OGE Energy Corp (OGE) 2007 Q3 法說會逐字稿

Good morning. My name is Regina and I will be your conference operator today. At this time, I would like to welcome everyone to the Earnings Release Conference Call. (Operator Instructions.) I would now like to turn the call over to Mr. Jim Hatfield. Sir, you may begin your conference.

Thank you and good morning, and welcome to OGE Energy Corp.'s third quarter 2007 conference call. I am Jim Hatfield, Senior Vice President and Chief Financial Officer, and I have with me today Pete Delaney, Chairman, President, and CEO, Dan Harris, Senior Vice President and Chief Operating Officer, and several other members of the Management Team to address questions.

On the call today, we'll cover the following topics. First, we will hear opening comments from Pete Delaney, then I will cover third quarter results, the utility capital expenditure program, discuss 2007 outlook, and we'll close with a Q&A session. Before I begin, I want to remind everyone that we have prepared slides to accompany our webcast so it will be easier to follow the numbers when we get to that point.

I'd also like to direct your attention to the Safe Harbor statement regarding forward-looking statements. This is an SEC requirement for financial statements that simply states that we cannot guarantee forward looking results, but this is our best estimate to date. Also, please keep in mind that we are in the registration process on the Enogex IPO, so other than covering third quarter results, we will be limited on what we can say about Enogex.

And with that, I'd like to turn the call over to Pete Delaney. Pete?

Thanks, Jim. As you know, this is our first earnings call since Steve's unexpected death in late September. Steve was a great leader. He guided the company through some challenging times in the industry. He was our CEO for 11 years, and unfortunately eight years of that he fought cancer. But his courage and determination as he addressed the disease really inspired us here at the company and we sorely miss him.

We'd had a succession that was put in place well before Steve's passing. The plan has been executed, the Management Team is in place, and we continue to execute on the strategy. Part of that strategy, as you know, is the initial public offering of Enogex through the issuance of master limited partnership units and we continue on that course. But as we are in the registration period, we're very limited in what we can discuss about Enogex today.

We remain focused on the details of our business. We earned $1.37 per share in the third quarter, up from $1.31 last year. We believe that's a solid result, particularly given the fact that this summer and this year we're hitting records for rainfall in Oklahoma, about two times over 40 inches the normal amount we get and not--and we're not dealing with the heat records that we have in the past years that are obviously more favorable to earnings.

But Jim has all the details. He'll share with you in a minute. We're on track to firmly hit the 2007 earnings target of 2.30 to 2.50 per share this year.

The Red Rock project, our coal plant, was denied by the Oklahoma Corporation Commission this quarter by a 2-to-1 vote on issues that are very specific to this case and not based on the broader industry issues that we're all aware of. One of the things that--this is the first time the Oklahoma Corporation Commission was faced with a preapproval of this magnitude and since legislation--the Bill 1910 was passed supporting preapproval.

The Red Rock coal plant and the Red Rock Partnership that we had with PSO was selected in the competitive bidding process by PSO. They were working under a tight timeline to get their plant--their base load plant operational by 2011. Because of that timeline, their regulatory proceeding was not filed under the new preapproval law and their competitive process was not--was conducted before the competitive bid rules were in place. Both of those are in place at this time. And one of the issues mentioned by the commissioners with the "no" votes was that--was concern over the bid process and what the differences were, but the rules were ultimately passed.

Also, subsequent to the passage of the 1910 legislation, the regulations for the preapproval process and recovery was not--were not fully developed, and we believe that was problematic for one of the new commissioners coming into office in late May. That's obviously quite late in that process. The record shows it was a "no" vote for--it was not a "no" vote for coal. Two commissioners who denied the application continue to say that coal needs to be considered as part of our future alternatives for meeting base load.

However, there was a lot of publicity generated at a local--by a local natural gas company that raised the political stakes in this matter as well. There was also concern mentioned regarding the extent of the need for base load capacity on OG&E's behalf, [finding our] need to be only 300 megawatts. Our net capability out of that plant was about 345 megawatts. So despite the fact that the OCC staff supported the plant and the ALJ recommended approval, preapproval was not granted by the Commission. We do not believe, however, that this signals a turn for the worst in terms of Oklahoma regulation, but really reflects the change in the composition in the Commission with a new commissioner that reflects a desire for more prescriptive regulations, and we support that.

We continue to believe that Red Rock is the best option for our customers in terms of providing the lowest cost alternative, and that included [carbon] taxes. But that did not seem to be enough to carry the day. At this point, we've cancelled our partnership, our fixed price CPC contract has been cancelled, all of the resources we had gathered have been released, and it seems that we will be headed to the next best option at this point, which is the natural gas fire facility.

We are working with the Oklahoma Corporation Commission on developing new rules for competitive bidding, demand side management, and recovery under the preapproval process.

We also recently announced our intent to increase the amount of wind generation on our system to around 770 megawatts from the 170 megawatts today and do that within about five years. We also, of course, would hope to own a percentage of that new capacity. Today, we own 120 out of the 170 megawatts on our system.

We are also working with regional authorities to get approval to build out the transmission backbone that will be needed to bring the wind from the plains in western Oklahoma and in the Panhandle to our load centers in the state.

All of these growth initiatives that we've recently announced are in addition to the distribution and transmission reliability spends, the environmental upgrades at the existing coal plants, and our general growth projects. They remain substantial.

We are well positioned financially to turn that capital expenditure program into earnings with a low payout ratio and a strong balance sheet. Thank you for your interest in the company. Now, Jim will review our results for the quarter.

Thank you, Pete. Starting first with third quarter results, we reported net income of 126.8 million, or $1.37 per diluted share, as compared to net income of 121.4 million, or $1.31 per diluted share in 2006. Throughout the remainder of this presentation, earnings comparisons will be based on income from continuing operations and per share amounts on a diluted share basis. The contribution by business unit on a comparative basis is as follows - OG&E, the regulated utility, $1.18 versus $1.16; Enogex, $0.22 versus $0.14; the holding company, a loss of $0.03 versus a $0.02 contribution in 2006; continuing operations, $1.37 versus $1.32.

At OG&E, net income was 109 million, or $1.18 per share, as compared to net income of 107.4 million, or $1.16 per share in 2006. Some of the primary drivers are as follows. Gross margin on revenues decreased 8.8 million, or 2.8%, to 306.3 million from 315.1 million in last year's quarter. I will discuss the components of gross margin on the next slide. Operation and maintenance expenses increased 4.4 million, or 5.9%, primarily due to increases in outside services, materials and supplies, and fees and permits. Depreciation expense increased 2.8 million, or 8.6%, primarily due to the Centennial Wind Farm, which was put into service in January of this year.

Net other income and expense decreased 4.3 million in 2007, primarily due to the write-off in our Arkansas and FERC jurisdiction of costs incurred for the Red Rock project and lower [ASCDC] due to the Centennial Wind Farm project in 2006. These items were partially offset by higher income from our guaranteed flat bill program. Please note that we have deferred the costs associated with Red Rock in our Oklahoma jurisdiction and plan to file an application to seek recovery later this month. Those costs are approximately 15.4 million.

Interest expense decreased 5 million, primarily due to a one-time recognition of interest expense and related amortization in the 2006 quarter. The effective tax rate for the utility declined over 18%, from 39.3% in 2006 to 32.2% in 2007, primarily due to state and federal tax credits associated with the Centennial Wind Farm.

Now looking at gross margin, approximately 306 million during the three months ended September 30, as compared to approximately 315.1 million during the same period in 2006, a decrease of approximately 8.8 million, or 2.8%. Gross margin decreased primarily due to cooler weather in OG&E service territory resulting in an approximate 4.8% decrease in cooling degree days, as compared to the third quarter of 2006, decreasing gross margin by approximately $10.8 million.

OG&E's filing of amended tariffs with the OCC in January 2007 caused the gross margin to be approximately 5.9 million lower than the third quarter of 2006. Price variance due to sales and customer mix decreased the gross margin by approximately 4.4 million. However, these decreases were partially offset by higher rates, the result of the Centennial Wind Farm rider, security rider, and the Arkansas rate case, which increased gross margin by approximately [8.7] million, and customer growth and higher capacity related charges, which increased the gross margin by approximately 4.3 million.

Looking next at Enogex, income from continuing operations was 20.4 million, or $0.22 per share, as compared to income from continuing operations of 12.7 million, or $0.14 per share, in 2006. Some of the primary drivers are as follows. Gross margin increased 18.9 million, or 28.3%, from 66.8 million in 2006 to 85.7 million in 2007. I will discuss the components of gross margin on the next slide.

Operation and maintenance expense increased 3.9 million, or 14.8%, primarily due to higher employee costs associated with our growth initiatives and higher materials and supplies expense. Depreciation increased $700,000, or 6.6%, from 2006 primarily due to higher levels of depreciable plant. Net other income decreased $1 million, primarily due to lower interest income as Enogex continues to redeploy capital in the [step out] growth projects.

Looking at gross margin at Enogex, increased 18.9 million, or 28.3%, from 66.8 million in 2006 to 85.7 million in 2007. The largest increase in gross margin occurred in the transportation and storage business, which increased 12.9 million, or 52%. There were two primary drivers increasing gross margin - a lower cost or market adjustment related to natural gas inventories used to operate the pipeline in the third quarter of 2006, which reduced gross margin by approximately 6.4 million with no comparable item in 2007; the change in our net in-balance liability, as Enogex recognized a 3.2 million benefit in 2007 compared to an expense of 1.9 million in 2006, resulting in improved gross margins of 5.1 million.

In the gathering and processing business, gross margins increased 4.5 million, or 10.8%, primarily due to improved processing margins in all categories and higher gathered volumes. Gathered volumes year to date are up over 7% from 2006 levels and quarter over quarter volumes have increased more than 12%. [Well connects] year to date are 295 versus 276 in 2006. These increases in gross margin were partially offset by a reduction of fuel recoveries, which decreased the gross margin by 2.9 million. We realized a processing spread of $5.72 for the third quarter, and we have hedged approximately 72% of volumes subject to commodity price risks for the remainder of the year.

Marketing gross margins increased 1.5 million in 2007, primarily driven by higher margins from our Cheyenne Plains transportation position.

For the third quarter of 2007, Enogex did not have any significant nonrecurring items. You can see the 800,000 of nonrecurring items which occurred in the third quarter of 2006 primarily as a result of the loss of 600,000 for discontinued operations and a small impairment of assets.

Looking at the impact of timing items for the three months ended September 30, 2007, Enogex's consolidated net income of approximately 20.4 million included a loss of approximately 3 million at the marketing unit resulting from recording economic hedges associated with the Cheyenne Plains transportation contract at market value on September 30, 2007. The offsetting gains from physical utilization of the capacity are expected to be realized during the remainder of 2007.

Also for the three months ended September 30, 2007, the marketing company recorded a loss of approximately 900,000, resulting from recording storage inventory at the lower of cost or market value. The offsetting gains from the withdrawal of those volumes from inventory are expected to be realized during the first quarter of 2008. During the three months ended September 30, 2007, Enogex had no significant items [and it is] not considered to be reflective of its ongoing performance.

For 2007, we are reiterating the company's previously stated consolidated earnings guidance of 213 million to 231 million of net income from continuing operations, or $2.30 to $2.50 per diluted share. The key assumptions can be found in the company's third quarter 10-Q. I would also like to point out that we would normally issue 2008 guidance on this call. However, because we are in the SEC quiet period regarding the Enogex MLP, we will wait until after the IPO to issue guidance.

Before closing, I'd like to touch on the capital expenditures for the utility. The graph you see on the screen illustrates a 2.4 billion capital spending program the utility expects to undertake over the next six years. The largest expenditure area is in blue, which is our infrastructure build out in the transmission and distribution areas. Other expenditures include environmental compliance and transmission.

Please note this slide here does not include the expenditures associated with additional wins in transmission announced Tuesday, as the timing and amounts are uncertain at this point.

To put the capital spending projections into context, we project total company rate base to increase from approximately 2.5 billion in 2007 to approximately 3.9 billion in 2012. This represents a 56% increase in rate base, which offers a tremendous growth opportunity at the utility. However, we know that the impact on the customer is important, and therefore, we must continue to control costs so that rate increases to the customer are mitigated.

In summary, we continue to execute on our growth initiatives at both the utility and Enogex. Third quarter results were positive for both businesses as the utility increased earnings despite weather that was cooler than in 2006 and Enogex continues to product in a favorable commodity price environment.

Looking forward, we see growth opportunities at both the utility and Enogex. On October 25, we filed Amendment No. 2 in the registration process on our proposed MLP IPO, and we continue to move forward on that process. Guidance has been reaffirmed for 2007 at $2.30 to $2.50 per diluted share. And again, we will issue 2008 guidance with assumptions after the SEC quiet period ends.

This concludes our prepared remarks and we'll be glad to answer any questions you have at this time.

(Operator Instructions.) Your first question comes from the line of Doug Fischer with Wachovia.

Good morning, Jim and all.

Good morning, Doug, and I guess congratulations at being at Wachovia.

Thank you. Just a little bit of color about the wind and the related transportation and maybe the gas unit. What assumptions are you making in this CapEx about the timing and cost and ownership of a gas unit? And then, a little bit in terms of transmission that is related to the wind that's in the slide 11.

Well, if you look at the 2.4 billion in CapEx, we have not included any of the additional wind that we announced on Tuesday, the 600 megawatts. As Pete alluded to in his comments, certainly we would prefer to own that. However, we do have an RFP process that we need to go through in Oklahoma, which will dictate how that ultimately shakes out. So we have not put anything associated with wind at this point.

As it relates to how we satisfy our 300 megawatts of--at least 300 megawatts of capacity need, again, we'll have to go through an RFP process in Oklahoma. And certainly, a self-build option from OG&E will be one of the things that will be bid into that process. And again, we have to assume nothing associated with potential gas generation at this point, because there is a process to go through.

We would also say that the transmission associated with the wind in western Oklahoma, which again the timing and amounts are uncertain, have not been put into that CapEx plan as well. And what we're talking about associated with the 600--additional 600 megawatts would be a line from Oklahoma City to Woodward and then Woodward to Guymon, which obviously still has a process to go through at both--primarily at the SPP.

We do have in our plan about 129 million associated with transmission, which is really the western half of the X Plan--the SPP's X Plan, which is now in their 10-year base plan. We've made some assumptions beginning primarily in 2009, but again, how that shakes out will really be [a] timing based on developments of the pool.

And then, the need for the 300 to just clarify would be what year--standard megawatts of gas?

It was 2012--was our filing in Red Rock. So--base load.

And that remains-- 2012 remains the relevant year?

Yes, I think--.

--Will you be updating?

Yes. We have gone out for purchased power 2008 through 2010. That's a process that's currently underway and should be finalized this quarter. If you just think about a self-build option and a process to go through the RFP, you're really talking about a 2012, potentially a 2013 timeframe before you could construct that. But we will--as soon as we get the process in place, we'll be talking about it.

Okay. And I may have a follow up later.

Okay.

(Operator Instructions.) Your next question comes from the line of David Frank at Catapult Partners.

Yes, hi. Good morning, guys.

Good morning, David.

I just wanted to clarify when you--something you were mentioning to Doug there on the SPP X Plan. You said 129 million of transmission was kind of factored into your forecast here.

Yes. In the 2.4 billion.

For some reason, I thought the number could be substantially larger than that. Is there a potential for that to still grow, or how did you come up with that 129?

Well, the 129 is only the western piece of the X Plan. There is also the eastern side of that. And then, in addition to that is what we talked about--announced on Tuesday, which is connecting Oklahoma City to Woodward, Woodward to Guymon. So the 129 is just part of the proposed SPP X Plan.

Okay. That's--I think that--the last part there, the Woodward to Guyward was it?

Guymon.

Okay. That's not included?

No.

And roughly how much--do you have a guesstimate roughly of what that might be in the western half if you added all those things up?

No. The--we--Oklahoma City to Woodward, Woodward to Guymon, I don't have a good estimate on that now. The western half, as I said, was 129 million. And the eastern half, looking at the size, would be somewhat in that same range. But again, that's still subject to final determination.

Okay. And I guess your forecast wouldn't include any transmission associated with the 600 megawatts of additional wind, or would it?

Yes. No, the only thing that's in there, like I said, is that western half of the X Plan. There are--there is additional transmission needed for our 600 megawatts to bring it into the load area. And that's what we're working on timing wise and getting the correct scope.

Okay, great. And then, just one question on the utility. It looked like you had a write-off for costs outside Oklahoma. I didn't quite catch this. But I noticed on the slide your other net was down 4.3 million.

Yes.

What was--?

--The write-off in FERC in Arkansas was 2.2 million.

Okay.

And there were just some other miscellaneous charges in there.

And do you know--do you have an estimate of what impact weather--milder weather had versus normal in the quarter?

Well, from the prior year it was 10.8 million. So we were essentially just a little below normal in the third quarter. So I think that gives you a pretty good magnitude in the quarter.

Okay, great. Thanks a lot.

yes.

Your next question comes from the line of Scott Engstrom at Blenheim Capital Management.

Good morning, Jim.

Hey, Scott, how are you?

Good, thank you. A real quick question. The timing items, the hedging and the starts, were those--did that both--did both of those come out of the gross margin of transportation and storage?

Both of those items were at the marketing gross margin.

Okay.

Yes.

Thanks very much.

Yes.

(Operator Instructions.) You have a follow up question from the line of Doug Fischer with Wachovia.

Thanks. Can you--the transmission--the eastern half of transmission of X Plan, remind me, would--is it possible that you could be the sole builder of that? And how many miles is that?

Well, Doug, I don't have the miles with that. But certainly, our intention is to be the builder and owner of transmission in Oklahoma where we have the opportunity to do so.

Okay. I'll ask my colleague. He's pretty close to all of this transmission stuff.

Okay.

And then, the wind at--the wind--is it Oklahoma City to Woodward to Guymon? Is that what you're talking about? Is that the line?

Correct.

Any mileage there or any kinds of rules of thumb of what cost per mile that we might--even just a very broad range?

Well, Oklahoma City to Woodward is about 120 miles. And this is in a sparsely populated area, so it's--rule of thumb is people are using about $1 million per mile.

Okay. And what about the Woodward to Guymon?

Woodward to Guymon is not quite as long, approximately 90 miles. So--.

--And still sparsely populated, et cetera?

Yes, it's in the Panhandle.

Yes. And then, how would you describe--is this a line where you think you have a good opportunity to be the sole builder of these additional lines to the wind, or is there going to be fierce competition for that? I know my colleague follows ITC and I know they're involved and interested in Kansas and Oklahoma.

Well, currently under the SPP rules, as the incumbent utility, we have the right of first refusal to build this. That does not mean there won't be competition or other outside pressures.

There's also an SPP committee, Doug, that's looking at those rules about who will--about who will build - that right of first refusal. And there's--I'm not sure of the timing of what that recommendation would be out of that committee at the SPP. Of course, ITC is--office up in I think Wichita, and of course, they're filed here in Oklahoma to become a--to be deemed by the Commission a utility, so that they can compete in Oklahoma. And Howard Motley's here with us. I'm not sure if we know the timing of any decision on that request, Howard, at this point in time.

Yes. It really hasn't had a lot of traction right now. There's been a lot of other things going on at the Commission and there's not even a procedure schedule set for a timing to make those decisions. But it's still down in the queue.

Okay. So to answer your question, Doug, currently under the rules we have the right of first refusal. Your question refers to ITC. They are certainly here in Oklahoma. So it's not a given that we're going to have the sole opportunity to do this.

And that right of first refusal goes towards--depends on where that line is, and if it's in our service area. And so, if--the Woodward line is. And if the SPP were to--again, they have to agree with the layout of the line and the route of the line. If they were to change the route of the line, it could change those--.

--Sure--.

--That impact us as well. So there's still a lot of uncertainty in that process as you go through with the SPP.

And just to go back, Doug, when we were with you in August and this question came up, we view transmission as a fairly low risk investment. And again, it's our intention to be the builder of those lines where we have the opportunity.

And these--okay. And these would all be, of course, FERC regulated?

Yes.

And then, with regard to the--just one final question. With regard to the wind that you're talking about, what's your ability to be an owner versus a purchaser of that power? And is the Commission sensitive to the fact that a purchaser is basically living off your balance sheet?

Well, currently, as Pete mentioned, we own 120 of the 170 megawatts that we have in our portfolio today. I think the issue comes down to what's the best overall proposition for customers. That's how we were able to buy the 120 megawatts at Centennial versus purchase power. They're also I think aware that there is an imputed debt cost associated with the PPA. And so, they'll take all of those things under advisement when they look at the economics.

Okay. Thank you.

(Operator Instructions.) Your next question comes from [Adar van Gogh] with Zimmer Lucas.

Good morning.

Good morning.

A quick question on the rate based guidance. Can you say what the average annual D&A expense embedded in that guidance is?

Well, it's--we start at about 145 and go to about 175 roughly.

And I just wanted to confirm again both your rate based guidance and the CapEx exclude any of the potential [new end] and related transmission.

Correct.

Okay. And at what point in that process do you feel comfortable rolling in new projects like that into your guidance?

Well, again, the transmission is going to be somewhat dependent upon SPP. And the wind will be going through a competitive process in Oklahoma. And as those processes are determined, we'll be coming out with guidance associated with that.

Thank you.

There are no further questions at this time.

As always, we appreciate your interest--continued interest in the company. Have a good day. Thank you.

This concludes today's conference call. You may now disconnect.