OGE Energy Corp (OGE) 2002 Q4 法說會逐字稿

Good day. All sides are now on the conference line in a listen only mode. My name is Emily. Should you require any assistance throughout the call please feel free to press the star and zero on your touch tone phone and at this time I would now like to turn the program over to your host Mr. James H. Hatfield. Chief financial officer.

Good morning, and welcome to OGE Energy corporation's fourth quarter conference call. I have with me Steven Moore, Chairman and CEO. Al Strecker, Pete Delaney, Donald Rowlett, Eric Weekes and Danny Hears.

We will start with comments from our chairman Steve Moore, we'll look at the 2002-2003 out2003 outlook. We'll have comments from Pete Delaney and we'll turn it over for question and answers.

I would like to point out to everybody to the Safe Harbor statement contained in the press release. And with that I'll turn it over to you Steve.

Thank you. Good morning. Appreciate you joining us this morning. Today, we reported a loss of 39 cents a share for the fourth quarter due to the impairment of about $50 million in the value of some natural gas assets at Enogex.

Without that impairment, it was a break-even quarter which was not unexpected by us. For the year, we earned $1.16 a share. Excluding the impairment, we earned $1.55 in 2002, up from $1.34 excluding impairment in 2001. We improved our operating results at both Enogex and OGE any and lowered our interest expense. It was a pretty solid performance considering we did in it in a year with a summer that was 11% cooler than 2001.

We cut costs restructured operations sold assets and reduced debt by 17% at Enogex, and as a result reduced the risk profile of the company. Our cash flow remains strong. It continues to meet our capital needs and cover our dividend. In the year ahead, we face a number of challenges starting with a $25 million a year rate reduction at OG&E.

The rate order we agreed to encourages us to acquire new electric generating capacity. Making that happen with the right asset at the right price with the right financing is a top priority. The financing of the new power plant is expected to include, as one component, the issuance of equity in 2003 to support our capital structure.

We are excited about the opportunity for growth this power plant acquisition presents at the utility. OG&E remains a strong performer, fundamentally strong, for the third time in the last four years we were recognized by the Edison electric institute with their national emergency response award. Our people and our practices were put to the most difficult test in our 100-year history after the ice storm last January. Our employees' response was nothing short of remarkable. These are the same people we are counting on for results in the year ahead and we are confident they will deliver those results. They continued their work on a process redesign program that will continue service and financial performance. We are beginning to implement these initiatives and expect not only better results, but also, opportunities for growth moving forward.

At Enogex they have completed their reorganization. Enogex will continue to cut costs, reduce debt and focus on performance. The charge of $50 million announced today demonstrates our commitment to improving performance. We will have a natural gas pipeline that has lower costs, lower risk, lower debt, and more stable, reliable earnings. We continue to believe that our asset based, core focused operations will deliver value over the long haul.

In closing I'd like to say just a few words about our recent credit rating down grade from Standard & Poor's while we are in no way satisfied with our rating down grade we remain a strong investment grade credit with a stable outlook.

I thank you for joining us today, and for your continued interest in the company. At this time, I'd ask Jim Hatfield to walk you through the details of the quarter and year end. Jim.

Thank you, Steve. I would now like to cover the earnings of OGE Energy corp and I'll cover the full year first and talk about the fourth quarter. As Steve talked about for 2002, we reported earnings of $1.16 a share compared to $1.29 in 2001. Included in both years are impairment charge, $50.1 pretax or 39 cents a share in 2002 and $6 million pretax or 5 cents a share in 2001. Therefore on a operating basis we earned $1.55 a share in 2002 as compared to $1.34 a share in 2001. Absent the impairment charges we exceeded our guidance we issued earlier in the year and we felt we had a good year in spite of the challenges. I'll provide an overview of the impairment charges when we discuss the fourth quarter.

I'd like to point out a couple of presentation items in the financials. We discussed last quarter the change purchase pursuant to EIT F 02-03 of revenues reported as net versus gross for the unregulated business. As a result of further guidance we received from the accounting profession, the industry is again reporting revenue from sales result that result in physical delivery on a gross basis so that's a change from the third quarter. We will also be impacted in 2003 by EIT F 02-03 and I'll discuss that in a moment.

As we stated in the last quarter we have broken out our discontinued operations. Those operations consist of our Bellvan(ph) in West Texas which were sold in February, 2002; our ENP (ph) ENP (ph) operations which were sold in September and December, 2002; and our NuStar joint venture which is West Texas gathering and processing (ph) expected to close in February. For the full year 2002, excluding the impairment charges, we set $1.55 as compared to $1.34. The breakout by businesses OG&E, $1.61 a share compared to $1.55 in 2001; Enogex 10 cents a share compared to a loss of a penny a share in 2001 and OGE Energy Corp, the holding company a loss of 16 cents a share as compared to a loss of 20 cents a share in 2001.

For OG&E specifically net income of $121 million, $1.61 a share as compared to $121.2 million or $1.55 a share in 2001 - which represents an increase in earnings of 4%. The components of that increase are as follows: revenue net of fuel, were up $1.9 million or 1 cents a share. We had growth just short of 3% at 2.9% increase offset by cooler weather, as Steve mentioned. Cooling degree days for a year were 3% below normal 10% below normal of 2001. That equates to about 3 cents. The Arkansas energy cost recovery rider (ph) which is a timing issue related to recovery of fuel was off about 5 cents and then the generation efficiency performance rider which went away June 30 off system sales and various other riders was about 7 cents so revenue net of fuel up 1 cent year-over-year. O&M was down 4.3 million or 3 cents a share at a level of $283 million. The big driver of the O&M was uncollectible were down 11.5 million or 9 cents a share offset by predominantly pension and medical costs up 9.9 million year-over-year. And I'll point out the OEM being down year-over-year, we did set up a regulatory asset for 5.4million dollars this year related storm costs [ph] which we will recover over the next three years. O&M benefit is 3 cents, interest and depreciation, a little higher appreciation offset by lower interest cost. Enogex net income, again these are without the impairment charges, net income of $7.8 million, 10 cents a share compared to loss of 1.3 million or 1 cent a share in 2001. The components of the net income are as follows EBIT, transportation and storage $48.1 million versus 36.8 million in 2001. Big drivers for the increase in transportation and storage recovery [ph], better fuel recovery in 2002 versus 2001. We had firm revenue increases from the IPP projects Calpine and Co-JENTRIX (ph) a little higher operating expenses, volumes were essentially flat, off 1%. Gathering and processing loss of 2.7 versus $7.8 million of EBIT in 2001. Gathering volumes, off about 8%, year over year, processing volumes were off about 43%, and we have lower expenses in that sector.

Marketing a positive EBIT contribution of 900,000 versus a loss of 4.8 million in '01. Again that's based on better revenues, and around storage for the marketing unit. And then of course ENP add 5.2 million dollars compared to 8.7. And we have exited that business, as I said earlier. On the consolidated basis lower interest expense 48.5 million compared to 64.7 million in ’01, reflecting the reduction of debt.

And I'll point out as well when you look at the full year results were also adversely affected by unusual charges which include the loss from a large customer bankruptcy, lost gas expense and severance cost and these things aggregated about 6.8 million in total.

In terms of the fourth quarter, a loss of 30.4 million, 39 cents a share compared to loss of 6.3 million or eight cents a share in '01. We talked earlier about the impact in impairment in both 2002 and 2001, 39 cents a share and 5 cents a share respectively. So on an operating basis we had exceptionally a break-even quarter in 2002 compared to loss of 3 cents a share in '01. Again a quarter with some improved performance.

I'd like to discuss the nature and the amounts of the impairment cost. The majority of these costs related to compression of processing assets that are no longer used in the business. These assets have been taken out of service and will be sold. Those assets are all at Enogex. There was also a miscellaneous charge to the holding company. And the impairment is really the difference between the book value and the market value of those assets. As these assets are sold in 2003, we'll realize the proceeds and continue to pay down debt. And the breakout of those impairment charges are processing, 40.5 million, compression 7.8 million and miscellaneous 1.8 million equaling(ph) the 50.1. The breakout order- again adjusting for the impairment charges is OG&E, a loss of 2 cents, as compared to a loss of 8 cents a share in ’01. Enogex earned 5 cents a share as compared to earnings of 11 cents a share in '01 and the holding company reported a loss of three cents compared to loss of six cents in 2001. For OG&E the breakout of the comparison of the 2 cent loss in '02 versus eight cents in 01 revenue net of fuel was a big driver, six cents a share. Weather was on a heating degree day 10% above normal and 30% above the level in 2001 which contributed to about 4 cents.

We had the timing of the Arkansas cost rider, offset by GEP and off-system sales and other riders, the net benefit to revenue 6 cents. O&M was essentially flat. We had the uncollectible benefit in the quarter offset by pension, medical, and interest and interest and depreciation was essentially flat for year six (ph in comparison.

At Enogex net income of 3.9 million or five cents a share compared to a net income last year 11 cents a share. The components are transportation storage, 13.3 million, versus 17 million last year, again, better fuel recovery and the IPP revenues offset by lower storage fees and a little higher operating cost. Gathering processing, negative 6.5 million this year versus 7.2 last year, again the big driver in that sector continues to be lower volumes. Marketing down slightly 2.8 million versus 4.4, lower expenses offset by lower storage revenues and E and P 3.6 million versus negative 6 million in 01 and of course we've exited that business. Two other issues I think we ought to highlight today, one is liquidity. On January 8 we renewed our commercial paper backup facility. The facility was 10% oversubscribed. We the facility from increased from 190 million to 200 million, while also bringing in three new banks. So we've had no problems in accessing the capital markets.

The other issue is a status of our pension plan at 12-31-2002 our plan is 71% funded. We made contributions of $48 million last year and will fund $50 million in '03. Both contributions were planned and incorporated into our financial projections. The impact is really our F 87 expense news (ph) from 25.2 million in 2002 to $35 million in 2003. So we'll have an increase in Fas 87 expenses. 2003, our projection is to earn between 1.35 and 1.45. To earn between 112 and one 13 million. The breakout is for OG&E to earn between 112-118 million. Enogex, to earn between 14 – 16 million. And we see the holding company with a loss of approximately 14 million.

I talked about the impact of EIT F '02-03. It will impact earnings that are not in that range that I gave you. We'll book a charge in the first quarter related to the change in accounting principal as relates to how we account for storage. The charge will be partially offset during the year by the charge for physical storage but we're unable to predict the amount of the charge and the impact in fiscal '03 at this point as we nail down the exact accounting treatment.

I will reconcile the results of 2002-2003 as it relates to OG&E, starting with the 2002 net income of 126.1 million. Revenue net of of fuel loss we see as $10 million in'03 from 02. Rate reduction began January 6th, that will be $25 million. The GEPR, the generation efficiency performance rider, was discontinued effective June 30, 2002, so that impact in the first half of the year is about $3 million. We're projecting growth to be right around 2%. That's $14 million cost dif(ph) and then we had $4 million of negative weather. And that reconciled back to negative $10 million year-over-year.

We see OEM being about 10%, $10 million greater in '03 to '02, driven again principally by increases in pensions and other positive impactors about $17 million, so we see that net income being right around $115 million with the range again 112 to 118.

OG&E is pretty straightforward with the risk factors for the utilities. Net income being the weather, our ability to control O&M (ph), and, of course, customer growth.

In terms of the spread of net income by quarter, continue to see a loss in the first quarter by both OG&E and Enogex, with roughly 25 [inaudible] ,over our net income in the second quarter and 75% of our net income in the third quarter so again we generate significantly all of our net income in the second and third quarter. The fourth quarter should be a break-even quarter with Enogex posting a profit and the utility posting a loss. And with that I'd now like to turn it over to Pete Delaney to discuss the 2003 Enogex outlook. Pete.

Thank you, Jim. Spend a couple of minutes speaking about 2003 and how we expect the performance relates to 2002. I believe we approached the year 2003 A much different company than we approached the beginning of 2002, in terms of concrete measures, as Steve mentioned we reduced debt by $129 million in Enogex roughly 17% of our total debt. Further we reduced headcount by 12%. That's not including the sale of the west Texas asset at which time our employment would be down 17%, the effects of the ENP business. We believe we reduced our downsizing side exposure to processing margins through the settlement of the FERC (ph) proceeding in which we expect and order this quarter, and we are in the final stages of selling our West Texas asset.

On the organization or soft side we've reorganized the company strength and leadership and improved our work process. And the implication for 2003 are lower fixed cost, less exposure to our margin from commodity prices, better management our of commodity exposure and a management team focused on the performance.

I’d like to spend a little bit of time talking about the drivers of the projected $223 mill gross margin for Enogex for 2003. Roughly 120 million of that 223 million, or over half, we expect to come from our transportation and storage segments. And as you know these revenues are driven largely by the OG&E and PSO gas transportation contracts for the most part. In addition to that, we have firm demand transportation contracts with independent power plants. In gross margin in the transportation and storage sectors is expected to increase, again due to the full year operation of the Oneida power plant. In addition, we have this year the full year's operation of the Stuart natural gas storage facility which provides gas to the Seminole [ph] power plant, which we acquired last fall. Again we acquired that asset utilizing a favorable arbitration award. In other words we didn't pay any cash for that asset.

Gathering gross margin from 2003 is expected to contribute about 25% of the total gross margin. That's less than last year, due to projected volume decline. Our profits and gross margin, again, this is a segment in which we have a lion's share of our commodity volatility, expected to contribute only 10% of our total gross margin and again the margin from that segment is projected to be down significantly again because we are assuming in our 2003 projections the sale of the West Texas asset. In addition, we are projecting lower volumes in Oklahoma and again we are assuming relatively flat processing margins compared to 2002.

The marketing segment is expected to contribute around 10% of total gross margin, increasing its contribution through increased volumes and higher margin. And without the ENP segment and given the other factors cited above total gross margin for 2003 is projected to decline again by $11 million from 234 in 2002 to 223 in '03 which is about a 5% decline. However, offsetting that decline in gross margin, it's projected $28 million reduction in expenses. And this decline in expense is driven largely by the headcount reduction accomplished in 2002 that I mentioned a little while ago. The reduction of expenses associated with the discontinued operations, again the West Texas assets in the E and P segment reduced operating expenses again years occurred in 2002 particularly those associated with severance and receivable write down and then lastly a decline in interest expense associated with the roughly $129 million that we've paid down in 2002, and again, we will pay down additional debt through the sale of the West Texas asset in February and through the sale of the compression (ph) of processing the assets (ph), for which we took the impairment charge.

I'd like to also at this time, I think it would be a good time to point out that there is more seasonality in our earnings in 2003, and that's driven some of that's driven by the change in our business mix. The seasonality is due primarily to the timing of our transmission fuel recovery. We under recovered our fuel costs in the first quarter of the year and we over recovered them in the third quarter predominately in the third quarter. Also our cost savings of 2003 are more heavily weighted towards the second half of the year, and we expect again to realize a lot of the storage revenues in the later part of the year as well. As a result, we are projecting and part of our plan is we expect losses in the first quarter of 2003, and we expect to realize half of our earnings in the third quarter of the year, with the remainder of our earnings roughly split between the second and fourth quarters.

Of course as Jim mentioned, any change in accounting principles around the mark to market accounting impact, the timing of revenue recognition (ph) associated with the optimization of our natural gas storage asset. We are planning to visit with the investment community later in the first quarter at which time we will review these numbers in greater detail. Jim.

We will now turn the -- over to Q&A.

Thank you. Mr. Hatfield.

At this time if you would like the ask a question, please press the star and 1 on your touch tone phone at this time. To withdraw your question at any time you may press the pound sign. Once again to register for a question, please press the star and 1 on your phone now.

We will take our first question, from the site of Devon G. Gagen with, Luminous (ph). Please go ahead sir.

Thanks so much for the call this morning guys, I appreciate it. Just wanted to get the utility breakdown again in terms of how you go from 126 of net income just down to about 115. I think it was 10 million decrease in revenue 25 rate case 3 million for some rate rider, but then you get 14 million of revenue for growth I think --

And $4 million for to normalize weather.

Okay and then OEM hits by about $10 million?

By about 10 million.

I guess I think that takes about $19 million of net income away, just assuming like a 36% tax --

Well, there's about $3 million of miscellaneous adjustments that work in our favor. I think the total is about $17 million.

Okay. So gets you to about $110. I guess I'm just trying to see how the 110 gets to 118.

We are using the 37% tax rate. But there's upside and downside associated with that number.

Okay.

And again our ability to control O&M will be key. We have continuing--you know, customer growth, and so we just put our number there at 115 and then put a range around it to pick the upsides and downsides.

That makes sense. And is the pension funding, the $50 million, is that required or optional contribution?

That's an optional contribution. Again, you know, we have typically funded our level of Fas 87 expenses to the extent we get behind from a funding perspective, we do fund more. The $50 million that I mentioned has been incorporated in our plan, and it is not a surprise. We have been in a position of trying to fund that plan over the last couple of years.

One last question, I appreciate the time. Can you just run me through your expected, I guess, cash flows CFI/ CFF this year, just to get me to a beginning cash balance in '03 and ending cash balance in '03?

Yeah, our cash from operations not taking into account working capital changes is expected to be in the vicinity of $300 million. And then we're looking at, again, this is, as you know, we have the rate settlement where we acquire power plant. [ph] But absent that we looked for Capex around $157 million this year to utility and about 39 at Enogex on a consolidated basis. So that's about 196 or so.

Okay. And then, cash flow from investing, I don't know if this is the right way to think about it but it seems to me that you know I thought you had said you were going after a 500 megawatt plant and just assuming the recent prices of 350 to 450 that gets you to a cost of let's just call $200 million. I guess are you -- do you still think you're going to pay -- use -- issue about 200 million of equity to that? Because it seems like your EPS numbers seem to weight a $200 million equity issuance about July, August of this year.

Our equity assumption would be to obviously issue equity to support the capital structure with the purchase of a power plant. You know, it's 400 megawatt facility is what our order contemplates. And using $400 at KW it's $160 million. So with a 56% capital structure we would be looking at about $90 million in equity for that power plant.

Okay. I guess --

And again those are sort of the basic assumptions we would use from a planning perspective.

OK. The rating agencies I thought they were of the assumption it was done with all equity. Are they comfortable with the --

Oh, no. They understand, and what was presented was a plan that was to get the utility at a 56% capital structure. I don't think they believed it was going to be all equity.

Thank you for your time. I appreciate it and congratulations again.

Thank you. We shall now take our next question from the site of Rick Shobun with Dusquesne Capital (ph).

Goood morning. I was wondering if you could give me through the Enogex, EBIT breakdown for the three segments for three segments - the gas processing, transportation and marketing and trading.

Yes, the EBIT breakdown in '03 is transportation and storage, you know, $53 million, which is about 76% of total EBIT, GNP is about $ 6 million and marketing is about 10 million so about 69 million EBIT. So that would be the breakdown.

Okay. And then my last question is, as far as the acquisition of the power plant, the $400 million -- 400 megawatt power plant, will that be addressed in the -- when you putt that into your utility, will that be addressed in the 2004 rate review?

Yeah. Our assumption is that we would purchase the facility in '03, pursue rate relief, and the rate increase would go into effect 1-1-04. So there would be no revenue associated with the power plant in our 2003 forecast.

When do you file for the rate relief?

It's dependent upon the timing of purchase of a plant. So but we would contemplate some time second quarter, sort of time frame.

And have you targeted a specific asset that are -- already, have you just begun looking?

No, we've targeted several assets in our region, and we have -- we are under discussions with the parties.

Does the asset need to be in the state or can it be outside of the state?

I think the -- we are looking primarily in our -- in the state.

Okay, thank you very much.

Thank you. We shall now take our next question from the site of Paul Debis with Value Line. Please go ahead sir.

I'm Paul, I have two questions. Steve mentioned that the cash flow was adequate to meet the capital needs and pay the dividend. Are you still saying that the dividend is secure at this level at least for the short term, meaning '03?

Yes, I am. Repeat what we said before. We're committed to our dividend.

Okay. And what's the book value of the assets that Enogex intends to sell?

Are you referring to what we've already sold or --

Well, the ones that were written down, that you referred to that you want to sell now.

$21 million.

Okay. Thank you.

Thank you. Our next question will now come from the site of David Dickens (ph) with Deep Haven Capital. Please go ahead sir.

Most of my questions have been answered. I would love to have you just clarify just what exactly in terms of the new power plant is assumed in the $115 million guidance at the utility. Can you walk us through what --

Yes, what's assumed in '03 is really no -- no rate relief, and remember, our order to the extent that we get to create the regulatory asset, any charges associated with the plant '03 would be booked as a regular regulatory asset beginning in '04. So there is really no impact embedded into the forecast from the power plant in '03.

But it does appear that there's -- that share -- I mean if you do the simple math, and take the EPS numbers that you gave, and then look or the net income number and you translate that to an EPS number we are looking at a bump, fairly significant bump in shares. So there is an assumption of the equity being issued?

That's correct. Our plan would be, once the power plant is, you know, secure, that we would access the equity market. So there would be some prefunding in '03 for the -- in advance of the rate relief.

Okay, thank you much.

Thank you. Our next question will now come from the site of Paul Patterson (ph) with Glenrock Associates (ph) Please go ahead.

Good morning. I wanted to ask you a little bit about EITF 02-03. Is it your expectation that the benefits from your accrual will fully offset the loss from mark to market gains that you guys have been benefiting from? Do you have any more color on that?

Well, I can probably -- we have marketed our gas and storage to market following the accounting under 9810 so we will basically be writing it back to cost. Within most of those, as we produce that gas, and take it out of the whole we'll recognize those gains. So to the extent we get all the gas out during the calendar year it will be a wash. To the extent some of the gas carries over to '04 there would be some of those earnings that will go into ’04..

Okay. What about the transportation contract?

With -- it really shouldn't have any impact.

It shouldn't, okay. Then also, on the dividend payout, what what's your goal over the long term in terms of what you think the payout should be? I mean, it does look a little high here. I'm just trying to get an idea as to what you -- what's your perspective on the dividend payout.

Well, we've been consistent on that. We maintain overtime, our goal is 75%.

Okay. And then finally, on the uncollectible reduction of the uncollectebls, what made that go down?

In the -- I guess in the uncollectebles, we've implemented several steps and we've made process improvements that have reduced the amount of uncollectible accounts. You know, I think it was also one of the drivers this year was a milder weather, so as the summer bills don't get quite as high we tend to have better recoveries.

Okay, well thank you very much.

Thank you. Our next question will now come from the site of Doug Fisher with A.G. Edwards. Please go ahead.

Thank you and good morning. Could you go over the '03 cash flow outlook in a little more detail, Jim? Because I'm just trying to reconcile it with what you said on your October 17 presentation. I believe, then, the operating cash flow was 320. Is that now 300?

Yes.

And what are the maintenance cap expenditures for OGE and for Enogex?

Well, the maintenance CAPEX, or what we would assume, you know, on an annual, like $120 million roughly, which would be, you know, just normal customer hookups, that sort of thing, we're projecting a little higher number in '03 as we work on some reliability projects that we really have not worked on over the last couple of years.

Enogex CAPEX this year, it's looking like $39 million, although I would say that from a maintenance level, it's more like 25 to 30 million, and we're planning some technology upgrades in some of those things in 2003.

And then we would -- so we'd have the 157 plus 39, at the two units, then we'd have the -- is it 50 million for pension as well in '03?

That's correct.

And --

But Doug, $35 million of that is already built into the net income number so you're really talking about incrementally 15 million.

Okay, right, right. Okay. And then we'd have the power plant, and then we'd have the dividend. So the -- what amount of additional incremental debt do you expect to have to finance, given all of this in '03, roughly?

Well, on a long-terminator, your long-term debt would really just be your 44% piece of your power plant. So if it's 160, you know, you'd be talking about a number more like 70 million. The others, if you walk through your cash flows were we're also have the sale of assets in there. Which --

And what's the total? You've got the West Texas plus the assets you just wrote down. So what's the total of those?

Well, West Texas book value is roughly 35 million, your compression after the write down is 21. So that's 56 million at book.

Okay. Thanks, Jim.

So we don't see any incremental requirements for debt other than --

Other than the power plant portion?

Power plant and get the utility cap structure, yes.

Okay, thanks.

Thank you. We shall now accept our next question from Norman Greenberg with Greenberg Consulting. Go ahead sir.

Hi, Pete.

Hi, Norm.

I'm -- the pension plan, did I understand you to say is now 71% funded?

That's correct.

When do you expect to bring it up all the way?

Well, we plan -- based on the current discount rates. Based on normal assumptions it's going to be in the vicinity over the next four or five years. But as we know, we've had two years now the perfect storm related to TB (ph) plans with very low discount rates and negative return, but just based on normal assumptions it would be over the next four or five years.

How was the pension plan funded as far as between debt and equity?

It's about a 60% equity, 40% fixed income mix.

Was it 60% equity is what's been hitting -- what's been getting you. Okay. Now, I missed your forecast for '03.

Okay. It's $1.35 to $1.45. Which is really OG&E the utility, $112 to $118 million, Enogex 14 to 16 and the holding company about a $14 million loss.

Okay, I thank you. Thanks.

Thank you, Norm.

Thank you. We shall now take our next question from the site of Nick Basalacos with Eaton Vance. Thank you sir.

Good morning, thank you for taking the call. I was wondering if you have a comment, was there any effect on your working capital as to the S&P downgrade to BBB. Also if you could give us a debt and cash balance for the quarter end.

There has been no impact on working capital from the down grade. As you know we're now triple B plus with the stable outlook. We were -- we had a negative outlook so there hasn't been any real change. We're sitting at quarter end. And your question was what's our cash balance at quarter end?

Yes, cash and debt, please.

Our short term debt at the end of the year was about $275 million..

Okay.

And then the total debt on a consolidated basis is about a billion 5.

In cash?

Cash balance?

Yeah.

Cash balance, about $30 million at the end of the year.

Great, thank you.

Thank you. Our next question shall now come from the site of Devon Gohagen (ph) with, luminous Management (ph), go ahead fir.

Follow up questions, one is on the debt structure. How much debt is still at Enogex?

Enogex currently has long-term debt outstanding of $591 million, which is $550 million long term debt and $41 million as the joint venture which is non-recourse.

DEVON GOHAGEN Okay. Just somebody asked a question earlier on the share count, and I had a follow-up to that. It seems like if I just add up the stuff you get like a buck 43, it's like 10 cents higher and I would assume that the plant isn't going to be purchased you know sometime before mid year. So it really seems to me that the equity assumed in your numbers is probably closer to 150, 200. Does that make sense and would you use that extra to continue paying down debt at Enogex or --

We -- the assuming for the $1.35, $1.45 is 83 million shares outstanding.

Obviously timing is going to have a big part of the shares outstanding during the year, and we would obviously access the market when it's the best time to do that taking all the factors into account.

DEVON GOHAGEN Is that a -- is that an average shares or is that absolutely basic shares?

That's average shares outstanding.

DEVON GOHAGEN Okay, thank you so much. Congratulations again on a good '02.

Thank you.

Thank you. Our next question will come from the site of Paul Devost as a follow up from Value Line. Go ahead sir.

Regarding the equity offering, it definite that it would be one of those straight offering, rather than one of those hybrids?

I think our plan would be to issue straight equity.

Okay. Thank you.

Thank you. Our next question comes from the site of Doug Fischer again as a follow up from A.G. Edwards. Please go ahead.

Just like to follow up, Jim. When do you expect to hear something from Moody's to resolve their ratings with your company?

Well, we visited S&P and Moody's at the same time and S&P acted a couple weeks ago. We would expect Moody's to take some action here soon. Other than that, we really don't know about timing.

Okay, thanks.

Our next question shall now come from the site of Andy Levi (ph) from Bear Wagner. Go ahead sir.

Which is sense, keeping the dividend paying out at 100% or close to 100% of net income to dividend. I understand you are buying a plant but you have to issue stock too. Looking what we all learned in school the prudent thing would be to either have an increase in earnings which doesn't seem very likely in the short run, or do something about the dividends. So I just want to understand really the thinking beyond just the statement that we're going to keep the dividend. What is the business reason for keeping the dividend?

Well, we note that our investors rely on the dividend. And as we said many times we are committed to it. Our dividend is based on earnings over the long term. And in the short term our cash flow is strong. So that's the reason we are committed to our dividend.

But is there a business reason why? I mean I understand, you know, basically the mom and pop theme of it. But is there -- is there a business reason that you think that over a year or two You're going to be able to work yourself out. you're talking a four or five year period to get to a 75% payout ratio. It doesn't seem to me that it makes a lot of sense. So if I were to buy the stock or do something else with the stock, I just really want to understand what the business sense is. Is it just to keep it to make your shareholders happy or is there a business reason for keeping it?

No, we see, as you've heard, we see Enogex's performance improving and we see a path to grow our utility company with the acquisition of a power plant. So we think that business case supports our dividend policy.

Okay, thank you.

Our next question now comes from the site of David Frank with Zimmer Lucas Partners (PH). Please go ahead sir.

Hi, good morning, Jim. I just wanted to clarify on the shares, you were saying that the '03 earnings assumption assumes 83 million shares outstanding, or that was average shares?

Average shares.

Average shares. And you're looking at doing kind of a mid-year equity offering?

Well, it -- obviously the timing would be around a plant which would be a second or third quarter sort of event. The 83 million is the average. And obviously that could go up or down depending on when we access the market.

Right.

So that's our assumption that's embedded in the plan. You can, you know, make your own assumption on what that impact is depending on, you know, when we actually come in.

Because if I was to take $90 million and assume that that's going to fund the equity portion of your acquisition, that would get me to around 83 million shares right there.

Right.

outstanding. So you're either doing, I'm assuming and I missed the very beginning of the conference call, I apologize, are you looking at a larger acquisition, maybe something twice the size or additional equity to repair your balance sheet?

We are issued drip shares, new issue shares with drip throughout the year which we started in July of last year.

How much is that on an annual basis?

Oh, it's roughly 50 million or so it’s embedded in our plan.

$50 million?

Yeah.

thank you. Our next question -- will now come from the site of James Delacker with bill cap please go ahead sir.

Guess a follow up to David's question is do you have any preliminary estimate on what the '04 average shares are going to be?

No, we have no guidance on '04 at this point.

Okay, thank you.

Our next question will now come from the site of Doug Fisher once again with A.G. Edwards. Please go ahead.

Yes, do could you give us some indication, you know maybe addressing the dividend question in another longer-term way, what -- can you give us any kind of ballpark as to what the long term earnings power of Enogex might be? You know, obviously you're making progress, but the return on assets is, I assume, still low in '03. What kind of earnings power do you see as potential over the long term?

Now, you're correct. The return of assets is still not what we want it to be. You know, we continue to look at all the assets to see if they're performing along our expectations and at levels that, you know, give us our cost to capital. And we're going to deal with them if they do not.

You know, falling from 7 million to 17 million at this year, you know, we're projecting, you know, in our forecast, you know, declines on our system. Again, based on, you know, hire well connections in the past year. But we incorporate low natural gas prices. With these natural gays gas prices that we are seeing now we expect to see a lot higher. [inaudible] in our system. A lot of the answer goes to whether the volumes we are going to see on our system, and you know I think we're being conservative. I don't know if we're in a position right now to tell you from the 2003 number where -- what that number is sustainable. We know it's higher but I don't think we're in a position right now to tell you how much higher that is. But we -- management is focused on I think the same numbers you are, and you know, we're looking at strategies that get us next couple of years at levels that we think we need to support our cost to capital in that business.

Pete, is the upside more in higher volumes for transportation and storage, or is the upside on more on improving the results from more on improving the results from gathering and processing?

I think the more -- the upsides from the improving our performance and gathering and processing, we look around at the performance of the assets, it is the gathering and processing, the areas that are probably underperforming the most. You know, some of the actions we have taken, felt these assets are just to address this -- those issues, you know clearly again, we're projecting a low processing margin environment, moving forward. This is as we experienced in 2002.

You know, we're waiting to see if that based on the fundamentals is an environment that's going to be sustained for the next couple of years. We have strategically other ways of dealing with that, and you know we're looking at those things right now. But the lion's share of improvement needs to come from the G and P sector.

What kind of well connections do you have for '03 and what did you experience in '02?

Our well connect rose three above with above 180, and in '02, I believe it was 136, 137 total. I'll have to check that 2002 number. Again, we based our well connects on a $3.30 level for '03, as you know we're consistently higher than that. We ended towards the year on an annualized level above 200 wells. We are on our numbers so far.

When we correlate gas price to well connects, I'll give you an example. The last time, 2001, we saw gas prices above $4, our well connects in 2001 were about 230 wells. So -- 279 wells. So '02 was 139 wells connected. So we forecast that increase, but you know, that's what we were experiencing at year end and based on gas price what we're seeing we're still on that number of 180 wells for '03.

Okay. Did you say '02 was 139?

139, that's correct.

Okay. And what kind of processing margins are you assuming for '03?

Well, our total margin, you know, begin, 10% from that sector of 253.

Right.

And you know, we -- you know, we have to look at -- we look at our -- a lot of our processing margin we impacted by our composition and whether we reject assaying. We have been move away from talking about one FRACT spread(ph) number because it really is not representative changes in profitability when you talk about of changes in profitability if you look at changes in FRACT (ph) spread rate.

But when you look at the margins that we received in '02, our forecast basically incorporates the same type of margins in terms of the FRACT spread in '02. Maybe a slight increase but nothing material But really we're projecting sort of the same scenario we've had had in '02 moving forward. Again, we think that that's conservative.

You know, we've seen a large increase in gas prices here, as you're well aware. We've also, in crude oil, we've also seen our liquids prices go up well over what we had in the budget. That differential that we track and that we continue to try to manage.

Is the environment right now better or worse than it was for the, on average in '02?

Oh, I'd say right now it's probably -- well, from what we're seeing in January, and what we expect to realize in January, it's probably a little better, given the pickup we've had in liquids prices.

Okay, thanks.

But not material.

Thank you, Pete.

Yes.

Our next question will come from the site of Devon Gohagen once again with Luminous Management.

Sorry for the follow-up questions. I'm trying to get a handle on the long term Enogex situation. I was under the assumption that you guys had switched a lot of your key pole to pot [inaudible] previous contracts. My understanding of that is while it reduces the absolute dollar profitability potential.

And talking to some of your competitors people have mentioned that Oklahoma because of the [inaudible] going to other basins, because you have to go farther and farther out to connect to wells that the long term profitability is going to decline. And then when you look at your free cash flow status, you're not free cash flow this year, next year will be difficult, I'm trying to understand when, you know, just how Enogex fits into that situation and also how your parent ratio is going to get below 90%. Because the delusion next year is going to still be there.

Let me try to sort out, you had a bunch of stuff in there. I'll let Jim talk about cash flow, because we are cash flow positive and have been for several years and we have internal fash flow generation well in excess of our capital expenditures in that business.

Just to go back to talk about the contractual or gathering processing contracts you talked about the key pole exposures, to make some corrections in your statements there. We have a FERC proceeding during the year, which addressed -- conditions under which we're gathering and processing gas in the system. One of those and we reached settlement with the major interveners in that case and we've gotten comments back from the FERC and we expect them to issue an order this quarter. Part of that settlement included a treating fee. And that treating fee is applicable to our key pole contracts.

The treating fee would enable us to recover or charge a treating fee in the instance where we have a negative FRACT spread. That is where gas -- price of gas exceeds the gas that the shrink that we have in removing liquids from the gas stream, that that cost gas skied the liquids that we sell in the market. And so should that spread or margin be turned negative we would then charge a treating fee which would keep us whole, keep us whole, in that environment.

That effectively, that provision effectively takes our key pole unprotected key pole volumes down from around 85% to around 21%. That we have 21% of our volumes going forward are key pole, without any treating fee. But those are very lean gas streams. And much smaller amount of volume. And actually we're not budgeting really any margin from those gas streams.

But does it -- I'm sorry to interrupt --

It does not limit our upside, it limits our down side to key pole.

) DEVON GOHAGEN ) But treating recovery your fuel costs or fixed costs or prevent from you losing money on just the processing part of it?

Right. DEVON GOHAGEN Some of your competitors say the treating fee doesn't get you there, not you but just doesn't get the operations to break even on a net income basis.

That's correct. The treating fee will not cover your operating costs. They will cover your shrinkage cost which is the natural gas that you're losing out of your gas stream. In our case you know, we have fixed fee and POL dollars that we have to cover our operating cost. Now, you know whether it gets to the -- you know, gets up there, a lot of it, you know, depends on, again, the margins in the gross processing segment. That's a situation we're continued to monitor. And you know, we -- we're going to monitor that and see how the treating fee works for us. If it does not work for us, we will look to do something else.

DEVON GOHAGEN Okay. Can you address, then, just sort of the long-term situation, and the Oklahoma region request gas processing? I mean --

Right. The what you -- what we've seen, you know, recently is the declines in the -- what we've been tracking, the declines in production in the area, which we've seen on our system, as you know declines last year and we're projecting probably 8 or 9% declines this year. Again, that's based on the, you know, the gas prices that we've seen dramatically decrease in '01, now it's bounced back up. A lot of that will depend on gas prices going forward.

We believe that they're going to be sustainable in a higher range going forward which will be possible to end cap our well connect. You know, we're not going to take that assumption that in fact the gas prices and the well volumes will be there. Well connect volumes will be there to eliminate any future reduction. You know, this is -- we're looking at all our costs, again, to try to reduce our costs further, and I would say I would characterize the market as being one, there's a market consolidating market, and given the amount of infrastructure in place and the issue with the volumes, I suspect that there would be consolidation in the region and there's still some fragmentation out there and possibilities to reduce cost through consolidation.

DEVON GOHAGEN Does that mean you'll consider buying another fuel processing business? I guess what this all fits into to sort of summarize, I realize it's getting late, is the dividend payout ratio and you know it's an attractive yield here but I think a lot of people are quite worried about the long term sustainability of that especially given where Enogex is, granted it's been improved a tremendous amount and it’s to your credit, congratulations. But I think that's what people are really concerned about.

Yeah, I mean, the dividend payout, I mean I think that Steve mentioned, our strategy is to grow our utility, and our asset mix, toward around a 70-30 basis. I think the power plant and the fact that we're short power at this point in time, and the great position to be in from the utility standpoint, bringing back to our share holders and getting assets, you know hopefully blow the cost to build.

You know, and Enogex I think we have a good handle on the performance of our assets. We're spending some money on technology this year to improve our basic data collection. And we're going to manage, you know, we have money invested in Enogex and the next couple of years we're going to manage to recoup that investment in the earning – earnings are good return or recoup that investment. That's what we're committed to. And I think given all of that, given the accomplishment Of both of those things the earnings level should continue to support more than cover our dividend.

DEVON GOHAGEN I wanted to clarify the point that was brought up about the cash flow situation at Enogex. If you look at Enogex stand-alone basis, the cash from operations not including changes in working capital are in a range of 70 to $75 million.

I was referring just to the consolidated. I'm aware --

I think on a consolidated basis, there was a net deficit in cash this year related mainly to the fact that we had a storm that caused us $92 million. I think if you subtract that out, then you would see that on a consolidated basis we were cash positive in '02.

Going forward you're not. That means a CFO 300 of CAPEX 196 dividends are going to be above 104. That already gets me neglect negative.

That, two things, one is you do have the regulatory lag of new rates in '04 and you also have higher CAPEX this year than we would normally maintain as a utility going forward as well.

Okay, thanks for your comments guys, I appreciate it and I hope that everything indeed does go well for you.

Thank you.

Thank you. Our next question will come from the site of Paul Patterson as a follow up from Glen Rock Associates.

Your drip is 50 million, five-zero?

Yes.

And you're issuing about 90million sometime this year?

That would be an assumption of 160 million plant 56% cash structure, yes.

Thank you Wilson, very much.

Our last question comes from the site of Zack Schreiber with Duquesne Capital (ph) Thank you.

Hi Jim, I got in late so if this question was already asked I apologize. What was the realized FRACT spread for 2002. I thought you said the FRACT spread assumption – [inaudible] better than your '03 guide. I was wondering if you could clarify that firstly.

Secondly, if you could reiterate the sensitivity changes in the FRACT spread, if it's changed given that some of the changes in your key pole percentage on this deal on the treating fees.

Our 2003 budget's based on a processing margin of around 10% of our total gross margin. Probably roughly little less than half of that would come from volumes associated with the key pole contracts. There is no one FRACT spread. You have to look at each component.

Sure.

Each component has a separate FRACT spread. And again, from where we're looking forward to in '03 versus '02, we're not building in any really improvement from what we realized in '02 in terms of our FRACT spread. I think you think in '02, for that number that I think that was calculated, is the $1 1.13, around there I believe.

$1.13 per MMBTU?

That's right. Thank you very much.

Thank you. At this time it appears that we have no further questions. I will turn the program back to management for any concluding comments.

We'd like to thank you for taking the time to be with us this morning and we thank you for your interest in the company.

Thank you for an outstanding presentation. This does conclude today's teleconference. You may disconnect your line, thank you for calling, and have a wonderful day.

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