OGE Energy Corp (OGE) 2005 Q3 法說會逐字稿

At this time some I would like to welcome everyone to the third-quarter earnings results conference call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be question-and-answer session. (OPERATOR INSTRUCTIONS) Thank you. Mr. Hatfield, you may begin, sir.

Thank you. Good morning, everyone, and welcome to OGE Energy Corp.'s third-quarter 2005 conference call. I am Jim Hatfield, Senior Vice President and Chief Financial Officer. I have me today Steve Moore, Chairman, President and CEO; Pete Delaney, Executive Vice President and Chief Operating Officer; Howard Motley, Director of Regulatory Affairs and Strategy for OG&E; and Danny Harris, Senior Vice President, and President and Chief Operating Officer of Enogex. And we have several other members of the management team available to address questions.

In terms of the call today, we will hear first comments from our Chairman; then I will cover third-quarter results; we will talk about the 2005 outlook. Howard is going to give us a regulatory update, and then we will be available for Q&A session. Before I begin, want to remind everybody that we've prepared slides to accompany our webcast, so it will be easier to follow the numbers, when we get to that point.

I just want to point everybody to the Safe Harbor statement that is on page 2. This is an SEC requirement for financial statements and states that we cannot guarantee forward-looking financial results, but this is our best estimate to date. And now I would like to turn the presentation over to Steve Moore. Steve?

Thanks, Jim. Welcome to our call, and I do want to thank you for your interest in OGE Energy Corp. Today we will focus on the quarterly and year-to-date financial results we announced this morning. We will also talk about our electrical rate case here in Oklahoma and bring you up-to-date on some of the other issues we're working on.

In the third quarter, we reported solid results, with earnings per share up about 14% compared to last year. As we indicated in our press release, times are good in the natural gas pipeline business; and once again, Enogex has had a good quarter. But we also will take this opportunity to remind you that for a midstream player like Enogex in the gas industry, high prices are no guarantee of higher profits. We have worked very hard to capture the value and that work has paid off.

In our regulated utility business, as you know, the third quarter is the warmest season of our operating year and typically our strongest. For the third quarter, we did have favorable weather, 24% warmer than last summer. But OG&E's earnings increased only 6%.

In past years, even as we sustained many rate reductions, hot summers produced strong earnings. Now such a summer is needed simply to keep up with the rising cost of operating our business and accommodating growth in the communities we serve. We have reached at a point where normal weather would result in an earnings decline. We see this as clear evidence of the need for rate relief, which we will discuss in more detail in just a few moments.

So now, with three quarters of the year in the books we are affirming our previous guidance of $1.65 to $1.75 per share, which excludes gains from the sale of some Enogex assets this year. In the third quarter at the pipeline, the strongest results came from the gathering and processing business, that part of the business that is closest to the producing fields where the new wells are being drilled.

The sale of our interest in the Noark pipeline system, and that is primarily a FERC-regulated interstate line in Arkansas, will be reflected in our fourth quarter. We continue to seek opportunities to invest the proceeds from that sale in midstream projects offering a higher rate of return.

In our electric utility, Oklahoma Gas and Electric Company, the third-quarter contribution to earnings was $1.09 a share in the third quarter, only a slight improvement from $1.03 in the cool summer of 2004. This was the first full quarter that we could no longer treat the costs associated with the McClain power plant as a regulatory asset. Our ability to capitalize those expenses expired in July.

We have been working to remedy that situation with our Oklahoma rate case, and late yesterday we received news of the referee's finding in that case. We're still studying the report, but we estimate the referee's recommendation to be an increase of approximately $42 million. While the referee's recommendation appears to be above the proposals from some of the other parties in the case, it is not enough to continue investment in our electric system at current levels.

We have a very strong case to support the need for investments in our aging assets to maintain reliability. We are hopeful the Commission will support a higher recovery to fund additional investments that are needed. Based on the Oklahoma Commission's procedural schedule, expect an order from the full three-member Commission within the next two weeks.

We should note that our customers are already enjoying significant savings and improved reliability from the substantial investments we have made. We had planned to invest even more in the capacity and reliability of our system. But if we can't recover the investments we have already made, those plans will have to be further reduced. Still, we remain hopeful that the Commissioners will see the reasonableness of our investments and increase the referee's recommendation.

As always, we thank you for your support of our thoughtful, conservative strategy to deliver value for our customers and our shareowners alike. We appreciate your interest in OGE Energy; and now I will turn the program back over to Jim Hatfield. Jim?

Thank you, Steve. For the third quarter, we reported net income of 111.1 million or $1.22 per share, as compared to net income of 94.6 million or $1.07 per diluted share in the third quarter of 2004. This is a 14% increase in earnings per share. EPS was affected by higher shares outstanding, which increased to 2.8% to 90.8 million, compared to 88.3 million.

The contribution by business unit on a comparative basis is as follows. OG&E, $1.09 versus $1.03; Enogex, $0.17 versus $0.07; and the Holding Company, a $0.04 loss versus a $0.03 loss, $1.22 versus $1.07.

Looking first at OG&E, net income was 99.4 million or $1.09 per diluted share, as compared to 91.3 or $1.03 per diluted share in the third quarter of 2004. Gross margin on revenues was up 29.6 million or $0.22 per diluted share to 284.6 million, as compared to 255 million in the third-quarter 2004, which is an increase of 11.6%. The major factors which impacted higher gross margins were warmer weather, which increased gross margin by 24.8 million; customer growth, which increased gross margin by 10.7 million; and a seasonal undercollection of the cogeneration rider of 5.9 nine million. Cooling-degree days were 7% above normal and 24% above last year's quarter.

In addition to revenue, some of the other major categories affecting earnings at the utility were operation and maintenance, and depreciation expenses. O&M expenses increased 7.3 million or 11.1%, primarily due to higher labor-related costs, materials and supplies, and outside services. Most of these costs are associated with the utility's customer savings and reliability plan. Depreciation expense increased 4.5 million or 14.9% due to investments made in the electric system for reliability and the McClain power plant. Also note for the last six months of the year, the costs associated with the McClain plant, deferred as a regulatory asset through July 8, will hit the income statement. We anticipate those costs to be approximately 14.7 million for the last six months of the year.

Other income decreased 3.8 million, primarily due to a gain from the sale of the Company's interest in its natural gas producing properties in 2004. Net interest expense increased 6.1 million, due primarily to an IRS reserve, higher interest rates, and the McClain plant expense no longer being deferred.

At Enogex, we reported net income of 15 million or $0.17 per diluted share, as compared to 6.3 million or $0.07 per diluted share in the third-quarter 2004. During the third quarter, gross margins increased to 64 million, up 2.1 million or 3.4%, as compared to 61.9 million in the third quarter of 2004. The increase in gross margin is due to higher margins in the gathering and processing business. This increase was partially offset by lower margins in the marketing and transportation and storage businesses.

During the third quarter, transportation storage margins were down 2.3 million from the third quarter of 2004. The main factors impacting gross margins were reduced recoveries of fuel and lower demand fees, partially offset by higher cross-haul prices and volumes, and 700,000 in commodity revenues due to a favorable contract renegotiations.

Gathering and processing margins increased 4.8 million to 43.5 million, up 12.4% over last year's quarter. Gathering gross margins were 5 million higher as compared to the third quarter of 2004. Key drivers were increased retained fuel volumes and higher contractual fuel gains.

In processing, gross margins were essentially flat compared to last year, due primarily to a 14% reduction in keep-whole volumes due to ethane being rejected in much of the quarter. This was partially offset by higher condensate prices. In the quarter, average sales prices per NGL gallon increased 34%, as the current year's quarter average price was $0.972 compared to $0.727 in last year's quarter. The average commodity spread for the third quarter was $3.27 per MMBtu compared to 2.84 last year.

Marketing and gross margins were down slightly in the quarter compared to 2004. O&M expenses declined 900,000 or 3.7% due to the absence of an uncollectible reserve recorded in 2004. Likewise there was no asset impairment charge this year; last year we recorded a charge of 8.6 million or $0.06 per diluted share. Discontinued operations had a positive variance of 3.2 million due to the sale of our Enerven joint venture interest in the third quarter.

During the three months ended September 30, 2005, Enogex had an increase in net income of approximately 4 million relating to income from continued operations. On a comparative basis, during the three months ended September 2004, Enogex had a decrease in net income of approximately 1.4 million relating to various items that the Companies do not consider to be reflective of the ongoing profitability of Enogex's business. You see those various items on the screen.

As Steve mentioned, we continue to be comfortable with maintaining our $1.65 to $1.75 per share earnings guidance for 2005. This range implies net income of between 149 million and 158 million, and assumes approximately 91 million average diluted shares outstanding. This earnings guidance does exclude the gain on the sale of assets of approximately $52 million or $0.57 per share.

Earnings guidance at Enogex remains at 49 to 56 million, or $0.54 to $0.62 per share. The Company has increased OGE's earnings guidance due to warm summer weather. The range is now 112 to 116 million or $1.23 to $1.27 per share.

Earnings guidance at the Holding Company has been slightly lowered to an expected loss between 8 and 10 million or $0.09 to $0.11 per share due to higher-than-expected interest costs. So that is a summary of the quarter. I would now like to turn the program over to Howard Motley for a regulatory update. Howard?

Thank you, Jim. We have been in the process for the last 10 months in the rate case in the Oklahoma submission. We filed our case on May 20 and gone through the audit process. We concluded the hearing on October 24. The Commission had a very short, very fast timeline together with the referee's report. The referee did issue the report last night after hours, around 6 or 6:30. The Commission legally posted yesterday a deliberation for next Monday morning.

So the Commission will start looking at the referee's report and trying to make a decision in this case. Under the Oklahoma statutes, there is 180-day timetable for the Commission to issue an order target. We believe the Commission will issue an order in the next couple of weeks.

Next slide shows the summary of the positions. This is the positions of the parties in the case that was presented to the referee. As you can see, there was a range. The Company asked for 89.1 million rate increase; the staff recommended a 13.1 million rate increase; the Attorney General recommended a $24 million rate reduction; and the large industrial customer group recommended a $31 million rate reduction.

Kind of the differences, the return on equity is a major issue. The industrial customers recommended a 9.0; the Attorney General a 7.9 return on equity; and the staff a 9.75. So as you can see there was a range of 29 million to almost 55 million impact on our 89 million revenue requirement just for return on equity.

Also in the capital structure, the Attorney General and the OIEC recommended the energy report (ph) capital structure instead of the utility capital structure, which made a 12 to $13 million difference to the Company's recommendation. Then all three parties disallowed certain expenses and rate-based items that true up to the bottom number of 89 million. So we went into the hearing with three different proposals from the parties, and the Company's 89.1 million.

The next slide is a summary of the referee report. I just talked about the different return on equity. The referee's report recommends a 10.75 return on equity. Just to put it in perspective, every 100 basis points is worth about 16 to 17 million to our revenue requirement on our rate increase. The capital structure was recommended at 57% common equity and 43%; that was the capital structure recommended by the staff witness in the case.

As mentioned earlier, we have been evaluating. We evaluated the report last night and right now we -- it's about $42 million, the rate increase that is generated by that recommendation. Although, the 10.75% return on equity and the capital structure -- we are pleased with that or it is more positive when you look at all the recommendations, there were still some things lacking in the recommendation that concerns us. Two or three things like prepaid pensions were disallowed; a few expenses that were disallowed, we believe that we were entitled to.

I think, just to put it in perspective, this $42 million rate increase, that doesn't quite cover even the regulatory asset and the cost of McClain. In our proposed order, we laid out to the Commission that it would take $47.4 million of rate increase just to cover the cost of McClain in the regulatory asset.

Today, the consumers are benefiting about $26 million a year of fuel savings from McClain. So if you really look at it from that perspective, 47 million minus the $26 million fuel savings is really a net increase to the consumers of 20 million.

So we are in hopes that the Commission, next week when they begin deliberation of the referee's report, they will look at some of the expenses, O&M expenses, and look at the rate-based items that have been disallowed, and consider our construction program for the future, and be able to modify it and bring it up to a more appropriate level that will let us continue the business under the plan we have going today. With that, Jim, I will give it back to you for summary.

Thank you, Howard. Just in closing, a few points. Year to date, the utility has benefited from weather. However, if you think about the impact of weather, 24% warmer summer than last year, only 6% increase in net income; and if you normalize that for weather, we were down approximately 5%. This in our opinion clearly demonstrates the need for rate relief at the utility.

On the Enogex side, continued to benefit from ongoing operational improvements and strong commodity prices. As was mentioned earlier, we did sell the Noark asset, so we continue to evaluate assets. We have had asset sales, and we are beginning a strategic repositioning of the Enogex asset base, looking for assets in the mid-continent and Rocky Mountains.

We will provide 2006 guidance after a complete evaluation of the OCC order. Once we get the order we will make a determination of the appropriate spending plans of both O&M and capital; and at that time we will be in a position to provide 2006 guidance. That concludes our prepared remarks, and we will now open the floor for questions.

(OPERATOR INSTRUCTIONS) Doug Fischer.

I just wanted to get some comments on the current processing environment, given the spike in natural gas prices, even though it has moderated off of its highest levels; and how that is affecting the spread for you all looking forward.

Then, secondly, can you elaborate at all? I know you just got the referee's recommendation, but can you elaborate? With a 10.75 ROE, one would have expected the revenue amount to be materially better than the 42 million. So I wondered if you could at least point us in the direction of some material disallowances of expenses or rate base that helps explain the referee's (multiple speakers).

Why don't we do this, Doug? We will let Howard answer the first question about some of the things within the referee's recommendation. Then we will address the processing environment. Howard, do you want to talk about some of the items?

Yes, I think that as far as rate base, several items stick out. She, the referee, reduced rate base 67 million for prepaid pension and allowed a 6% interest on that. That was an issue in the ONG rate case that was just heard by the Commission. They call it alternative financing. So they're getting a rate-based rate of return in taxes; they just allow you some type of an interest.

The Commission did not adopt that in the ONG case and actually set up a workshop in the future to look at alternative financing of areas like materials and supplies, fuel inventories, and prepayments like that. So we're in hopes that the Commission will use that same judgment in deciding our case and sent that issue to the same workshop that will be an industry workshop. So that would make the rate base, OG&E's rate base go up 67 million. That was the major adjustment to rate base.

Another one was the regulatory asset. We asked for 24 million in rate base. They did a four-year projection of that, and gave us a four-year average 15 million in rate base. We will get to recover 100% of the 24 million over four years, but only get a return on 15 million. So there is about a 9 or $10 million reduction to rate base for that. Then there's other miscellaneous adjustments to rate base. But that is the big ones.

As far as expenses, there was -- I think incentive compensation was probably a 6 or $7 million issue. They disallowed a couple million dollars of pension cost. Then a lot of the adjustments were just nickel and dime adjustments that were proposed that added up to quite a few dollars. One is bad debts; we have a very low bad debt cost. We work very hard to get that down. As a matter-of-fact, in the ONG rate case, the parties -- the OIEC proposed that we were kind of the poster child, and ONG should have lower bad debt. Then they turn around in this rate case and reduce our bad debts even lower than what we've got them down to. We have reduced them about 60 to 70% over the last three years, and that was a $700,000 expense.

So I believe that there's quite a few expense adjustments and rate base adjustments that the Commission will really closely look at next week when they start deliberating and hopefully give us some fair consideration.

Do you get to rebut in any fashion the referee's report?

I think under the process we're under now, I don't think that is the way they plan on deliberating it. Now, we will get to attend the deliberations. They are open. It is an open meeting, and the Commission can call on parties in the audience to explain issues or ask for opinions. But usually in that forum, if you are called on you can speak; if you're not called on you don't get to speak.

Okay, so let me just summarize a little bit. There were 67 million of rate base or revenue related to the prepaid pension?

No, $67 million of rate base.

What is the revenue implication of that?

Probably about 8 or 9 million. 8 million of rate-based implication. Then they allowed us about $3 million of interest expense, this alternative financing. So the differential would be probably around $5 million to our revenue requirement, 4.5 to 5 million. So it is a major issue.

4.5 to 5 was the net impact of that. I don't follow ONG, so are you saying they allowed (multiple speakers) in rate base for ONG, but they sent it off to be further studied?

It wasn't specifically prepaid pensions in ONG. What some of the staff and some of the other parties have done, mainly the OIEC started the -- it is a new regulatory concept that we researched across the nation and have not found anybody, any Commission dong this right now. It is that they go in and they take out prepayments, or cash working capital, or gas in storage and say, instead of getting a rate of return on it we are going to give you a commercial paper rate on it. And you should be financing a lot of your rate base through commercial paper or some other type of alternative financing.

In the ONG case there was quite a few million dollars in different items that were taken out of rate base, or recommended to. When the Commission finally issued its order, said no, we're not going to change that at this time; but we're going to send a -- have a workshop to talk about, is there any benefit to alternative financing of rate-based items? So we are in hope that the Commission will look at this same item and handle that in our case the same way.

What is the precedent? Have they allowed prepaid pension before in rate base?

Yes, they have.

I think it has never been this large of a number; but they have in the past. Historically in all jurisdictions -- specifically I am familiar with Oklahoma jurisdictions for the last 32 years -- prepayments have always been included in rate base, along with materials and supply and working capital.

The deferral? Again, I am sorry to go over this. But the deferral was related to the carrying costs for McClain or what? I missed that.

You're talking about the what? The rate-based item for McClain?

Right.

The rate-based item for McClain --.

Is that the 24 million?

Yes. It is the regulatory asset for McClain. They allow us to recover 100% of it by giving us over four years. They give us about $6 million a year in our expenses to recover the 24 million. While we're recovering it over the four-year period, we should get a return on the 24 million. You know? If you use (multiple speakers).

On the unrecovered balance?

Right. What they have done is they have gone out, kind of like an amortization of a home loan. They have looked out over four years and said, over the next four years your average balance is going to be 15 million. So we're only going to allow you to earn 15 million on that over the next -- on a $15 million number. So they reduced rate base for the difference between 24 and 15. So we get full recovery of the regulatory asset. We just get to earn a rate of return on a lower amount.

And what is the revenue impact of that?

That would be probably -- maybe 1.5, 1.6 million.

Okay, and then you outlined some of the major items on the expense side.

I will point out, that is one item the staff originally recommended not to even put the 15 million in rate base, but to take it out and have this alternative financing and give a 6% on it, and the referee rejected that. So very similar to the prepaid pension. So she rejected what they recommended in the regulatory asset, but then adopted the prepaid pension.

So there is a little disconnect there, and I think based on the ONG case, and even her decision on the regulatory asset, I think when the Commission starts looking at the prepaid pension, it's such a major issue and a policy, I think they will give a strong consideration of looking at it.

Okay, thank you. Sorry to belabor those.

No problem, Doug. On your first question about the processing environment, we would look at slightly compressed spreads in the fourth quarter. In the third quarter, the average spread was $3.27. As of last Friday, that spread was $2.32, to give you an idea of sort of the compression in spreads based on the current prices.

Okay, thank you.

Erica Piserchia.

Quick question. I guess just kind of following up on Doug's question, I guess with the ALJ's -- I'm sorry, the referee's recommendation, we talked about some of the rate base impacts; what would be the total rate base that the recommendation is premised on?

The total rate base for the Oklahoma jurisdiction is about 1.7 billion.

That is under the ALJ's recommendation?

That is correct.

Okay. Then I guess just turning to Enogex, and I know you guys had given a spread to the commodity -- a sensitivity, rather -- to the commodity spread a while back of a $0.10 change being equivalent to a 1.5 or $1.25 million change in net income. Is there a way that we could get -- is there any update to that? Or is that still kind of the case as we're looking forward to 2006, and sort of how that would play in?

That is still pretty much the sensitivity.

Okay, and then I guess --.

Keeping in mind that your mix changes whether you reject ethane or not and that sort of thing, but that is sort of a rule of thumb, if you will.

Okay, and then on the guidance for 2006, I think you said after you evaluate the final order with the rate case that you would kind of update that guidance. Is that going to be like a December thing, or should we be thinking more like the fourth-quarter call in early 2006?

I would anticipate that it would be more of a December sort of timing than waiting on the first-quarter call.

Okay, thank you.

Jeff Cobiello (ph).

Actually, Erica asked my rate base question, but I wanted to just follow up on the frac spread a bit. I guess you said it was a little above $3 at the end of the third quarter; is that right?

That was the average for the quarter.

When you give your range of what is embedded in your guidance for '05, that is apples-to-apples, right? That $3.27 compared to the $2.00 and something?

Yes.

Even with -- I guess when I look at the frac spreads, this run-up in gas prices, it seems like it was compressing it a bit. Still right now, though, you're saying it is about $2.32?

That was as of last Friday.

Do either of those numbers assume ethane rejection or are they including ethane?

Well, the third quarter we talked about rejecting ethane; that is why volumes were down 14%. The price last Friday was without ethane rejection.

Got it. Okay, I appreciate. Thank you very much.

David Frank.

I was actually going to ask just basically the same questions on the frac spread. But while I have you here, can you tell us, your realized frac spread, how much of that was due to hedging in the quarter versus the spot market? Or was there not any hedging?

No, we have hedged a percentage of both keep-whole and POL volumes in the third quarter. I don't have the exact sort of hedge on top of my head at the moment, David.

Was the hedge above the market?

The hedge would have been -- the way we approach hedging is we look at what our budget and forecast was, and try to lock in any incremental value. That is about all the information I have on our hedge. We will get back to you on that item. But typically when we hedge, we are just sort of locking in physical value, and it's a small part of the mix on the processing side.

Okay, so just to summarize one more time, the average realized. I guess, if you were just out in the market and you were a taker of the frac spread or you were along the frac spread, for the quarter was -- excluding hedging, would have been -- do you have what that was?

It was 327 is what we realized, again it was a very small amount of that. So I think for your purposes, you could think of it sort of de minimus to the spread in the quarter.

Okay, and right now you're seeing something like 232 for the year?

232 as of last Friday.

That is the most recent spot?

Yes, and we still expect for the year will be between 230 and 260 on average over the course of the year.

Okay, and that is baked into the guidance for this year?

Yes.

Okay, thanks a lot guys.

Reza Hatafi (ph).

You mentioned earlier that your Oklahoma jurisdictional rate base, that ALJ recommendation, was 1.7 billion. Does that compare to your filing of 1.87 billion? Or am I just -- they're not apples-to-apples?

No. That is apples-to-apples.

So your request was 1.87 and the ALJ's is 1.7.

That is correct.

And could you explain this press release from today? The deal with the Continental Connector pipeline project? Just any kind of -- what is this? Are you spending money? It is kind of unclear in the press release.

No. We're not spending any money. That announcement was about a development agreement that we have with El Paso. Basically, Enogex is working with El Paso at this time to put together the Continental Connector pipeline project that really connects part of the western part of El Paso's pipeline system that accesses gas in the Rockies with its eastern system that delivers gas into the Southeast, Midwest, and Northeast part of the United States.

Our role and Enogex in this effort is working with El Paso to secure enough commitments from gas producers in the Rockies and gas producers in the mid-continent really to support expansion on our system, and to support some new pipeline construction that would extend from a point on our system in Southeast Oklahoma down to a pipeline, El Paso's pipelines in Louisiana.

We're really just in the development phase. We still have a lot of work to do together in terms of structuring the project and securing enough firm commitments to provide Enogex and El Paso enough certainty to proceed to the next step. So this is very much consistent with our strategy at Enogex to strengthen our system by accessing new supply and accessing additional markets for the gas on our system or goes through our system.

Great. Going back, just one more thing on my previous question, the 1.7 billion ALJ recommendation for rate base. That is in line with the staff recommendation as well, correct? I think they recommended around 1.7, right?

I think that is pretty close.

Okay, and just finally in your slides, on your summary on slide 16 you talk about evaluation of assets has led to asset sales as we begin strategic repositioning of Enogex's asset base. Could you expand on that as far as further asset sales? Would it be more on the pipeline side or the gathering and processing side? Or what does that really mean?

This is Dan Harris. That is something that we have put in place in the past year, just really doing a thorough review of our asset mix, trying to match it with strategy. One of the decisions that we had was, for instance, the sale of our Noark partnership. It was an interstate pipeline, and we determined that was not a part of the core strategy for going forward.

The looking at also just the assets that we have, gathering assets in the mid-continent basin, our intent there is just to strengthen the existing holdings that we have in the mid-continent and concentrate on those areas that are more of a growing area for us. Then the third area is just looking outside at areas of expansion. Our intent is to diversify geographically, so that we reduce our mid-continent risk.

Great, thank you very much.

At this time there are no further questions. Would you like to have any closing remarks, Mr. Hatfield?

This is Steve Moore. I want to thank each and every one of you for your interest in OGE Energy Company, and have a great day. Thank you.

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