 10-year power purchase agreement for 570 MW of power from Calpine. The power procurement plan would put SDG&E back in the role of procuring electricity for its customers and add over 600 million to utility rate base. Public hearings on the proposal are expected to be held by the end of the first quarter, with a final decision anticipated in the first half of 2004.

On October 9, SDG&E filed an all parties settlement, which included the CPUC and the FERC's staff (ph), on its transmission rate case. If approved, SDG&E would earn a return on equity equal to 11.25 percent, with rates effective October 1, 2003 through June 30, 2004. The annual increase in revenues would be approximately $25 million, which reflects a 21 percent increase over current transmission revenues.

Please turn to slide 6, where we will discuss the results of Sempra Energy Trading. For the quarter, Trading reported net income of $22 million, up from the net income of $10 million in the third quarter of 2002. Excluding the litigation reserve related to pending FERC settlement announced on October 31st, Trading's earnings for the third quarter were 24 million. the remaining amount of the 7.2 million pre-tax settlement was recorded in the second quarter. If approved by the FERC, the settlement would resolve several elements of FERC's investigation of Sempra Energy Trading's participation in the western U.S. energy markets during the energy crisis. Excluding the cumulative effect of EITF 02-3 and the costs of the pending FERC settlement, Sempra Energy Trading's earnings for the first nine months of 2003 were 70 million. Trading's earnings for the nine months of 2002, excluding a 2 million extraordinary gain for the acquisition of metals, were $71 million.

Both commodity volumes and margins increased this quarter, with significant gains in power and oil trading margins. Our focus continues to be on a short dated portfolio. As of September 30, unrealized revenues from over-the-counter sources were approximately 303 million, of which 86 percent will settle over the next 24 months. At September 30, trading also had 225 million in marketable energy inventories on its balance sheet, which will be delivered and converted to cash by mid 2004.

Now please turn to slide 7 and I'll give you an update on Sempra Energy Resources, our generation unit. Resources reported net income of $33 million in the third quarter 2003 compared with 29 million in the third quarter 2002. The increase in net income was due primarily to the positive contribution from the operations of Twin Oaks Power, the coal-fired Texas power plant that Sempra Energy Resources acquired in November of 2002. During the quarter, Sempra Energy Resources delivered 2.6 million MW hours of energy to the California Department of Water Resources under our long-term contract with the CDWR. This contract has been upheld by the California Superior Court and the Federal Energy Regulatory Commission.

In addition, on September 30, an arbitration panel ruled in favor of Sempra Energy Resources in a dispute with a subsidiary of Occidental Petroleum, the co-owner of our Elk Hills facility, that asserted a right to participate in our CDWR contract. These favorable legal and regulatory decisions reinforce our expectations that Sempra Energy Resources will generate predictable earnings and cash flow into the future. Sempra Energy Resources now has over 2000 MW in operation, with an average of 85 percent of our capacity hedged through 2005, and 82 percent through 2010. The second phase of the Mesquite Power Plant in Arizona is ahead of schedule, and is expected to be operational by mid-November, adding 625 additional MWs to our portfolio. Construction of the 550 MW Palomar Power Plant will move forward once the agreement to sell the completed plant to SDG&E is approved by the CPUC. Construction of the plant is expected to be complete in 2006.

Turning out to slide 8, Sempra Energy International reported a third-quarter net loss of 32 million compared to net income of 13 million in the third quarter of 2002. The net loss was due to a $50 million after-tax impairment charge for the write-down of the carrying value of assets of Frontier Energy, a small natural gas distribution company. In addition, a 3 million income tax benefit was recorded at the parent, resulting in a consolidated impairment charge of $47 million. Absent the charge at Sempra Energy International, earnings were 18 million in the third quarter of 2003. The improved operating performance was due primarily to increased earnings from the Company's Gasoducto Bajanorte natural gas pipeline.

Slide 9 provides a summary of our earnings for the quarter. Let me review a few items. Results for Sempra Energy Solutions were breakeven during the third quarter of 2003 compared with 5 million in net income for the third quarter 2002. The decrease was primarily due to reduced retail commodity margins. Earnings from Sempra Energy Financial increased to 13 million from 9 million in the third quarter of 2002. The increase is primarily due to increased income from Section 29 tax credits. Sempra Energy's total net income contribution from Section 29 tax credits in the quarter was 14 million, with 6 million from Sempra Energy Trading, and 8 million from Sempra Energy Financial. Our Section 29 outlook for the year anticipates a total 2003 net income contribution of approximately 40 million. The Internal Revenue Service recently issued an announcement regarding the validity of test procedures and results related to Section 29 tax credits. The IRS has agreed that the testing procedures being used in the industry are valid. To our knowledge, they did not revoke any rulings retroactively or prospectively. And, since the announcement, the IRS is issuing new private letter rulings for Section 29 tax credits. Parent and other reported a $2 million contribution in the third quarter compared with a loss of 18 million in the third quarter of 2002. The improvement is primarily related to a positive adjustment to reflect the Company's consolidated effective tax rate.

Now, please turn to slide 10 for an update on our liquified natural gas, or LNG, business. We made significant progress this quarter in obtaining the key permits necessary to go forward with the bulk of our LNG receiving terminals. At Energia Costa Azul in northern Baja, California, Mexico, we now have our storage and regasification permit from the Comision Reguladora de Energia, Mexico's national regulatory agency, and a key local land use permit from the municipality of , Together with the environmental permit we received earlier in the year, we are the only company that has all key permits for the construction and operation of an LNG receiving terminal on the West Coast of Mexico.

In September, we received FERC authorization to construct and operate our Cameron LNG receiving terminal in Louisiana. This will be the first new LNG terminal built in the United States in more than two decades. Our main attention now is focused on negotiating supply and capacity agreements for each of our terminals. As I've said before, Sempra will not commence construction of the sites until we have a sufficient portion of the capacity hedged or contracted forward. We are in discussions with multiple parties for each of our projects and hope to make announcements soon. We expect to begin construction on both sites in 2004, with completion planned for 2007.

I'd like to announce some organizational changes we have made in order to have the right people focused on our growth businesses. The LNG project will be grouped together and report to Darcel Hulse, President of Sempra Energy LNG. As most of you know, Darcel has been one of our key executives responsible for our LNG strategy. Darcel has more than 33 years of energy experience. Sempra Energy International, which was previously headed by Darcel, is now managed by George Liparidis, President of Sempra Energy International. George has been in the energy business for 23 years and was instrumental in developing and growing our growing Mexican gas distribution business and our successful Bajanorte pipeline.

Turning to slide 11, today we are affirming our 2003 earnings per share guidance of $2.70 to $2.90 on a GAAP basis. In addition to the unusual items recorded here today, our guidance continues to include the expected fourth-quarter impact of two previously disclosed items. They are the adoption of FASB interpretation No. 46, which is expected to result in a non-cash cumulative downward adjustment to earnings of approximately 17 million; and the favorable resolution of tax issues related to utility balancing accounts, which is expected to resolve in a positive contribution to earnings in excess of $75 million. Excluding the unusual items recorded year-to-date and those expected to be recorded in the fourth quarter, there continues to be no change in our net income expectations for 2003. We still expect our businesses to deliver operating results in the range of $2.60 to $2.80 per share. In addition, today, we are affirming our 2004 earnings per share guidance of $2.60 to $2.90 per share on a GAAP basis.

We have consistently stated that Sempra Energy will maintain a strong balance sheet and solid liquidity. One of the reasons Sempra Energy was able to avoid many of the problems that plagued our industry was due to our focus on strong financials. We further improved our balance sheet on October 14 by issuing 16.5 million common shares., resulting in net proceeds of $448 million. The proceeds were primarily used to pay down short-term debt. Adjusting for the equity proceeds, our total debt to total capital as of September 30 would have been 54 percent. Capital expenditures and investments year-to-date are $846 million. Based on our current plans, we expect capital expenditures and investments to be approximately 1.2 billion. We estimate the cash flow from earnings plus depreciation, amortization and deferred taxes will approximately equal capital expenditures and investments for 2003.

In conclusion, our strong third-quarter results demonstrate that we are on track to meet our targets for the year. Many of the uncertainties that had concerned investors are now favorably resolved. We're seeing an improved regulatory and political environment in California. We also have additional certainty from recent legal and regulatory rulings upholding our CDWR contract. And the Resources business is producing the strong earnings and cash flow we had projected. Looking forward, our LNG business is moving from a plan to a reality, and SDG&E's proposed re-entry to the generation business will add additional rate base and predictable earnings for years to come. With that, I'll open the call for questions.

(OPERATOR INSTRUCTIONS) Denado Assay from Royalist.

Afternoon, gentlemen. And Steve, I appreciate the update. I've got three quick ones. The 600 million that you're trying to get in the rate base, would this be, beyond the strategy of moving toward supplying your own energy etc., help pacify some of the rating agencies' concerns about your competitive businesses versus the regulated businesses. I would assume that it would, but I wanted to get your thoughts on it.

The second question deals with Trading. Year-to-date is a bit behind, but clearly the third quarter is significantly higher than that of year ago. Is that reflective of the transition that many of the trading companies were going through or was there something else that was driving that huge increase? And my third question deals with the write-down of Frontier. I apologize -- I'm sure you've covered this in the past, but I couldn't find it in my notes. It's a brand-new system. I'm wondering why it required such a hefty write-down. I don't recall it was (indiscernible); maybe it was. But just out of curiosity, why a 50 million write-down on it?

Thanks, Donato. Let me take them in order. The 600 million rate base addition approximate at SDG&E that will result, if the CPUC approves the acquisition of the Palomar Power Plant, will add to assets and earnings at the utilities. And at least heretofore, the rating agencies have viewed those earnings as being more stable. So I guess I hadn't really thought a lot about it, but I think, yes, the answer to the question is yes, it should contribute to the stability of our ratings. And I've said many times, our -- one of our strategic objectives is the maintenance of a strong investment-grade credit rating. So we see this investment within the context of obtaining that goal. Now, that investment will not occur and rate base will not be judged, if you will, until later this year, from the commission, but the rate base won't occur until 2007 -- or 6, I guess, the end of 2006.

As far as Trading is concerned, repeatedly we don't try to annualize Trading's' quarterly results. If you look at the nine months this year to last, they were roughly equivalent excluding some extraordinary items, and they generally represent the run rate that we would expect on a low basis. We've said right along you could expect maybe about 120 million a year out of Trading and there will be years in which we do better than that. I wouldn't -- I just would advise not inferring too much from a given quarter and leave it at that.

With respect to the write-down of Frontier, the reason for that is, all of us know that we've experienced significantly higher gas prices all over the US. What we've seen with respect to Frontier is business that we had anticipated from customers -- new customers signups have not occurred because of the higher gas prices. And in fact, in this part of North Carolina, we've seen some switching -- our larger customers were able to fuel-switch. And that caused us to revise downward our revenue and earnings forecast for the utility. And as you know, we have to impair the present value of the undiscounted cash flow as not adequate to be equal to the investment. So we wrote it down. In anticipation of a question, we have about 30 million left on the books with Frontier. We would expect to continue to operate that company into the indefinite future.

Thank you, Steve. I appreciate it.

Sam Brothwell of Merrill Lynch.

Good afternoon -- or morning out there. I'm sorry. Just a couple of questions. Can you maybe give us a little bit more color on the drivers in your 2004 earnings outlook range? And secondly, you alluded to your executive reassignments. Maybe you could speak to -- now that you're focusing on the LNG business as a growth driver (indiscernible) some of your other businesses, could we expect to see you maybe divest some of those or back away from them? And finally, with respect to your Resource proposal at SDG&E, can you comment on the whole situation with PG&E and their objections to reassignment of the FUR (ph)?

Actually, I think on the last point, although I could comment, I think I'm going to ask Ed Guiles with the PG&E situation and the allocation of DWR contracted electricity. But on the first your first point Sam -- first of all, good morning or good afternoon, wherever you are. The drivers in our 2004 outlook -- first of all, let me mention that the guidance is taking into account the full dilution of the recent equity offering. What I would refer you to -- if you attended our analyst conference last May, we did put forward a range of numbers for each of our businesses, and you could go back and look at those to give some context to the guidance that we've given.

I would just say that we're seeing very good results from our Resources company. So we have high levels of confidence in the cash flows and earnings of that unit. I think they were a little up. We are also feeling more confident about utility outlook, as we are seeing the unfolding of the cost of service proceeding with the utilities. I guess I would say that compared to last spring, we are somewhat more confident in our performance, even with the dilution that occurs from the issuance of the equity. And I would just say that this is largely based on the shedding of a lot of uncertainty around the numbers that we had last spring, resulting from ongoing litigation, which is now being resolved consistently in our favor.

With respect to the question of whether we would be divesting any businesses, we are constantly evaluating our portfolio of businesses. We think that they are the right businesses for us right now. I've mentioned on previous calls that we're looking eventually to divest our South American businesses. We don't think they are core to our strategy. Argentina has had the problems, as you know, that we've discussed quite often. But the other businesses are doing well, but they're not really core to our strategy. So yes, over some period of time -- maybe in four or five years -- we would expect, given the appropriate conditions, to divest those businesses. But otherwise, we have no present intention of divestitures.

With respect to Solutions, I noticed there was a change in management there recently. Do you remain happy with that business?

Yes, we do. I wouldn't draw too much of a conclusion one way or the other from quarterly results in that business. We still think it's a good business. We're seeing quite a bit of customer interest in the services and so forth. But let me turn to Ed and ask him to answer your question on the Resource proposal at SDG&E and PG&E's response.

We had made a filing, as you know, with respect to SDG&E's needs, and in particular, the addition of a combustion turbine and combined cycle facilities with the addition of Palomar really helps SDG&E's capacity need in that period. We also looked at the Otay Mesa project, and as you may know, both the Palomar Project and the Otay Mesa Calpine Project have been approved and certified by the Energy Commission. So as we looked at that, and you look at SDG&E's needs over the longer-term, adding combined cycle capacity here in our service territory would be good, not only for our grid reliability needs, but in looking at our reliability must-run contract needs, with the objective really of getting new facilities built that are more environmentally beneficial, as well as being more energy-efficient. So that was kind of the overarching need.

What we filed for PC consideration includes reallocation of the Sunrise contract to PG&E, which would give them a new source of energy in their service territory, and again, would allow us to secure this 10-year power purchase agreement. Sort of the overarching effect of all of this would be creation of a new-generation facility that would be beneficial to the entire California grid. And we put conditions on the 10-year PPA with Calpine which principally are reallocation of the Sunrise contract and the ability for us to get the transmission that would be needed to support that new plant to be built in San Diego.

PG&E has made some comment on it. There will be hearings that will take place during the first part of January and February. We would expect to get a decision by the end of May next year -- that's the current schedule. And so we've made this to the Commission and we feel it's a good overall plan.

I think our assessment that customers both of PG&E and SDG&E net will benefit by this reallocation. Particularly also the environment will benefit, because you're getting much more efficient, cleaner generation built in the South. You'd be shutting in our existing power plants with much higher heat rates. And so the benefits are pretty manifest. The PUC has complete discretion with respect to the allocation of CDWR contracts. And I think -- I can understand PG&E's position of wanting to be sure that customers were protected. I think they'll find that they are as we move through these proceedings.

Thank you very much.

David Maccarrone of Goldman Sachs.

I wanted to ask you if you could characterize the nature of the LNG contract discussions, and what the issues are so far in terms of preventing a deal from coming to fruition -- whether that's price or some type of service, what other structures? And when you say multiple parties that you're having discussions with, does that relate to specific capacity or have you boiled it down to what parties you think you're going to work with going forward?

David, I'm going to ask Don Felsinger to answer that. He's right in the middle of it, and give you a report from the front lines.

Good afternoon, David. As you are aware, the two LNG projects that we have, Cameron and Louisiana and Costa Azul in Baja, California, basically can access any part of the world in terms of gas supplies. As we've mentioned before, we are in fact having discussions with everyone in the world that has branded gas, that would like to look at the U.S. as a marketplace. The significant thing that's happened in the last quarter is there are numerous entities that have announced LNG receipt terminals in North America. And as potential suppliers look at where they would want to land their gas, it's becoming more apparent to them that Sempra has the lead in terms of permit approval, and so our discussions have now been more focused with the recent permit approvals that we received in Mexico and in Louisiana.

We have narrowed those discussions down to about 5 potential suppliers in Mexico and in Louisiana. As we have those discussions, you have to remember that even though we at Sempra are investing significant capital, about $700 million in each of the facilities including pipelines, that upstream of that there are literally billions of dollars being invested. So as we try and do a match of when those projects upstream would come online, the time required to put together 20-year capacity or buy-sell agreements is quite rigorous and lengthy.

With that being said, I would expect that sometime in the fourth quarter of this year or early next year, we would be announcing contracts for both of those facilities.

Beyond that, given the prospective success of this strategy, are you seeking additional LNG projects to develop?

I think we are continuing to reassess the market, what LNG volumes are required over the next 10 years and determining where we would position ourselves to continue beyond these two projects. We've made no announcements at this time.

How would you characterize the development of that strategy at this point?

We are still very enthused about the opportunity for LNG to solve the current gas price supply crisis in North America. So we have several locations that we are in fact pursuing but are not ready to announce yet.

Have you narrowed the strategy in which you're going to finance these projects?

In all of our discussions in terms of contracting, we are taking the approach we would eventually want to have the alternative of doing project financing.

Thank you very much.

John Edwards of Deutsche Bank.

Good morning. A couple of questions. Steve, could you talk about the variance -- a little more detail on the variance -- not the variance -- on the parent and other amount, there was you said a positive impact from an income tax effect. And I'm wondering if you could describe about how much that was?

Okay, John, in general, let me just elucidate a little bit. What we do with respect to taxes in each of the business units, is to calculate the tax that their respective tax burdens and on an expected basis for their businesses. And then we true that up on a quarterly basis at the parent. When one business might, as SDG&E did in the past quarter, have an usually large earnings coming from the settlement of the intermediate term contract case. We will resolve the tax effect of that unusually high earnings at the parent trued to our expected annual tax rate, not the expected business unit rate. So it's the difference between those rates. And as you know, we're running an effective tax rate at Sempra a little bit less than 20 percent for the year. So the utility would report income at a -- close to, I think, at a statutory rate. So it's the resolution of that difference. I don't have in my head the exact amount of that consolidated (indiscernible). I can't reconcile that exact consolidation. I don't know if Frank --

So in other words, it's the reconciliation between, say, the higher tax rate down at say a utility versus the consolidated rate that would be lower, and so in the end you up with a positive change there?

For the year, Sempra will pay taxes at about an 18 to 20 percent rate. And so for the year, it washes out.

And then I wanted -- I guess this question is probably for Ed. There is a number of moving pieces now on the regulatory front. You have the rate case as well as the potential Calpine contract, as well as the project that Resources is building at Palomar. I guess my question is, to what extent would the trade-off of the Calpine contract and Palomar, how would that perhaps impact the rate case filing? I mean, there are a lot of buckets of dollars here. Maybe you could describe a little bit of how that dynamic might work out?

Let me just comment on a couple of things. We have the cost of service proceeding that Steve sort of summarized. That's going on and we would expect that, which principally covers the O&M and capital related costs for the two utilities going forward, we would expect to get a decision by the end of the first quarter. Hearings are substantially completed. We feel very good about our position. Expect to file briefs in December, with reply briefs before Christmas. So that will take its course to establish revenues for 2004. We don't know whether we will get a 3 or a 5-year mechanism, but certainly we're hopeful to get a 5-year mechanism in that regard.

We also have on the electric transmission site, an all parties settlement on our electric transmission that allows an annual true up of rate base for electric transmission revenues and a guaranteed 11.25 percent ROE. The addition of the generation would go into rate base -- that's out a couple of years. In the case of Palomar, we're going to need that facility to be in-service by the summer of 2006 in order to meet our grid reliability capacity requirements.

With respect to the Otay Mesa facility, if you look at the electric transmission that's going to be needed to support the construction and integration of that facility into the grid, it's expected in the summer of 2007. So when you look at that, that's a 10-year power purchase agreement. The earnings benefit to the Corporation will principally be through the addition of the electric transmission and that addition to our rate base going forward. So that's sort of just a quick snapshot.

Ed, I'm glad you're guaranteeing them that rate of return on the transmission. FERC gives us the opportunity to get there and Ed's going to make his plan.

Okay. You mentioned that the ALJ had already made a recommendation as to -- but you didn't say what the amount was.

The ALJ's recommendation in terms of the -- ?

For the rate case. I think you said that he made a recommendation for --

What the ALJ did was to give us a balancing account, so that we can recover in rates for the period of time prior to the final decision, which is very important, because in the absence of such a thing, we wouldn't be able to change our rates and we would lose the return on the increased rate base during that period. There's always a struggle between companies and the staff over the timing because there are real dollars are involved. So if we get a balancing account, we can go back and true up and then collect over at period of time with interest.

So he did not make a recommendation on an amount. Because it sounded like that would be premature, if you don't have all of the rest of the filing and hearings.

It would have been.

If I could just add to that, the Administrative Law Judge, Doug Long, came out with this earlier this week. And this memorandum account is consistent with what they've done for the other utilities in their general rate case proceedings. This will be on the agenda for the PUC to consider on December 4th.

Thank you very much.

Michael Goldenberg (ph) of Luminous Management.

Good morning, guys. Just wanted to make sure I got a couple of things down correctly. First of all, the decision on the Palomar and Otay Mesa plants, hearings will take place in January with final decision in May. So it won't part of the regular rate case?

That's right.

Who will ultimately own Palomar? Will it be the GME (ph) or will it be Resources?

What we have proposed is that Sempra Energy Resources build Palomar at actually on kind of a turnkey basis, a fixed cost basis. So we will -- part of the deal is that the affiliate, Sempra Energy Resources, bears the risk of cost overruns in building the plant. It would then turn it over to SDG&E on a finished base, at which it would go into SDG&E's rate base, and the operations of the plant thereafter would be typical cost of service type operations of the plant.

We've also asked for some interim treatment in rates, as if the plant were being built during -- in SDG&E at the period of time -- during the period of time it's being built by the affiliate. So normally, in utility ratemaking, you get AFUDC during the construction period, which then could balance your capital structure. And we have asked for some revenues to cause the cap structure of SDG&E to be balanced approximately 50-50 at the time that the sale of the plant or the transfer of the plant is made from Palomar. And there are some ripple effects from that that would be caused, and the SDG&E would not be constrained -- would be constrained in its dividends during the period of time of the construction, and we would be otherwise financing that at the parent level.

That makes sense. I guess two more questions. One was, with your Solutions business doing somewhat weaker than previously, yet there has been definite pickup in retail activity across the United States. There is a lot of business getting picked up in the Northeast, plus California seems to becoming more open. Are these encouraging signs for long-term profits of your business? And if so, why maybe hasn't Solutions capitalized on this to the extent that some other ones have?

I wouldn't draw any conclusions from our third-quarter results. We did see the during the third quarter extreme gas prices and natural gas and high gas prices in electricity. And during that period, customers are reluctant to enter into long-term contracts. Year-to-date, our earnings are $7 million, and if you look at the business this year as compared to this time last year, we have had significant customer additions. We're serving about twice as many customers and about twice as much volume as we did. So we are well-positioned to make money when the market turns around going forward.

But why have you picked up customers without picking up margin on that income?

Basically, the customers we've picked up, we're picking up on a breakeven basis to add to our customer base, understanding that the commodity cycles are going to go up and down. We want to be positioned with a larger customer base as wholesale prices drop.

Okay, that makes sense. And final question on the tax rate, the 18 to 20 percent, will it last all the way through 2007? Is that which you guys are envisioning?

Maybe I'll ask Frank Ault to look at that. I'm not sure that we forecast future expected effective tax rates. A lot of it is driven by extraordinary depreciation on planted construction -- we're coming to the end of a construction period, and we will embark on a new one. And whether accelerated depreciation will apply to those new assets is unclear to me. Secondly, we have the Section 29 tax credits, and our affordable housing tax credits, which will continue in future years to have an effect of lowering our effective tax rate. Frank, I don't know if you want to address this in more specificity.

Just a little bit. The Section 29s have a definitive (ph) life and they will be expiring out in 2006, 2007 time frame. Also the Section 42 affordable housing credits that we have basically have a life. We have not entered into any new projects over the course of the last several years. So those will start expiring over the next five to six years. I would anticipate seeing an increase in our effective tax rate from the 20, 21 percent area where we are roughly now in the last couple years probably moving up to the mid to upper 20s as you get out three, four years.

Okay. Thank you very much, guys.

Paul Patterson of Glenrock Associates.

What I wanted to ask you was, basically I'm just a little confused on the GAAP accounting. The guidance that you guys gave before was based on a GAAP basis -- I think with EITF 02-03. And I guess that no longer is included in the guidance for '03. Could you clarify what's changed with EITF 02-03? Did it not turn out the way you thought it would or what led to that change?

That is certainly not the case. Our GAAP guidance does include the full effect of the EITF 02-03 -- the cumulative effects and the ongoing effects. So there is no accounting effect left out of our GAAP forecast.

Okay, so the 270, 290 is still the GAAP forecast?

Yes.

Okay. I just wanted to make sure -- I wasn't clear. What I also want to ask you is in terms of going through to 2004 -- and I apologize if I missed this -- what kind of PBR awards were you factoring into that, if any, for 2004?

It's been very difficult for us to forecast the timing of -- frankly even in the end the amount -- but I think more difficulty in timing of the PBR awards. I should step back and say that we expect PBRs to continue as part of our cost of service proceeding. We already have the GCIM mechanism at the gas company being continued, albeit on a slightly different formula. We have asked in the general rate case for the kinds of PBRs that we have at SDG&E to be included at the gas company, growing towards reliability, safety and customer satisfaction. We have -- we're optimistic that these mechanisms will be continued.

And we have pent up a $53 million pretax awards in the utilities, principally SDG&E. I think it's per (ph) DSM awards -- Demand-side management awards. We're pretty sure about that number; we're just not sure of the timing. I believe that we would have included some of that in our forecast. I don't know that we included all of it in the forecast for 2004.

So some portion of the 53 million is probably in '04?

Yes, let me just refer this to Frank Ault, our Controller.

One of the things that Steve mentioned was that we've had some issues with the Public Utility Commission on consistency of the timing in which they render decisions. For instance, this quarter we got two years' worth of GCIM awards, didn't have any the year before. We are assuming they will stay on track; we'll get one next year and one on the PBR. On the DSM, they have approved recently that they are not going to change the mechanism, so we do have part of that 53 million that they are currently reviewing. We would anticipate part of that getting freed up next year. Part of the reason that we have a 30-cent range in our earnings forecast is around the fact there is uncertainty with the PUC on the timing. We're very comfortable that we're going to get these awards. Whether we'll get and how much we will get next year is still a bit of a question mark, and that's part of the reason for the wider range.

That explains a lot. But in terms of the minimum amount that you are expecting, can you give us an idea what that might be?

Minimum, I don't know. We filed for and the public number is 53 million.

Okay. And then in terms of 2004, the 40 million in (indiscernible), should we think about it as pretty much being the annual run rate going forward from now on or do you see the possibility of increasing production there, possibly selling some, what have you, I don't know?

Neale Schmale has stuck up his hand, wants to jump into this briar patch.

For the immediate future, you should expect the run rate on the tax credit to be more or less the same as this year. Obviously, as was indicated earlier, the ability to generate those goes away in a few years.

Okay. Great, thank you very much.

(OPERATOR INSTRUCTIONS) Please limit yourself to one question to allow everyone a chance to ask their question. Bob Sullivan of UBS.

On the parent and other, it's pretty much been running in the low 20 million, high teens range. Is that the correct run rate going forward, or will it continue to be impacted by the tax issue?

I'll let Frank Ault answer this question.

Really, the issue around the effective tax rate is a quarterly issue. By the time we get to the end of the year, all of the individual business units with their effective tax rate will come up to the effective tax rate for the corporation. So there's just a little bit of timing issues around the quarters, depending on whether earnings are higher or lower in the given quarter of a business unit. So we would look then at the end of the year, the only tax things that are really sitting at the parent are tax effects of expenses incurred at the parent. So I think that the run rate that gets us to the 60 to $80 million annual rate, so around 20 million or maybe just a little bit under that for a quarter would be a reasonable rate to expect going forward.

It's 60 or 80? Okay. How much interest expense is in the parent and other line, and how much debt is associated with that?

At the parent, the bulk of the expense that you see is related to interest expense. So I would say that except for the corporate center operating costs and a few very minor subsidiaries that are there that are not either at the utility or in the global companies, really you have the after-tax effect of expenses there and you've got the interest. And I would say the interest is probably going to run on the order of 80 to 90 percent of that total.

How much debt is allocated to the parent?

There's not debt allocated to the parent. It's dedicated --

At the end of the quarter, how much debt was at the parent?

The debt is either at the global parent level or at the corporate center level. So the only thing that's not included is the debt at utilities, which is a large piece of our debt, and any debt that may be incurred directly by one of the business units.

You don't know how much debt it is?

I don't have that breakout with me.

Okay. Thanks.

Most of the non -- we can break that out, but most of the non-utility debt is at the parent. There's a little bit of debt in the Trading company and then there's some debt in the Resources company. But the bulk of the non-utility debt is represented by the interest you described (ph).

Thank you.

Peggy Jones of ABN AMRO.

Could you talk about what impact the Schwarzenegger administration is having on either the utility commission or the process for dealing with contracts?

We're just, of course, in the very earliest stages. He is still governor-elect; he's not even the Governor yet. As far as the Public Utility Commission is concerned -- I wouldn't observe anything about the individuals, but there -- they are not removable at the pleasure of the Governor. They serve fixed terms and they've been approved by the Legislature, and it's a constitutional agency. So there is really little if anything that the Governor can do with respect to the Public Utility Commission other than persuasion. And the next two terms that come up are Carl Wood and Loretta Lynch, whose terms expire at the end of 2004 -- in once case, just in January of 2005. And that would really be, unless there were a resignation, at the discretion of an individual commissioner. The governor-elect would not have the opportunity to make an appointment to the commission until that time.

I think it's fair to say looking at his energy proposal, that they are essentially pro-business, pro-economic recovery. I don't really see much difference between that and the current attitude of the majority of the commission. So I think that's a very intent -- everyone really in government in California right now, if I'm referring to the Commission and to the Governor-elect's people, very intent upon restoring business, because that is where the money is going to come from to solve the deficit. So they are really in lockstep on that regard.

Thank you.

Tom O'Neill (ph) of Lehman Brothers.

Two quick questions on the utility. I'm curious if there's timetable on the PBR proceeding that was separated from the cost of the service? And then second, I think you said you're going to finance the Palomar project on the San Diego Gas & Electric balance sheet. I just wanted to confirm that. And then, when you would start booking income from that project, if you got it as proposed?

I'm going to ask Ed to answer the first question. Let me say on the second, no, we're not financing it on the balance sheet of the utility. It's being financed separately as it's being constructed in Sempra Energy Resources, and that's a financing that's coming from the corporate resources of Sempra. What I said was that the utility has asked to afford (ph) some financial treatment during the construction period as if the plant were being constructed by the utility so that it can have a balanced capital structure at the time it makes the purchase from Sempra Energy Resources.

Now of course, it's not lost on anyone from whom we would get financing that there would be a Commission -- assuming we're successful, there would be a Commission order authorizing the purchase of the plant on a turnkey basis from Resources by the utility, and that has the effect of -- essentially, of putting the utility's balance sheet at the disposal, from a financial perspective, of Sempra Energy Resources.

On your question related to the PBR, as you know, the PBR was bifurcated in the cost of service proceeding. We don't have a definite schedule yet, but I would estimate that it will be in the latter part, third quarter, perhaps, of 2004. We have a request before the Commission which they haven't acted on yet to extend our existing PBRs until that decision is made.

Steve, just a follow-up on your question. It sounds like what you're saying is debt finance it at the parent, but it would be made in (ph) different from an income perspective from an accounting adjustment at the utility?

Well, no, I think AFUDC at the utility would be recognized in the results of separate consolidating.

Okay. And you'd start booking income when?

If the Commission were to agree with this proposal -- and by the way, this has just been filed with the Commission -- there are going to be a lot of hearings and a lot of back and forth on all of this stuff. But the AFUDC would show up, as I understand it -- maybe Frank, you want to comment on the accounting for this -- but would show up in the income statements of Sempra (indiscernible).

Sempra Energy Resources, as they build the power plant, will capitalize interest under normal accounting standards and that will be incorporated in the fixed prices paid by San Diego Gas & Electric. But under those particular accounting rules, you're only capitalizing the interest cost -- no equity component. So what we have asked the Commission to take a look at is have SDG&E build it under normal utility rules, where you are able to capture and capitalize a part of the equity costs of the plant, that we would look at what that AFUDC would have been at the utility, less (indiscernible) is being capitalized at Sempra Energy Resources on the interest side.

And we've asked the Commission to take that difference as the equity component and have that includable in the rates of SDG&E. If the Commission approves that, that equity component of AFDC would come into earnings between now and 2006. Most of it would be in the outer years as the capital expenditures become larger. What we have proposed is such that the customer would pay no more than it would pay had the utility built the plant themselves.

Great, thank you.

Winfried Fruehauf at National Bank Financial.

One question -- actually, a two-part question on LNG. I believe in the past Sempra had a predilection for Bolivian natural gas LNG. I understand there are some complications upstream within Bolivia that would make 2007 virtually unattainable. The question is, I know you said you are also looking at other sources. What would the potential loss of Bolivia do to your plans?

You're right that we had observed, I think it's fair to say, and at one time did have an MoU with Pacific LNG Group. We had observed -- and it's plain for anyone to see -- that Bolivia is half the distance to the West Coast of Baja, California than any of the principal sources of gas, X Alaska, in the Pacific Basin. We had hoped that Bolivia would be able to solve its political problems and that that gas would flow. It really makes a lot of sense from just a cost basis for that gas to reach North America. But we've been overtaken by politics.

I think it's pretty well known to everybody that the privatization efforts -- it's not just the export of gas, but privatization efforts in their totality in Bolivia are heavily under fire and have become a significant political issue costing the President his job. So I think it's fair to say that that source of gas is certainly delayed. I think in the end almost no matter what government in Bolivia comes to power, including those on the left, that the economic necessity for Bolivia of realizing the value of that resource will bring it to market, but not on the time schedule we had hoped for.

The other part to my LNG question is, you mentioned that you were considering using nonrecourse debt. Given that the rating agency seemed to be making no difference between sort of the nonrecourse debt and recourse debt, what does it really gain you and have the rating agencies indicated to you how they do view your engagement in LNG?

I'm not sure I'd agree with you entirely that rating agencies fully consolidate project debt and non-recourse project debt to the parent. I think there is a certain amount of look-though of it. But I think it's -- one of the positive indicators of project finance is that you have third party banks that think your project is a viable one, are willing to lend on it. So it's kind of a report card. If it's always just done at the parent level, there is always a question whether it would have withstood the test of an independent third party review.

It's more a process of discipline (multiple speakers) project.

Yes. The second part of your question was what?

Whether the rating agencies have intimated to you how they view your engagement in LNG, especially if you proceed with two projects?

I think the answer to that is that there is always a concern on the part of the rating agencies with respect to large capital expenditures during a period of time in which the revenues are deferred until the end of the project. But that's going to be tempered by their view of the credit worthiness of the counterparts that we have for the contracts. One of the reasons that I've said that we won't go forward with these projects without an identifiable credit-worthy counterpart with a long-term contract, at least for a portion of the throughput of the facilities, is that I don't want to put us in the position of uncertainty with any of our constituencies, including the rating agencies, about the viability of those capital expenditures.

Thanks very much.

Douglas Stapler (ph) of Duquesne Capital.

Just a further question on LNG. We've seen a lot of headlines recently, whether it be Conoco or Shell, there seems to be a lot of activity upstream. And those companies also, I know, have been getting projects, especially on the West Coast. I was just wondering philosophically if it's required that you were to sell down some of the equity in one of your LNG facilities in order to lock in supply from a credit like a Conoco or a Shell, would you be willing to do that? Or should we be still thinking in terms of you owning 100 percent of these LNG facilities?

All of these possibilities are before us right now. We don't rule out anything. Our preference is to make money in these projects, and that is a practical matter. We will pursue those opportunities if they make us money. And I can't really give you any more certainty on your answer than that, other than I don't rule out anything.

Would you, at this point, if it were to mean spending less money on a re-gas facility, be at all interested in participating further upstream or do have no interest in that?

That is not our business, the upstream business. I think the only sort of subpart to that that I would bring out is that we need -- we do a lot of ship chartering in the oil business in our Trading company. It is a business that we know something about. The ownership of ships is not, but the chartering business is. And it may be that we would, depending on our contract arrangements, move to some degree into the transportation part of the value chain. But that is not a principal focus, it would only be as an adjunct to making sure that the supply contracts were profitable to us.

Thanks very much.

Teresa Ho of Salomon Brothers.

Good afternoon. In the past, you had given us sort of the earnings profile, a long-term earnings profile, for each of the business units. And now, with so many moving parts, the rate cases, as well as your LNG project, could you just sort of update us in terms of how you are looking at the Company earnings profile? In particular, are you expecting that any potential fall-off from, say, tax credits that you are receiving now would be replaced by, say, your LNG contribution?

Teresa, we're going to have an analyst conference this spring. I really hope to see you there. We will go through and detail at that conference the spread out through 2007, business unit by business unit, giving you the range of expectations that we have. But I think it's -- it's premature to do that right now and I'd rather -- we would rather do that in a comprehensive fashion for everybody at that time, give you a chance to dig in in depth with all of our business unit leaders. So, I would extend an invitation to you to come to that conference, and I hope we can satisfy all of your question at that time.

Okay. How about this? Maybe instead of particular business units, could you comment on perhaps what the regulated versus the non-regulated profile could be?

I mean, we expect to do pretty well in this rate case with the utilities. And that's the way the case has been going. I would say the intervenors have not shown particularly well in their attacks. We have the backing of labor in our request for O&M. Our capital additions are not particularly controversial. And there are some fairly large capital investments that we discussed rising out the Resource plan. So I would think that we could forecast relatively robust results from the utilities over the period, at least out through -- to 2007 -- 4, 5 and 6, and we hope beyond, because we've asked for a longer period. And as we've said, in 2007, would be the first-year effect of the Palomar Power Plant if it's approved in the utility's rate base. So I think you could expect some more earnings from the utilities than perhaps we've talked about in the past, principally driven by some optimism that we have in the rate case, and also the new capital additions to rate base that will come from the utility's return to full service obligation. So, that's one comment.

LNG, now, would appear not to impact our earnings significantly until the end of 2007. So I think the LNG being on the horizon now is probably, from what we talked about a year ago, has slipped slightly. Maybe not quite a year, but it's slipped a little bit. So the impact of LNG earnings coming in at that time would be in 2007 probably toward the end of the year. But those are the only real -- again, I want to say that we'll give you a full dose from the fire hose in the spring.

Okay, play to be there then. Thank you.

Faisel Khan (ph) of CSFB.

On the Trading side, Table E, just trying to make sure I understand what's going on. Your REROC (ph) for the quarter was at around 17 percent, even though your margins were much higher, at $135 million. And if I go back and look at the previous quarters, usually when you had these higher margins, it came along with higher REROC. So I'm just trying to reconcile what's going on. And I just have one question after that.

I'll take a stab at it, and then maybe if Frank wants to comment. I think we have some extraordinary adjustments during the period that have influence that calculation -- in particular, the settlement amounts with the FERC. And I think that's the principal impact on Trading's activities in terms of the return -- risk-adjusted return on capital. Frank, do you want to comment on that?

I think, Steve, that's one of the principal ones. There's also what the implementation of EITF 02-03, there's some timing differences that you see there a little bit that hit the GAAP earnings that aren't necessarily fully reflected because the difference from year to year. One year, you have that new procedure in place; the second year, you didn't that -- last year, you didn't have that kind of rule; this year you do. So there's a slight difference because of that, as well as the adjustments that Steve was talking about.

You don't talk about the power gross margin -- that was up considerably for the year. I'm trying to figure out what's going on in that part of the business? Is that starting to come back now? Do you see more liquidity in that market?

Don, do you want to want to comment on the power business and Trading.

We've seen more activity from customers that want to enter into contracts. So the margins are better and we've got more volume.

The last question, on the consolidated income statement, the swing in other income of about 50 million, could you specify what that's related to? Is that related to one of the one-time items?

You're talking about the other income on Table A?

Yes, sir.

The other income, basically, is a sum of a couple things. But the biggest single one down here has to do with the earnings from our non-consolidated subsidiary companies. So as we have improvement in those specific companies, we will see the effect in this line. So we had some losses in a couple of those last year that have turned profitable this year. So bottom line is where you see that improvement coming through in this particular line. But that obviously is reflected in the business unit results that we talked about a little bit earlier.

Okay, thank you.

Ashar Khan (ph) of Forsyte (ph) Investments.

Steve, just going back to the '03 forecast, I know you've provided ranges for the different business. With the year nearly complete, can you just provide us a little bit better what the numbers could come out -- I guess a tighter range in terms of achieving the earnings objective for this year?

Frank stuck his hand up here, so --

Let me tell you the reason that we have the range as wide as we do at this point in time, and it really comes down to what Steve talked about earlier on those tax issues. We have two large tax issues pending before the IRS that we're very close to settling. We talked about them at the end of the second quarter and again now. We anticipate that they're going to come in the fourth quarter. We anticipate if we get both of those, it'll be $75 million plus outcome. But we don't know the exact amount we're going to settle for or necessarily the timing we're going settle those issues. So that is the reason we are keeping as wide a range as we are this late in the year.

But I would also point out that we have reiterated our operating forecast for the companies as being pretty much consistent all through the year.

I understand. If I could just go one more question on Solutions, can you just share with us what kind of margins are you seeing this year versus the last quarter in terms of MW hours in the business?

We typically don't comment on margins, so let me just say, as I said earlier, as we've been seeing higher commodity prices, customers have been reluctant to enter into contracts. but one thing we have been doing in our Solutions business, which is very positive, is we've almost doubled the number of customers we serve and almost doubled the volumes that we supply. So we are getting ourselves a good foundation going forward, when we expect to see prices become more favorable for customers entered in long-term contracts.

Let me ask this question in a different way. From the spring meeting, you had some forecast for the Solutions business going forward for the next three, four years. Of course the growth in earnings was a mixture of increase in volumes and of course maintaining of some margins. So what margins do you think that you can achieve in this business on an annualized basis, taking out the discrepancies which might come from quarter to quarter due to different commodity prices?

I think we've said in the commodity business that we would look to have margins, both gas and electric, in the 2 to 4 percent range.

Could you do it on a MW hour basis or on a gas-equivalent basis or something?

No, I can't right now.

Thank you, sir.

(OPERATOR INSTRUCTIONS) You may listen to a rebroadcast of this conference at 4:30 PM Eastern time today, through November 13th at midnight by dialing 719-457-0820 and enter confirmation code 655829. At this time, I will turn the conference back over to our speaker, Mr. Arriola, for any additional or closing remarks.

I think that's it for today. We appreciate you joining in for the call and participating in the Q&A. And if you have any follow-up questions, you can get ahold of our investor relations team. We'll be around for quite a while. Thanks.

And this concludes today's conference call. Thank you, everyone, for your participation.