OGE Energy Corp (OGE) 2003 Q4 法說會逐字稿

(OPERATOR INSTRUCTIONS). At this time, I would like to turn the call over to your moderator, Mr. Jim Hatfield.

Good morning, everyone, and welcome to OGE Energy Corp's fourth-quarter 2003 conference call. As the moderator said, I am Jim Hatfield, Chief Financial Officer. And I have with me today Steve Moore, Chairman, President and CEO and Pete Delaney, Executive Vice President and COO of Enogex. We also have several other members of the management team available here to address questions.

In terms of the call today, we'll start off with comments from Steve Moore. I'll review 2003 results, starting the full year and then the fourth quarter. We will talk about our 2004 outlook. Pete and I will have some comments on the regulatory proceedings going on in Oklahoma and in Washington. And then we will end with Q&A.

But before we begin, I want to remind everyone that we have prepared slides to accompany this Webcast, so it will be easier to follow the numbers when we get to that point. Also before we begin, I want to direct everyone's attention to the Safe Harbor statement that is contained here in the presentation, as well as the end of the press release. And with that caveat, I will turn the presentation over to Steve Moore. Steve.

I would also like to welcome you to the call and thank you for your interest in OGE Energy. Today in addition to our 2003 financial results, we know you are interested in the regulatory issues surrounding the McClain Power Plant acquisition, the withdrawal of our Oklahoma rate case and a potential rate reduction of about $2 million per year per month, commencing on January 1st this year. First, today, we announced a fourth-quarter net loss of 1.6 million or 2 cents per share diluted, compared with a loss in the fourth quarter last year of $30 million or 39 cents per share diluted. You will recall that last year's fourth quarter results included a pretax impairment charge of $48 million at Enogex as we wrote down the value of a number of gas assets we no longer needed in our pipeline business. As we told you last year, we continued to rationalize assets, and as a result, we wrote down $9 million of Enogex assets in the fourth quarter just concluded. The fourth quarter consolidated net loss was due to that impairment charge. The good news is that in each of the four quarters of 2003, stronger performance at Enogex offset lower year-over-year comparisons at OGE, which had a $25 million rate reduction stemming from the agreement reached in 2002.

For the full year, OGE energy's consolidated earnings were $1.58 per diluted share compared with $1.16 a share in 2002. OG&E earned $1.41 a share and Enogex earned 33 cents a share, solid indications that we are successfully executing our plan. Once again, I point to what we call operational excellence. It's an important part of our corporate vision, as our employees -- and they work on it each and every day, and they are to be congratulated for an outstanding performance in 2003.

At Enogex, the fundamental operating changes we have made in the business are producing sustained improvement in financial performance. At OG&E, a sharp focus on business process is essential as we deal with rising costs, lower rates and regulatory uncertainty. Jim will go through the financial details in just a moment, but I want to emphasize that from an operational and financial standpoint, we had a very good year.

The financial markets recognize this, sending the price of OGE common stock up 37 percent during 2003, nearly twice the gain that was seen in the Dow Jones utility average. During a summer hot spell, we met four new records for peak power demand and four new records for daily system MW hour usage. It was definitely a fine display of power plants, pipelines, transmission and distribution systems all working together when it mattered the very most for our customers. We also responded to tornado damage last May with a performance that had General Motors telling the world that OG&E set the standard, as we helped them get their Oklahoma City assembly plant restarted after that storm. We were recognized as the best in the strongest 15-state Southeast region for customer satisfaction by J. D. Power & Associates. I feel this affirms our strategy of focusing on core operations and customer service. Also in 2003, we completed a long series of challenging steps in our plan to acquire the McClain Power Plant. We expected to take ownership by year-end in keeping with our 2002 commitment to provide long-term savings to our retail electric customers. We filed a rate case with the Oklahoma Corporation Commission to include the plant in our regulated rate base, as well as to address rising costs and invest in system reliability while reducing rates for schools and businesses. Approval of the McClain Plant acquisition to serve retail customers was widely expected. But on December 17, the FERC commissioners raised wholesale market power concerns and ordered a hearing. In turn, we withdrew our Oklahoma rate case. We remain determined to complete the acquisition. But in the meantime, we are delivering the savings we have guaranteed. Our agreement to acquire the plant, which was reached last August, includes a provision that enables us for now to purchase low-cost power from it. We have asked the Oklahoma Corporation Commission to review the savings we have been delivering since January 1st this year, and confirmed that we are in compliance with the 2002 rate agreement. If the Commission finds otherwise and we are penalized with a rate reduction, we would expect to cut our planned expenditures this year for electric system reliability upgrades. With respect to the FERC, we are asking the Commission to reconsider its order because it wrongly harms our retail customers and our shareholders. We are not alone on this point. The Edison Electric Institute and the Oklahoma Municipal Power Authority have both intervened with FERC in support of our position. We are working to resolve this as quickly as we can so we can complete the acquisition and file a new rate proposal in keeping with our strategy to secure long-term savings for our customers and earnings growth for our shareowners. We have a strong case to support our careful, conservative plan to increase capacity and reliability in a cost-effective way to meet growing retail customer demand. It has not come together exactly on the timetable we wanted, but we are determined to make it happen.

Looking ahead, we will continue to pursue our customer savings and reliability plan. It's an excellent plan and it's the right thing to do for our customers, our shareowners and for our hard-working employees who make it all possible. Again, I would like to thank you for your interest in the Company. Now, I will turn it back over to Jim for a more detailed financial review of the fourth quarter and 2003 and our outlook for the year ahead. Jim.

I will start the financial review by covering the earnings of OGE Energy Corporation. And as I mentioned, we will begin with the discussion of 2003 full-year results. For 2003, we reported net income of 129.8 million or $1.58 per diluted share as compared to net income of 90.8 million or $1.16 per diluted share in 2002. The contribution by business unit on a comparative basis is as follows -- OG&E, the electric utility, $1.41 versus $1.61 in 2002; Enogex, a positive contribution at 33 cents versus a loss of 28 cents in 2002; the holding company, a loss of 16 cents versus 17 cents in 2002, $1.58 versus $1.16. For OG&E, net income was 115.4 million or $1.41 a share as compared to net income of 126.1 million or $1.61 per share in 2002. The growth rate for 2003 was 2.5 percent, driven primarily by strong residential sales. Gross margin on revenues decreased to 679.7 million from 692.2 million in 2002. The major factors impacting gross margin were lower rates, the result of the January rate reduction, which lowered revenues by 24.8 million or 20 cents per share in cooler weather. These factors were partially offset by a growth in retail sales that I mentioned earlier. In terms of expenses, O&M increase 11.9 million or 4.2 percent from the 2002 level. The largest increase in O&M expense were pension costs. In addition, 5.4 million of expenses from our ice storm were deferred as a regulatory asset in 2002, creating a negative variance for 2003. Partially offsetting these higher expenses were lower levels of bad debt expense, the result of process improvement. Average diluted shares outstanding increased to 82.1 million from 78.2 million, the result of our August equity offering. (Indiscernible) resulting from the offering equals approximately 7 cents per share. A lower income tax rate in 2003 resulted in a positive variance of 4 cents per share.

At Enogex, we reported net income of 26.9 million or 33 cents per diluted share in 2003 as compared to a net loss of 21.7 million or 28 cents per share in 2002. As we anticipated in our third quarter call, we recorded an impairment charge in the fourth quarter of 9.2 million or 6 cents per diluted share. In last year's fourth quarter, we reported an impairment charge of 48 million or 39 cents per diluted share. Therefore, excluding the impairment charges, net income would have been 32.5 million or 39 cents per diluted share as compared to 9.3 million or 12 cents per diluted share in 2002. Income from continuing operations was 27.3 million in 2003 compared to a loss of 31.5 million in 2002. During 2003, gross margins increased to 253.3 million from 211.4 million in 2002, an increase of 19.8 percent. As you can see, gross margin on revenues were up in all of the Enogex businesses for 2003. During 2003, transportation storage gross margins on revenues were up 17.3 million from 2002. The major factors driving increased gross margins were 6.8 million in year-over-year recoveries of prior under-recovered fuel; 5.5 million relating to a contractual dispute in which we received payment in 2003 as compared to deferring revenue in 2002; 5.2 million of increased margin related to the owning of the Stewart (ph) Storage Facility for all of 2003 as compared to four months of ownership in 2002; 3.6 million from the execution of a new storage agreement with OG&E that began in May of 2003; partially offsetting these positive variances were 4.1 million of gathering revenue that were previously bundled and recorded in transportation in 2002. These were unbundled and recorded in gathering in 2003 as well as miscellaneous other factors. For 2003, gathering and processing gross margins increased 18.3 million over 2002. Gathering gross margins were 9.8 million higher in 2003 as compared to 2002, the result of continued efforts to increase in margins for renegotiation of expiring contracts. The result was a 9 percent increase in margin for MMBtus gathered. Continued strong natural gas prices resulted in new wall connects increasing from 166 in 2002 to 232 in 2003.

In processing, gross margins increased 8.5 million, primarily the result of stronger NGL prices and favorable commodity spreads in 2003. Marketing and trading margins were higher by 6.3 million in 2003 as compared to 2002. However, we reported a cumulative adjustment for a change in accounting principle in the third quarter of 2003 in the amount of $9.2 million related to the marketing and trading business. Therefore, the increase in gross margin needs to be viewed in light of this change in accounting principle.

Total operating expenses decreased 9.9 million, the result of continued efforts to improve processes and lower costs. Interested expense also fell 9.7 million, as we delevered Enogex through asset sales and improving earnings. We expect to reach our 50-50 capital structure target during 2004. That sums up 2003.

Now I would like to briefly touch upon the fourth quarter. For the quarter, we reported a net loss of 1.6 million or 2 cents per diluted share as compared to a net loss of 30.4 million or 39 cents per diluted share in the fourth quarter of 2002. The contribution by business unit on a comparative basis is as follows -- OG&E, a loss of 5 cents in '03 versus a loss of 2 cents in 2002; Enogex, a positive contribution of 6 cents in 2003 versus a loss of 33 cents in 2002; the holding company, a loss of 3 cents as compared to a loss of 4 cents; consolidated, a loss of 2 cents versus a loss of 39 cents. For OG&E, a net loss of 4.3 million or 5 cents per share as compared to a net loss of 1.6 million or 2 cents per share in the fourth quarter of 2002. Gross margin on revenues decreased to 115.8 million from 123.2 million in 2002. The major factors impacting reduced gross margins were lower rates, again, the result of the January rate reduction, which lowered revenues by 7.4 million or 3 cents a share in warmer weather. Heating degree days were 14 percent below normal and 21 percent below last year's fourth quarter. These factors were partially offset by a growth in retail sales that we had mentioned earlier.

In terms of expenses, O&M expense increased 2.6 million to 76.4 million from 73.8 million in 2002. Again, a higher O&M expenses were driven by increased pension costs. Higher levels of labor and bad debt expense also contributed to higher levels of O&M expense. Partially offsetting the increases were lower level of professional services costs. At Enogex, net income was 5.3 million or 6 cents per diluted share as compared to a net loss of 25.5 million or 33 cents per share in the fourth quarter of 2002. As we mentioned earlier, we took a 9.2 million or 5.6 million after-tax impairment charge in this year's fourth quarter as compared to a 48 million or 29.8 million after-tax charge in last year's quarter. This was a very strong quarter for Enogex as they were able to post a positive net income contribution for the fourth quarter despite the impairment charge. Income from continuing operations was 5.2 million as compared to a loss of 27.9 million in 2002. Gross margin on revenues increased 11 percent in the fourth quarter of 2003 to 66.4 million from 59.7 million in 2002. Gathering and processing posted the largest increase, but margins were up in all businesses.

During the fourth quarter, transportation storage gross margins increased slightly over 2002. Impacting gross margins were 2 million associated with the recovery of prior under-recovered fuel. These recoveries were partially offset by reduced demand fees under our transportation contract and the expiration of the storage contract. As we stated in prior calls, the reduction in demand fees for transportation is a timing issue related to collecting the fees on a through-put basis as compared to a flat monthly fee in total 2002. The total fees collected were the same in each year.

Gathering and processing gross margins increased 5.6 million quarter-over-quarter. Gathering gross margins were $3.4 million higher in 2003 as compared to 2002. Higher gross margins were the results of continued efforts to increase margins from the re-negotiation of expiring contracts. Processing gross margins were 2.2 million higher as compared to 2002. Higher NGL prices and favorable commodity spreads drove gross margin higher. Marketing and trading gross margins were half $1 million higher in 2003 due to improved storage results.

For the fourth quarter at Enogex, they also saw lower operating expenses and reduced interest expense. Operating expenses were 5.4 million lower and interest expense was 1.9 million lower in the comparable quarter in 2002. As we have discussed all year, Enogex has recorded several onetime items. And before we discuss the 2004 outlook, we thought it would be relevant to review those onetime items to get a clearer picture of normalized operating earnings. We had a total of 3.9 million in net income related to various onetime items. The recovery of prior -- the under-recovery of fuel provided a positive earnings contribution of 5.9 million. In addition we had the gain on the sale of assets and discontinued operations contributing 4.1 million. Of course, these were offset by the compression impairment of 6.1 million. This math adds back to a $23 million run rate. And this is the starting point for us in looking at 2004.

Looking ahead, we are reaffirming our 2004 guidance of between $1.40 and $1.50. This range assumes that OG&E earns between 113 and 117 million in net income; Enogex earns between 27 and 31 million in net income; and the holding company posts a loss of 16 million. We have also assumed 88 million shares outstanding, reflecting the full year effect of our August equity offering and the issuance of additional drift (ph) shares in 2004.

Specific assumptions for OG&E, we've assumed no change in base rates; just under 2 percent growth rate in retail sales; operating expense increases of 2.8 percent; and then lower short-term debt interest expense. As Steve mentioned, we have plans to increase capital spending at the utilities, over $200 million this year. And these expenditures are across the board in generation, transmission, distribution, and our planned reliability upgrades. For Enogex, we see flat gross margins and operating expenses, but lower interest expense and lower income tax rates.

Before I turn the presentation over to Pete Delaney to address the proceedings before the FERC, I want to touch on three separate and distinct proceedings we have in front of the Oklahoma Corporation Commission. On January 8th, we filed an application with the OCC to confirm that we're delivering customer savings; that we are in compliance with the 2002 settlement agreement; and that no further rate reduction is necessary. Although we do not own the McClain Power Plant, customers are paying less through (indiscernible) purchase capacity, reduction and amount of cogeneration capacity payments and reduced fuel costs. We filed a exhibit with our application demonstrating no savings. That exhibit, which is similar to what we have provided the financial community in the past, and the application, is available on our website. A procedural schedule is expected to be discussed tomorrow in front of the Commission that will set out the relevant dates in this proceeding. We strongly believe that we are living up to the settlement agreement by providing customer savings, and we are on the right side of this issue. In addition, FERC stated in its (indiscernible) on the McClain Power Plant the desire not to see OG&E penalized due to actions at FERC.

On January 15th, we filed a motion to dismiss our pending rate case. Our request was driven by the delay in the McClain acquisition, which was a significant part of our case. Although O&M expenses were higher in '03, and we expect them to be even higher in '04, the improved earnings profile of Enogex provided us the financial flexibility to delay the filing. It was in the best interest of all parties to pursue rate relief once as opposed to back-to-back rate cases. A ruling on this motion is pending at this point.

Finally, I want to update you on the timing of the OG&E recovery and the Enogex gas transportation charges. This case was filed in April of 2003. And while we do not have a procedural schedule, we will expect this case to be heard sometime in the third quarter.

Now, I want to turn the presentation over to Pete Delaney. Pete.

A Steve mentioned in his remarks, the FERC issued an order in late December finding that the proposed acquisition of the McClain facility created both vertical and horizontal market power issues, and ordered the matter to hearing to consider mitigation remedies. Horizontal market power issues considers the potential for higher prices in the wholesale market as a result of controlling more generation. Vertical market power issues consider the ability or incentive to use transmission to raise prices (indiscernible) in-for (ph) entry into a market. Of course, we do not agree with that finding, and had anticipated that the acquisition would be approved by year-end for several reasons. The market power screening analysis filed in our 2003 application, conducted by our consultants, is consistent with numerous fire orders and findings by the FERC showed that no substantive market powers existed as a result of the acquisition. Additionally, we offered in our application to increase transmission capacity if so ordered. That results in more in-for capacity on a more competitive market. The capacity from the acquisition of McClain is needed to serve our retail load not for sale under the wholesale market. Also, not one wholesale customer has intervened in opposition to the acquisition. We are, of course, compliant with the FERC order, and on January the 15, the FERC ALJ approved a procedural schedule that calls for the hearing to be completed in the third quarter of this year. As you may be aware, we have several interveners in this case. And while not asking FERC to deny approval of the acquisition, they would like to see certain conditions attached to any such approval. We are not optimistic that a settlement can be reached with these parties avoiding the more lengthy procedural schedule mentioned earlier. However, given the many errors by FERC in the order, we filed, on January 20, a motion for FERC to re-hear the case. The principal issues we stated are that the findings were contrary to policy under FERC Order No. 642; it was contrary to prior FERC orders on vertical market power; ignores FERC policy on proper methodology for horizontal competitive analysis; and establishes, without explanation, a new standard for judging mitigation. Based on these errors, we are asking, in our filing, for prompt approval and reconsideration. And to remove any doubt as to the effect on vertical and horizontal market power, we have offered even additional mitigation, consisting of four additional transmission upgrades. We have offered to delay closing the acquisition until the transmission upgrades are completed. And also, have agreed to the appointment of a market monitor until the SBP (ph) market monitor is in place under the SBP RTO (ph). And as Steve mentioned, we have had supporting intervention by EEI (ph) and by the Oklahoma Municipal Power Authority, a 23 percent owner in the McClain facility in our request for re-hearing. In light of Chairman Woods recent statements regarding the OG decision and his concerns regarding purchases of distressed assets by utilities, it is clear there has been a policy shift, just as (ph) the standards (ph) by which these acquisitions are judged has changed. Even considering this shift, the additional mitigation offered our motion for re-hearing substantially increases the import capacity into our control areas. For most competition, that is, in our opinion, consistent with the Chairman's statements. We do not have retail competition in Oklahoma. And this acquisition does not harm competition on the wholesale market. On the contrary, OGE, by its actions, have supported development of competitive wholesale markets, having actively led and supported the development of a SBP RTO (ph), for which we hope will be approved in the near future. But

regardless of the strength of our case, these issues will take time to resolve. This acquisition is clearly in the best interest of our retail customers, as the least cost supply option. And we will continue to seek approval as expeditiously as possible. With such barriers to vertically integrated utilities are allowed to stand, our other (ph) utilities' resource (ph) supply options will be very limited in future. Accordingly, we have been in discussions with the plant owners and lenders to extend the asset purchase agreement to be consistent with the procedural schedule approved by the ALJ. For more information on this case and more details on our filing, I will refer you to our website, where you can find the motion for re-hearing that was filed, again, on January 20. Jim.

Before we go to Q&A, I would like to close by summarizing 2003. We had an outstanding year in 2003, and (indiscernible) posted record net income, which helped to offset the rate reduction at OG&E. We also successfully completed our equity offering. And as a result, we have improved our financial strength and increased our financial flexibility. Steve mentioned the numerous examples of operational excellence achieved during 2003, all while we were working to improve our financial position. Despite the delay in the McClain acquisition, we have reaffirmed our 2004 guidance of $1.40 to $1.50. As we look ahead to 2004, we will continue to execute on our plans for both the regulated and the unregulated business. That concludes our prepared remarks. We would now like to answer any questions you may have.

(OPERATOR INSTRUCTIONS). Jeff Gillersleeve (ph), Millennium Partners.

I just wanted to talk to you. I know you went through the rate case and you are going through the correct channels to try to remedy this situation with the McClain Plant. Could you just outline the timing of events? In other words, if you reached a settlement with the FERC in the spring, would you seek to file the rate case again shortly after that? Or if the acquisition was approved, say later in the year, would you then seek -- sort of immediately after approval -- to file the rate case?

By pulling the rate case, we have created ourselves the opportunity to be very flexible as to when we seek rate relief. I think whether it's in the spring or the fall is really going to be dependent upon how we are performing. We also, of course, are earning (ph) increasing capital expenditures at the utility and would try to seek the right opportunity to fold everything together under one filing. So I think it depends.

Okay. And you have made some concessions in your filing for re-hearing or shown a willingness to take some actions. What sort of chances do you see in the timing -- if there were to be a mutual settlement in the case with the FERC -- how would the timing occur on that?

You mean timing of a rate case filing?

No. With the FERC, if there was to be a settlement, at what point do you think that would occur?

I think, as I stated in my remarks, we are planning, for planning purposes, on the procedural schedule that has been established and holds for the hearing to be completed in the third quarter. It's hard to predict the possibility of a settlement, at this point in time.

Sure. Okay, thank you. One last question, on Enogex, a great turnaround there. The performance in the fourth quarter was very strong. As we look into '04, you mentioned in the assumptions some slightly lower margins. Could you give any more detail on how you see the commodity price environment and how you see your gathering and processing diversification? In other words, the keep-whole (ph) contracts and others, the other type contracts?

Sure. Just going back to assumption at Enogex (indiscernible) gross margin, we see fairly flat gross margin. You must keep in mind that that incorporates the fact that we had some onetime items related to the recovery of prior years' fuel. So if you look at it on that basis, even though it's flat, it incorporates stronger margins from the ongoing business. We are, from a price environment, we see -- we achieved around 50 cent liquids for the 2003. We see lower liquids prices in '03; we see about 4.50 gas. We see continued strong commodity prices but lower liquids prices in '04.

Doug Fischer, A.G. Edwards.

Thank you and congratulations on a very solid year. Just a couple things, could you outline for us the main issues in this pipeline rate case -- I mean the Enogex gas transportation rate case? And then, did I understand correctly, Pete, that you said you were not optimistic about reaching a settlement with the interveners in the McClain case? Maybe you can elaborate on why, even with the conditional mitigation you have proposed, you're not optimistic.

Again, what I was referring to mostly is the (indiscernible) interveners in the case. I guess we are not, at this point, optimistic that we are going to be able to settle with those parties anytime in the near future. Again, from a planning standpoint, we are prepared and are planning to see it through the hearing process.

I am going to turn over, Doug, your question on the gas transportation case, to Howard Motley (ph), who is Director of Regulatory Strategies.

In the gas transportation case, it has been extended because the Commission is wanting to look at a cost of service. So the company is now putting it together and we will file that with the Commission around April. The hearing will be scheduled probably in July or August. Recently, the Company has had meetings with the staff, and the staff is still very supportive of the dollar value of the contract. The real issue in the cases policy -- the Commission has wanted companies in Oklahoma to use competitive bidding in determining contracts. The Company did not competitive (ph) bid (ph) this. And so that is the issue that will have to be adjudicated in the case in August.

(Indiscernible). How do you expect this as a rate case? Or are there some documents on your Web site you can refer me to?

We have pre-filed testimony in the case explaining why we did not competitive bid and setting out the value of the contracts and explaining how they're market-driven. I don't know if we have that on our Web site or not. But we do have that as public information at the Commission. We will put the testimony and application of the Getra (ph) (indiscernible) case on the Web site.

Thank you. And I want to commend you for all the good information you post on your rate cases. I think you are fairly unusual in the amount you post on your Web site, and it is very helpful. That's it for now.

Paul Debbas, Value Line.

I have got a couple of questions. First of all, what are your financing plans for this year, and how would that be affected depending on whether you complete or don't complete McClain?

Incorporated in our guidance are the assumptions that Pete mentioned that we acquire McClain later this year, under the FERC schedule, that we would issue debt at the utility to fund the debt portion of that. Remember we did the equity last year. We have also assumed about $50 million or so of direct (ph) in the last half of '04. So our funding plans are very much dependent upon McClain, as well as the Commission action related to the $25 million.

What would the debt be, about 70 million?

We are assuming about 110 debt at the utility, because it incorporates not only the power plant, but other capital programs as well.

Some of that would be for McClain and some would be just for other things?

The capital we are doing this year -- we had the ice storm in 2002. So it's really to cleanse the balance sheet and take us to the 56 percent equity. Keeping in mind that we have the ability, with our 2002 stipulation, to close on McClain and create a regulatory asset for up to 12 months from the time we close it. And that gives us that flexibility.

You said your target is 56 percent equity ratio?

Yes, that's what was in the our last stipulation.

Is that at the utility, or is that for the total company?

That's the utility.

Do you have a specific target for total company?

We do not. We're targeting 50-50 at Enogex. And then, we are looking to keep our financial profile consistent with the current ratings as we strengthen and create financial flexibility.

What tax rate do you expect to use this year?

38.7.

Can you please repeat that?

38.7, Paul.

Jeffrey Cavalio (ph), Duquesne Capital.

I was wondering if you could lay out, if possible, you're CAPEX projections for 2004? I know you mentioned that if you don't have that $25 million credit applied to OG&E that you might be able to spend more money on reliability. I was wondering if you could kind of break out the CAPEX into rate base additions, as compared to maintenance? And I guess going along with that thought process, if the rate case is filed at the end of '04, you will be able to include that additional investment in reliability in the rate case?

Correct. I would say -- we're targeting about 212 million at the utility. Sort of normal routine, year-over-year projects, are around 150. The nature of that 150 changes from year-to-year. But that would be our normal run rate. So we really increased capital spending by over $50 million. And it's really to increase reliability and increase capacity on distribution; also, increase reliability and capacity for transmission, as well as increase spending for coal plant reliability and that gets us obviously less forced outage rates on a coal plants, more reliance on coal, which ultimately reduces costs to customers.

Would you be able to include some of those dollars on the rate case if you were to file it after they were spent?

File it after they were spent? Surely; it really depends on our timing when we go in. But typically, we file and we update the test year for known and measurable changes for six months after the test year. So that would be sort of be the timing we would incorporate that.

Zack Schreiber, Duquesne Capital.

All my questions have been answered. I just want to say great year, guys. I really appreciate all the hard work and focus, as an investor.

Thank you, Zack.

David Frank, Zimmer Lucas.

Jim, could you just give the guidance range for Enogex again, for 2004?

It's 27 to 31 million.

Okay. And you said you are essentially assuming flat margins but lower interest expense there?

Right. And you know we have been on a deleveraging program; we have paid down debt. We have 51 million of debt maturing in 2004. That's what's driving lower interest expense at Enogex.

Did you use to have -- or was there an original projection for what margins would be, or what the net income contribution would be for 2003 at Enogex? Can you remind me? Was it about 23 million --?

You are talking about what we had in our '03 guidance?

Yes.

We started the year at 14 to 16, and we moved up to 20 to 22 in our third quarter call. So we obviously exceeded the guidance at Enogex.

I guess built into this guidance now for '04 is lower liquids prices at 4.50 gas?

Correct.

The gas price seems a little conservative. If you have higher gas prices, will that bring up liquids prices?

There is a correlation between gas and liquid. It's not a perfect correlation. But they will react to gas prices.

And would that benefit you? Would higher gas prices in fact benefit your processing business? Or liquid business?

Well, higher gas prices has a negative impact on certainly your keep-whole. But we have a treating (ph) fee, which proved, in '03, to mitigate that impact. Obviously, on our liquids prices, will help POL and contracts which we saw as part of the strong processing results in 2003. Keep in mind that keep-whole is a very small percentage. The treating default processing fee is now only about 10 percent of volumes at in processing.

Right. I remember it used to negatively -- on your exposure to the frac. (ph) spread, it would negatively affect you a lot of times.

It would. But again, I think the imposition of the default processing fate has -- and I think '03 was the year that shows it mitigates your volatility to the downside while still giving you the upside on processing.

What about the opportunity for capturing higher margins on some of those contracts that expired? Do you have contracts expiring in 2004?

Yes. The benefit, as I mentioned, in gathering throughout the year -- as contracts re-negotiated -- would expire -- we would re-negotiate higher margins at the wellhead. So that effort is ongoing. As contracts come up for expiration, we continue that effort.

So there are contracts expiring in 2004, which may provide you with an opportunity to re-negotiate -- book -- higher margins. But you are not factoring any of that into your guidance?

I think there is some benefit of re-negotiation already built into the guidance, based on history and what we see coming up and who the customers are and things of that nature.

Paul Debbas, Value Line.

What is your CAPEX estimate for the total company?

It's 212 for the utility; Enogex is around 33 million or so. So consolidated is 245.

(OPERATOR INSTRUCTIONS). It appears we have no further questions. I will turn it back over to our speakers for any concluding remarks.

We would really like to thank you for your interest in the Company and your participation in this call. Have a good day.