OGE Energy Corp (OGE) 2006 Q2 法說會逐字稿

Good morning. My name is Wendy, and I will be your conference operator today. At this time, I would like to welcome to the OGE Energy Corp.'s Second Quarter Earnings Conference Call.

[OPERATOR INSTRUCTIONS]

Mr. Hatfield, you may begin your conference.

Thank you, Wendy. And I'd like to add my good morning and welcome to OGE Energy Corp.'s second quarter 2006 conference call. As Wendy said, I am Jim Hatfield, Senior Vice President and Chief Financial Officer of OGE Energy Corp.

I have with me today Steve Moore, Chairman, President and CEO; Pete Delaney, Executive Vice President and COO; Howard Motley, Director of Regulatory Affairs and Strategy at OG&E; and Danny Harris, Senior Vice President of OGE Energy Corp and President and CEO of Enogex; and several other members of the management team to address questions.

In terms of the call today, we'll start with comments from Steve Moore. I'll then review second quarter results. I'll also go over our revised 2006 outlook. Howard will give us an update on our all of our regulatory proceedings. And then, we'll follow with a Q&A session.

Before we begin, I want to remind everybody that we have prepared slides to accompany our webcast so it'd be easier to follow the numbers when we get to that point later in the presentation. But before we begin, I'd like to direct everybody's attention to slide number two, which is the Safe Harbor statement regarding forward-looking statements.

And with that, I'd like to turn the call over to Steve Moore. Steve?

Thanks, Jim. I would also like to welcome each and every one of you to our call. Today, we'll discuss our strong second quarter results and also talk about some important projects and regulatory cases that we're working on. And before we conclude, we will answer your questions.

In the second quarter, we reported higher earnings in both of our utility and pipeline businesses. Based on this performance and our expectations for the rest of this year, we are increasing our earnings guidance for 2006 from -- to between $2.25 a share and $2.40 a share. That is up from our prior earnings guidance of 2.05 to 2.25 a share.

At OG&E, the second quarter was 32% warmer than last year and 56% above normal. At Enogex, we continue to see the positive effect of process liquids prices relative to the price of natural gas.

In the second quarter, OGE Energy earned $1.02 per diluted share, OG&E contributed $0.48, and Enogex added $0.26. Jim has all the details, including the earnings from continued operations and earnings from the sale of some natural gas gathering assets in the second quarter.

Aside from our solid earnings and increased guidance, one of the big stories here at the Company is our plan to build a new baseload electric generating plant. It's an innovative plan in a number of ways.

First, we are partnering with AEP and PSO and the Oklahoma Municipal Power Authority with a proposal to invest about $1.8 billion in a new 950-megawatt generating unit at our Sooner generating station. We are now in the process of negotiating the details. The plans call for the new capacity to be online five years from now, in the summer of 2011. We plan to own 42% of the project.

Also, we will be working under Oklahoma's new law that enables us to seek pre-approval from state regulators, before we invest in such a major asset. We look forward to working with our partners and regulators to bring this new capacity online for our customers at a cost much lower than if we each built our own generation.

Meanwhile, construction continues at our Centennial Wind Farm in Northwestern Oklahoma. We expect to have the 120 megawatts of renewable energy online by yearend. You will recall it's a $200-million project that has already been approved here in Oklahoma, and we will begin recovering our investment when it's completed.

Another major point of focus for us is OG&E's general rate case in Arkansas, which we filed last week. We seek a rate increase of $13.5 million, which if approved would be our first general rate hike in Arkansas in 23 years. And as usual, we've got a number of other matters working in the regulatory arena, and Howard Motley is here to give you an update.

At Enogex, growth remains at the top of the agenda. We are focused on opportunities to redeploy the proceeds from recent asset sales into new investments. And as always, we continue to strive for operational excellence. We are seeing it this summer with temperatures regularly over 100 degrees here in our part of the country.

In fact, OG&E's customers set four new records for peak electricity demand in July. These records were set on consecutive days. We call that a heat storm that's hard on everybody, including our company members and our equipment. But our hardworking company members have successfully met that demand, but not without some equipment problems that continue to highlight the need for us to invest in our aging infrastructure.

Certainly, we appreciate your continued support. Thank you, again, for your interest in OGE Energy. And now, I'll turn the call back over to Jim. Jim?

Thank you, Steve. For the second quarter, we reported net income of 93.7 million, or $1.02 per diluted share, as compared to net income of 38.5 million, or $0.42 per diluted share in the second quarter 2005. Excluding discontinued operations, we reported net income of 57.9 million, or $0.63 per share, as compared to net income of 35.8 million, or $0.39 per share.

The contribution by business unit on a comparative basis is as follows. OG&E, $0.48 in 2006 versus $0.33 in 2005; Enogex, $0.17 in 2006 versus $0.09 in 2005; the holding company, with a loss of $0.02 in 2006 versus a loss of $0.03 last year; continuing operations, $0.63 versus $0.39; discontinued operations of $0.39 in the second quarter of 2006, $0.03 in 2005; consolidated, $1.02 versus $0.42.

Looking first at OG&E. We had net income of 44 million, or $0.48 per share, as compared to 29.7 million, or $0.33 per share in the second quarter of 2005. Gross margin on revenues was up 36.9 million, or 20.7%, to 215 million as compared to 178.2 million in the second quarter of 2005.

On the slide, you see the major factors driving improved gross margin. The rate increase, combined with favorable weather in our service territory, accounted for 74% of the gross margin increase. In terms of weather, cooling degree days were 56% above normal and 32% above last year's quarter.

Partially offsetting the increase in gross margin were higher expenses, and you can see the various increases on the slide. The largest variance was other expense, which increased 8.1 million over the 2005 quarter, mainly due to the loss on the retirement of fixed assets of 6.8 million.

This loss relates to a power supply contract with a large industrial customer, in which we had turbines dedicated to the customer. That contract expired. We chose to retire those assets rather than redeploy the turbines, as it was the least cost alternative.

At Enogex, we reported net income 51.3 million, or $0.56 per share, as compared to 11.3 million, or $0.12 per share, in the second quarter of 2005. Income from continuing operations was 15.5 million, or $0.17 per share, as compared to 8.6 million, or $0.09 per share, in the second quarter of 2005.

During the second quarter, gross margins increased to 69.6 million, up 11.7 million from 57.9 million in the second quarter of 2005, or an increase of 20.2%. This increase is primarily due to higher gross margins in the gathering and processing business.

During the second quarter, transportation and storage margins were 3.1 million higher than the same period last year, an increase of 13%. The main factors impacting higher gross margins were better management of gas pipeline and balances.

In 2005, we had a change in accounting estimates of the volume of natural gas and storage, which reduced net income 3.4 million in 2005. We did not have that same item in 2006. And then, higher volumes and higher prices also contributed to higher gross margins in transportation and storage.

Partially offsetting this increase were fuel over recovery reserve of approximately 5.1 million and a lower cost or market adjustment, which decreased gross margin by approximately 1.9 million. Both of those items are timing.

Gathering and processing gross margin was approximately 42.2 million in the second quarter, an increase of 23% over last year's quarter. Higher gross margin was principally the result of an increase of 12.1 million in keep-whole margins, the result of a favorable commodity spread. In the second quarter, we realized $0.259 per gallon as compared to $0.123 per gallon in last year's quarter, an increase of over 100%.

Partially offsetting the favorable keep-whole commodity environment was a decrease of 5.8 million due to the recognition of imbalance expenses that had previously been recorded in the transportation and storage business. And marketing margins were up slightly in the second quarter as compared to 2005.

On the expense side, O&M expenses increased 2.6 million, due to higher employee expenses. However, net interest expense fell 3 million due to higher levels of cash investments, primarily as a result of asset sales. The result is that expenses were essentially flat quarter-over-quarter.

On a comparative basis, Enogex had an increase in net income of approximately 37.1 million, relating to various items that we do not consider to be reflective of the ongoing profitability of the business. And you can see those items on the screen. The biggest item, of course, is the gain on the sale of the gathering assets. During the first quarter of 2005, Enogex had a net increase -- or net income of approximately 2.7 million relating to discontinued operations. And you can see that reflected on the slide.

As Steve mentioned, for 2006, the Company has increased its guidance to $2.25 to $2.40 per share or 207 million to 221 million of net income, up from $2.05 to $2.25 per share or 187 million to 205 million of net income, assuming approximately 92 million average diluted shares outstanding. The biggest change in guidance is at OG&E. The utility earnings guidance has increased to $1.46 to $1.51 per share or 134 million to 139 million, up from $1.36 to $1.40 per share or 124 million to 128 million.

Favorable weather experienced through the first quarter, approximately 70 million at gross margin, has been the big driver in increased guidance. We assume normal weather for the remainder of 2006. We also see higher sales growth of approximately 3% compared to our previous forecast of approximately 2%.

Holding company guidance has increased from a loss of 5 million to 6 million, or $0.05 to $0.06 per share to a loss of 4 million or $0.04 per share. Earnings guidance at Enogex has increased to $0.84 to $0.93 per share or 77 million to 86 million of net income from $0.75 to $0.90 per share or 69 million to 82 million of net income. We anticipate gross margins of approximately 312 million to 327 million as compared to 303 million to 324 million in our prior guidance.

Transportation and storage gross margin contribution approximately 131 million as compared to approximately 135 million in our first quarter guidance. A key factor affecting the revised transportation and storage gross margin is the lower cost market adjustment to the value of storage inventories. Gathering and processing gross margins contribution of approximately 172 million to 187 million as compared to approximately 159 million to 180 million in the prior guidance. Gross margin increase in the gathering and processing business in 2006 is primarily due to higher commodity spread offset by lower contractual gains, a result of lower natural gas prices.

We are assuming natural gas prices of $6.35 to $6.60 per MMBtu in 2006. Realized commodity spreads of $3.54 to $5.01 as compared to 2.56 to 3.46 per MMBtu assumed in our prior guidance. The commodity spread range is based on a combination of $4.07 realized for the first half of 2006 with approximately 65% of our production volumes hedged for the remainder of 2006. The remaining production volumes are subject to market prices. Average natural gas liquid prices are $0.93 to $1.22 per gallon as compared to $0.99 to $1.09 per gallon assumed in the previous guidance, and we are projecting 260 well connects in 2006.

Before I turn the presentation over to Howard for a regulatory update, I'd like to touch briefly on the July 18th announcement of our proposed Red Rock coal plant. To be built at the site of our existing Sooner generating station, it will be 950 megawatt unit to be jointly owned by OG&E with 42%, PSO with 50%, and the Oklahoma Municipal Power Authority with 8%. OG&E would be the operator of the unit. Total cost is projected to be around 1.8 billion, with our 42% share cost, it's approximately 750 million.

Howard will detail the regulatory process in a moment, but we hope to begin the construction in the third quarter of 2007 with an in service date, the second quarter of 2011. We're currently working on completing the various contracts with targeted completion date for those contracts at the end of this month. And of course, the plant is subject various regulatory approvals, and as with the Centennial Wind Farm, we would not be forward, move forward, unless we receive satisfactory regulatory approval.

And with that, I'll now turn the presentation over to Howard.

Thank you, Jim. Today, I'll be providing an update on the Arkansas rate case, the Centennial Wind project, and also the Red Rock coal plant.

On the Arkansas rate case, in May this year, May 1st, OG&E notified the Arkansas Commission of its intention to follow a general rate change. On July 28th, last Friday, the company filed its application for a $13.5 million rate increase. OG&E is requesting an 11.75% return on equity and a $306 million rate base. The test year is calendar year 2005 with adjustments through December 31, 2006. And we are expecting a commission orders sometime in 2007.

The next slide is on the Centennial Wind project. It's for Oklahoma and the Arkansas jurisdiction. In the Oklahoma jurisdiction, on February 27th of 2006, OG&E filed testimony requesting the Oklahoma Commission to approve the construction and ownership of the 120 megawatt wind project. The estimated capital cost of project, as we talked about today, is around 200 million. As part of the proposal, OG&E also requested a rider that will immediately recover the company's authorized rate of return, depreciation, add-on taxes and O&M expense.

On April 28th of the year, the Oklahoma Commission issued an order approving the project for us to build and own the wind facility and a rider that will recover the cost I just summarized and the initial annual recovery from Oklahoma customers is about $22.6 million a year. And that will begin after the wind plant becomes operational and in service.

In Arkansas, on June 8th, OG&E filed an application for approval of the Centennial project, and that was a separate application from the rate filing. In the rate filing [account] though, we have allocated a portion of Centennial that will be included and requested in the rate case that we filed on July 28th. The Arkansas Centennial annual revenue requirement is about 2.1 million of the 13.5 million that we requested in the Arkansas rate filing.

The final update is on the Red Rock coal plant. As discussed earlier with Jim Hatfield, Red Rock is a joint effort to build a 950 megawatt coal plant. PSO and OG&E will take separate regulatory path -- approval paths in the Oklahoma jurisdiction. OG&E will file a pre-approval application under commission rules that are based on a new Oklahoma law. The company is currently developing a regulatory contact. Under these rules, the commission that we file an application, they will issue an order within 240 days or about 8 month time period after we make the file.

Jim, back to you for summary.

Thank you, Howard. In closing, as we look back on the second quarter, we are pleased with our solid financial performance. As a result, we are able to increase our earnings guidance to $2.25 to $2.40 per share, which reflects our performance to date and our expectation of continuing favorable commodity prices.

As we look ahead, we will continue to execute on our strategy with asset diversity an integral part of that strategy. Our focus at the utility will be the on-time and on-budget completion of the Centennial wind project, completing the Arkansas rate case, and obtaining approval for the Red Rock coal plant.

At Enogex, we continue to pursue growth opportunities. Most of all, we look for the best way to redeploy capitol. We have a lot of opportunities for the company to add shareholder value, however, we must continue to execute.

And that concludes our prepared remarks. We would now like to answer any questions you may have.

[OPERATOR INSTRUCTIONS]

Your first question comes from the line of Doug Fischer.

Good morning.

Good morning, Doug.

Congratulations on a great quarter. Talk to us a little bit about the growth opportunities at Enogex, and whether some of that capital might come back to the utility to fund Red Rock. And any update on the age-old MLP question with regard to Enogex?

Okay, I'll start with the capital rate deployment question and I'll Danny comment a little bit on the growth opportunities we are currently seeing. But would the capital come back into the utility, that's one possible way to redeploy capital. And in fact, we are seeing that in the wind project in 2006, as we are completing that $200 million capital investment without any additional external equity, as we just fund the equity from the holding companies.

So that would be one way we could to do that. I'll just keep in mind that the Red Rock facility while out there is always a way from extensive capital needs. And Danny, would you may be talk about the things we are seeing in growth at Enogex.

Certainly, good morning, Doug.

Good morning.

We continue to look at possible entry opportunities in the Rockies area. That, of course, is a process, and there is nothing immediately pending on that that would be executed in short term. We are having success, however, continuing success with Mid-Continent area with expansion on the west side of our system into more of a growing basis there, a lot of drilling activity in the West. And we are also in the progress of looking at some other opportunities that provide minor expansion opportunities on the southeastern part of our system, of the southeast side of our system.

And Doug, the last piece of your question was the MLP question, and I guess, we will respond much like we have in prior calls. We continue to evaluate all the options to maximize shareholder value. And in the context to Energy an MLP, would an option under consideration. The benefits to our shareholders associated with only Enogex and MLP is impacted by many factors, as you know, among other things, the tax basis of our assets, market multiples of comparable MLPs, impact on cash flow and earnings, and the impact on OG&E stock valuation.

And a difficult issue for us is our existing low tax basis on Enogex assets. We continue to look at these issues and others in evaluating all of our options to enhance shareholder value. We expect to complete the review in the coming months, and we will take any recommendations if they're, as appropriate in these matters to the board for their consideration. But keep in mind our review of the strategy and our options to increase shareholder value is a continuous process and is a discrete annual effort, so I guess, this is something that is ongoing as we continue to look at this issue and others.

How challenging is the reinvestment issue? I know the tax issue is a challenge. Red Rock would have seemed to provide some, given timing, would provide some opportunity for reinvestment that you haven't had before.

Well, that's true. But if you look at the timetable, beginning construction in '07 and completing in second quarter of 2011, you are really talking about '08, '09, 2010 as really your timeframe of where you need most capital. So that's 2- 3 years down the road, so --

Yes, I understand.

Yes.

Okay, thank you.

Thank you, Doug.

[OPERATOR INSTRUCTIONS]

Your next question comes from the line of Neil Choi.

Hi. Could you provide an update on the gas pipeline project you are developing with El Paso?

Sure. You are speaking of Continental connector, Danny, you want to provide an update?

I'll be glad to provide an update on that. As you know El Paso closed its mining open season back in July and that was actually extension from their original date. They still feel optimistic about the project, but right now it's down to negotiations with a few remaining parties.

We expect to have some type of word from that in the probably, the mid-August timeframe. We do expect -- I think we originally talked about the project from an Oklahoma standpoint, Enogex standpoint being in the neighborhood of 500 million a day project. We expect that be downsized somewhat. But El Paso is still optimistic about the project.

Have you ever publicly stated how much of a capacity you was kind of biding during the binding season back in July?

No.

Subscribed or -- ?

El Paso is not being public on the individual constituents of the project.

Okay. Thank you.

Your next question comes from the line of Erica Piserchia.

Hi. How are you? Just two quick questions, first, with regard to sort of decisions in the coming months on what you will do with Enogex, and then obviously the power plants towards the end of the decade. Can you just talk about how some of these things may be impacting the way you're looking at the dividend right now, in terms of potential for dividend growth?

Well, Erica, in terms of looking at the dividend growth, obviously, in one aspect, you have Enogex and its earnings and cash flow contributions to Energy Corp. as a whole. And that will have to be considered in the context of a dividend increase as well as the fact that, assuming Red Rock goes forward, you will be entered into period of higher CapEx and that will have to be consider as well. So we'll take our five-year earnings plan and cash flow, in Enogex and Red Rock and anything else that's on the table and have to factor that in considering the dividend.

Okay. At this point, can you say whether or not, if you did Red Rock, is dividend increase out of a question?

No. Again it would just consider the capital needs, building the plan in the context of what a proper dividend rate should be going forward.

Okay. And then just one other quick question. On the wind project, given that you're kind of targeting to have that in service, beginning next year, I am assuming that [inaudible] energy has the turbine already, is that correct? Or the turbines.

Yes. That's correct. Construction's underway and we are proceedings on that path to be complete by the end of year.

Okay. Thank you.

Your next question is from the line of [Kathleen Kucikitz].

Good morning. I was wondering if you could talk a little bit about the decision to increase the expected demand, customer demand from 2% to 3%. Is that purely weather-related, or are you saying underlying demand growth that would worn that step up? Is that a longer-term trend or just weather related?

Well, Kathleen it's not weather related. I think if we look at our growth rate, we're seeing -- we have seen historically customer growth of about 1% a year. We're now seeing customer growth of 1.4% to 1.5% a year.

If you look at sort of second quarter results and you look customer growth plus quantity variances, you see about 6 million in the quarter. And if you annualize that, you see growth somewhere about 3% to 3.25%. And I think at this current time we are seeing the underlying economic growth in Oklahoma City. Whether or not that's going to continue for several years out, we don't know, but we are seeing in 2006.

Great. Could you also talk a little bit about how base load demand is growing versus peak load demand? Is there difference in the growth rate between the two?

Between annual peak demand and annual base load demand?

Yes. Please.

Well, you're always going to have your peak impacted by weather, which, of course, is going be driven primarily by your residential customer base. We're seeing our peak go up about 110 megawatts on annual basis. And about half of that we would consider just increased customer demand year-over-year. And half of that is weather-related peak. And, of course, of we plan for generation; we have to take into account the pure peak, because you have to satisfy customers when they need power.

Great. Thank you so much.

Your next question comes from the line of Reza Hatefi.

Thank you. Could you discuss how tax rate or recovery for the Red Rock CapEx can work?

I guess, your question was how the recovery of the CapEx at Red Rock would work?

Yes, I forgot, would it be rolled into rate base or would it be like a one-off recovery process similar to the wind farm?

I think that we right now, we are looking at a regulatory strategy for filing here in Oklahoma later this year. And part of that filing will be to ask the permission to a finding of prudence, in other words that building the coal plant is the right thing to do, also prudence of a specific dollar level of investment that would not be adjudicated in future hearings.

And then, of course, the third issue that would be the in application, will be inclusion of CWIP in the rate base in a rate proceeding. We really haven't determined yet exactly what the process will be, I think there is an opportunity for a rider, maybe, like we had in Centennial, but also we'd like to get permission to recognize that under the new pre-approval law at a minimum in the next rate case we would get to include construction work in progress in our rate based because the historical policy has been not to allow -- [CWIP] in rate base is not completed, by the time you go to hearing in a rate proceeding. So think the option's there for both of them, a rider or CWIP in rate base and we'll be presenting that to the commission later this year.

I'm guessing that the rider will be preferable, okay, because the CWIP in rate base have regulatory lag between rate cases?

Well, obviously if we have a preference from a recovery, the quicker recovery, the better for us. So and again we are sort of speculating on the menu of ways to recover that, yes, we are going to -- we would seek to recover and minimize regulatory lag.

Could you give us the latest frac spread that you are seeing in your systems?

Yes. As of last week, we're saying about $6 from a market perspective, this based on the prices of gas and liquid prices.

Your next question comes from the line of Jeff Coviello.

Good morning guys. How are you?

Hi Jeff. How are you?

Good. I think I just heard the end of last question. Was it, you were saying that frac last week was about $6?

Yes. The processing spread, which is what we are seeing in the marketplace was $6 frac.

I guess with the recent run up in gas versus oil, though these NGL prices are more tied to oil than they are to gas. I assume that there was some recent compression. Is that correct generally?

Generally, from if you look at June to July, you would see a compression in those market prices, keeping in mind, we're 65% ahead on volumes throughout the remainder of 2006, which is incorporated into our guidance.

And looking forward on a longer-term basis, what's the -- and obviously these fracs are very wide, has there has been a historical level of the frac spread that's may be more indicative of the long-term relationship that if you think about?

We don't know what normal is. I mean --

Okay.

You know it's cyclical, it goes in cycles. We're in a period now where you are seeing oil at $75. If you take 2000 and 2004, for example, on average over that timeframe was $1.58. So I think from the commodity cycle perspective, we are in the high side of the cycle. How long that continues depends on a lot of things, including crude oil and how long it stays up at the levels and then what happens in demand and supply of natural gas.

I guess it's fair to say that the guidance you have now assumes the current levels of oil prices and gas prices.

It would assume - it's really made up of two pieces. One is what we have locked in for the remainder of 2006 and then what we see as sort of the market as we look over the last six months of the year.

Great. Okay. Thank you very much.

Your next question is a follow-up from the line of Doug Fischer.

Thank you. It's my understanding that you have not hedged the processing spread in '07 to any material degree. Is that accurate?

That's correct. Not to any material degree at this point.

Okay. And how soon do you start doing that. My understanding was that was sort of three to six months ahead. Is that that you at least consider it?

Yes. I think we've gone out as far as nine months. If we're looking at locking sort of keep on spreads. But typically, you're within that three-six months and with in terms of having a deepen up market that we think we can execute it efficiently.

And is -- when you say that PSO is going to pursue a different regulatory path -- is it just that just that there is a separate proceeding, or are there , you know somewhat unique circumstances for PSO that are different than yours?

Where there is long unique circumstances. PSO filed a case for a base load plans earlier this year, before the new law was promulgated into commission rules. So they really are operating under the new law or new commission rules. They have another process going.

It'll be similar approval, but we will be actually be operating under the commission rules and seeking the prudence of the plan and a dollar amount. But like I said, since it is a joint effort, both companies will have to receive the appropriate regulatory approvals sometime next year, in order to be able to go forward with the project.

And I think a key thing, Doug is while it maybe on separate tracks for the reasons Howard mentioned from a timing perspective, we're looking to stick up to these timing's obviously so we're able to get approval on the same general timeframe so we can move forward.

Remind me on the wind, what is the rider collecting - it's return on equity a cost of debt?

Yes. It's a matter of fact, it's like a mini-rate case. It's a -- the investment's your rate-base, you get a rate of return on it to recover your stockholders equity and interest, depreciation, O&M expenses and [inaudible] tax. So it's like a mini-rate case for that one project.

So there is no peice that's missing there?

No. It's full recovery.

Okay. And that is -- that occurs once it goes is declared commercial.

Yes.

Okay. And that's an option -- a potential option for Red Rock

Yes. I think it would be. It would be ....

And remind me of that was by law that that's allowed under certain circumstances. Isn't it by a law change, I'm trying to remembering.

The Centennial or Red Rock?

No, the rider.

Yes.

Just commission practice.

Now, that's a more of a commission policy. In other words the law, under the pre-approval process, we can ask for recovery and we can ask for any type of math and as on that we would like to implement. But it is under the discretion of the commission to approve a rider or rate base or some other mechanism

But the rider based on past practice wouldn't allow you to get a cash return on your investment during the construction period?

Well, I think in the past we really haven't had a rider except on items that are actually plant in service not construction. I think the answer is yes.

Okay. But there is nothing to prevent the commission from using a rider as opposed to CWIP.

No. As a matter of fact, I think the difference is under the new commission rules, now, that they have pre-approval, it puts it in a different light than construction work used to be. So I think there is lot more -- a better foundation for allowing CWIP recovery in a rider today.

Okay. Thanks. That's helpful.

[OPERATOR INSTRUCTIONS]

Your next question comes from the line of Peter Hark.

Good morning, everybody.

Hi, Peter.

Hi, Jim. A follow-up question on Enogex. First, has the tax basis changed materially since the sale of the gas and gathering assets in the second quarter?

No.

What is that now, the tax basis?

The tax basis if Enogex is shown on the balance sheet, it's about $285 million.

And have you guys looked in ways of sheltering the tax leakage if you move to an MLP structure?

Well, I think anything we do with Enogex obviously -- the tax basis is a key part of that. So sheltering taxes or maximizing proceeds would be, you know, one large objective in anything we do.

I guess what I mean is, is there any potential, for instance, in funding for instance, Red Rock. Are there any types of, I don't know, like kind exchange of assets that allow the movement into the MLP and then the financing of something like a Red Rock? And thereby, taking care of some of the tax burden?

I guess, Peter, the answer to your question, there is a multiple ways that you could do something if you tried to do anything. I guess the point we're trying to make is that we're looking at the options, and, we'll and obviously one thing that's important in the context of that is the tax basis. And so that's one thing we have to keep in mind.

Right. Do all the assets now currently qualified, I mean, you got 8,000 miles of pipe and the storage fields and the processing plants. That would be all that would qualify. Is there anything that would not qualify?

Qualify -- I guess the answer to your question depends on what your like-kind exchange and what that asset is. I think like-kind exchanges are very difficult to do. But if you find like-kind assets, I guess, anything is possible. But it's -- I am not sure I can provide much clarity on that other than, I don't know why they wouldn't qualify.

Okay.

But again it depends on what you're exchanging for.

Right. It just a thought that, you're looking at some stuff in the Rockies, and whether it's new- build or old purchased construction, whether there is the opportunity in expanding the business and thereby raising the tax basis overall. Is that part of what you're looking at?

Sure. It would be one thing we would look at. In fact, we sold Ozark assets, and as Danny had talked earlier, some of the step-out projects we had done some like-kind exchange in construction of new assets, which was done, again, to minimize the your overall tax bill and that be whether we did anything as a whole or in part, we had always look to minimize taxes that way.

Okay. That's great. What is the expected production at Enogex for '06? I think you did like over 300 million gallons last year. What will it be this year?

We see that production and of course assuming that you don't reject ethane at some point throughout year would be essentially flat year-over-year. Again, there was pretty much dry gas or having lot of production with that.

Okay. And then, what was the realized frac in the second quarter?

The realized processing spread in the second quarter was $4.39.

4.39?

Yes.

And you were off to $6 spread year -- ?

The market is off to $6 spread in the second quarter, yes.

Right. Gotcha. And then, just in terms of guidance, I mean, you've talked about all of it reflecting where you were through June 30th. It sound like you were off to a pretty hot start here in July, and didn't know what the impacts might be at both the utility and the fracs that you're seeing down on Enogex, I mean, on a combination basis, it sounds like you're going to be beyond normal or ready for the third quarter. Is that fair to think?

Well, I think from revenue -- gross margin perspective as the utility July was about 25% above normal from a cooling degree day perspective. Of course, with hot weather comes incremental O&M, as it stresses the system, but there is two other months left in the quarter. And we have seen and 2004 is a great example of that where we had a warmer than normal second quarter and a very, very cool third quarter sales. If weather continued, we expect to see an increase in gross margins, but we could give that back or most of that back throughout the remainder of the second half.

Okay. Just being cautiously get on that side. Last question is on Red Rock. Just to understand, you are 42% owner, but you're the operator. Is there any -- first what are -- what's the fee status from both PSO and MUNI in terms of paying operating fees. And do you have kind of control over dispatchability and who keeps the upside to the extent that you market that output in the out years? Do you get greater economics versus the 42% ownership?

You know, Peter, I'll say first of all we're, as like I said earlier we're still hammering out these agreements, but I think our sort of vision and the vision of our partners would be that we sort of share proportionate. And just because we are operators, it's because we're at the Sooner plant where we're already operating two units. So we would not expect to see or planning to see upside beyond our 42% joint interest in the plant.

Okay. Well, thanks for your time Jim. Congratulations.

Thank you, Peter.

There are no further questions at this time. Mr. Hatfield, are there any closing remarks?

We would like to thank you for your interest in the company. And have a great day.

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