OGE Energy Corp (OGE) 2004 Q2 法說會逐字稿

Good day, all sites are now in the conference line in a listen-only mode. I'd like to turn the program over today to Mr. James Hatfield. Go ahead, sir.

Thank you. Good morning, everyone and welcome to OGE Energy Corp’s second quarter 2004 conference call. I'm Jim Hatfield, Senior Vice President and Chief Financial Officer of OGE Energy Corp., and I have with me today Steve Moore, Chairman, President, and CEO of OGE, Pete Delaney, Executive Vice President and Chief Operating Officer, and Howard Motley, Director of Regulatory Strategies for OG&E. And we have several other members of the management team here to address questions.

In terms of the call today, we will hear comments from Steve Moore. I will review the second quarter and discuss the 2004 outlook, then Howard Motley will cover the regulatory proceedings we have going. Steve will provide a summary, and then we'll turn it over to Q&A. But before we begin, I want to remind everyone that we have prepared slides to accompany our webcast so it will be easier to follow numbers when we get to that point.

Additionally, before we begin the presentation, I would like to direct your attention to the Safe Harbor statement regarding forward-looking statements. This is an SEC requirement for financial statements and simply states we cannot guarantee forward-looking financial results but this is our best estimate today.

And with that, I turn it over to Steve Moore. Steve?

Thanks, Jim. Thank you for joining us on the call. We do appreciate your interest in OGE Energy.

First, I'm very pleased to announce that we're celebrating our completion of the McClain power plant acquisition. It turned out to be a bit more of a challenge than we expected, but our people focused on FERC's concerns about wholesale competition in our regional electricity markets and what we could do to address those concerns.

The solution we devised, including nearly $20 million in transmission and substation upgrades, will support competition and increase the capacity of our high voltage transmission systems. FERC has approved our plan and we completed the acquisition in July. In fact, we expect the permanent financing to be completed for the plant with a long-term debt offering by OG&E, our utility, very soon.

We look forward to completing the integration of the McClain plant into our fleet, and to focusing on what we will need to do to ensure the plant delivers on its dual promise -- lower cost for our customers and higher earnings for our share owners. We don't expect to make any regulatory filings pertaining to the McClain plant this year, but we'll be required to file for a rate review in Oklahoma in 2005, before the anniversary of the acquisition in July.

Also today, we'll tell you about our second quarter results and update you on some of the other important issues we're working on. And as usual, there will be time for your questions at the end. We are pleased to report that OGE Energy Corp. reported second quarter net income of $39 million, compared with $32 million a year ago. That translates into 44 cents a share in the second quarter this year, compared to 41 cents per share a year ago.

OGE average common shares outstanding increased by 11% over last year, so obviously, we're very pleased with that result. Both OG&E, our regulated electric utility, and Enogex, our natural gas pipeline, have improved their financial performance compared to last year.

OG&E benefited slightly from weather, and the business environment in the second quarter for Enogex was good, with favorable commodity prices and increased volumes in the natural gas processing business. We applaud the work of our company members to capture value and control their costs. It's the kind of work that is never finished, and you can expect us to remain sharply focused on the details of our business, as we always have been.

And of course, for us, these are not just words and we have two important examples in the last few weeks as to our focus on the details of our business. I have already mentioned the McClain power plant acquisition. Also, at the end of June, Moody's Investor Service upgraded its credit rating outlook for Enogex from negative to stable.

Results always speak for themselves, but we're pleased to have an important third party such as Moody's acknowledge our success. Another issue of interest is the expiration this month of OG&E's contract to purchase power from Smith Cogeneration here in Oklahoma City. We have reached an agreement on a new contract which should preserve nearly 2,000 jobs at the Dayton power plant.

As usual, we are focused on a number of other regulatory and operational issues, both in Oklahoma and Arkansas. Our Director of Regulatory Strategies, Howard Motley, is here, and he will provide you with an update on some of these activities in just a moment. Jim Hatfield will explain the financial details in a minute, but I'm pleased to reaffirm our 2004 earnings guidance of between $1.60 and $1.70 per diluted share.

It's shaping up as a good year for us, and as always, we're focused on the challenges of the year ahead. Again, I would like to thank you for your continued interest in the Company and turn the program back over to Jim. Jim?

Thank you, Steve. I would now like to cover the earnings of OGE Energy Corp. and I will start with the discussion of the second quarter, discuss the contributions of the business units in the quarter, and reaffirm 2004 guidance. For a discussion of the second quarter, as Steve mentioned, we reported net income of 39 million, or 44 cents per share in 2004, as compared to net income of 32.2 million, or 41 cents per share in the second quarter of 2003.

The contribution by business unit on a comparative basis is as follows -- OG&E, 34 cents versus 35 cents in the 2003 quarter; Enogex, 13 cents, versus 10 cents in the 2003 quarter; and the holding company, with a loss of 3 cents, versus a loss of 4 cents in 2003, 44 cents as compared to 41. For OG&E, net income was 30.4 million, or 34 cents a share in the quarter as compared to 27.9 million, or 35 cents per share, in the second quarter of 2003.

Decrease in earnings per share for the second quarter of 2004 is due to higher average common stock outstanding pursuant to the issuance of shares under our DRIP plan and our equity issuance in August of 2003. Gross margin on revenues were down 2.7 million, or 2 cents per share, to 168.3 million in 2004 from 171 million in the second quarter of 2003.

The major factors impacting decreased gross margins were -- $3.5 million of lower fuel recoveries, $900,000 due to lower sales to wholesale customers, primarily resulting from reduced purchases of power under our new contract with an existing customer, partially offset by about $1 million due to warmer-than-normal weather, and $800,000 due to growth in OG&E service territory. In terms of expenses, O&M expenses decreased 3.4 million, or 3 cents per share, to 171.5 million in 2004 from 74.9 million in the second quarter of 2003.

O&M expenses were lower due to payroll-related expense, wages, and benefits, partially offset by increases in outside services and materials and supplies. The lower O&M expense at OG&E is due to timing. As we commented in our last call, we established a contingency plan to address the uncertainty surrounding the $25 million customer savings issue and have reduced our pending resolution of that issue.

That was resolved positively in April. As a result, I anticipate that expenditures deferred in the first 4 months will be spent as planned in the second half of the year. Other expenses were also up slightly in the second quarter of 2004 and income tax expense decreased 2.1 million due to a change in the timing of the recognition of book and tax differences in 2004, and the recognition of additional state tax credits, partially offset by higher pretax income.

So to summarize the utility -- gross margins off 2 cents; O&M, 3 cents better; income taxes, 2 cents better; and additional shares outstanding dilution of 4 cents, for a 1 cent negative comparison. At Enogex, net income increased approximately 49%, coming in at $11.5 million, or 13 cents per share in 2004, as compared to 7.7 million, or 6 cents per share in the second quarter of 2003.

Gross margin on revenues were 68.2 million, up 8.6 million, or 6 cents per share, as compared to 59.6 million in the second quarter of 2003. As you can see, Gathering and Processing posted the largest increase in gross margin with marketing margins slightly higher. These increases were partially offset by lower Transportation and Storage margins.

During the second quarter of 2004, Transportation and Storage gross margins decreased by 1.9 million from the second quarter of 2003. The various factors impacting gross margins were an increase of 1.7 million due to increase in nonfirm revenues; these are cross-haul and interruptible revenues; 1.1 million increase in Storage margins due to new contracts and demand fees.

These were more than offset by $3.8 million due to certain contractual revenues recorded in Transportation Storage in 2003 now being recorded in Gathering and processing for 2004, and $1.5 million less due to reduced fuel recoveries associated with underrecovered fuel in prior periods.

In Gathering and Processing, gross margins increased 10.1 million quarter-over-quarter. Gathering gross margins were 6.4 million higher in 2004 as compared to the second quarter of 2003. Higher gross margins were the result of the previously mentioned contractual revenues recorded in Transportation and Storage in 2003, now being recorded in Gathering and Processing 2004, as well as higher fees from contract negotiation efforts and an overall favorable business environment.

Processing gross margins were 3.7 million higher in 2004 as compared to the second quarter of 2003. Higher gross margins on revenue were primarily driven by higher NGL prices. Average sales price per gallon was 68 cents in 2004, as compared to 55.4 cents in the second quarter of 2003.

Marketing gross margins were up slightly in 2004 from the second quarter of 2003, due to higher Storage margins. For the second quarter of Enogex, O&M expenses increased by 2.7 million over the second quarter of 2003, primarily due to increased allocated costs from OG&E of about 1.3 million, increase in payroll-related cost, wages and benefits, as well as higher materials and supplies expense.

Other income increased 1.8 million, primarily due to the gain on the sale of Compression of Processing assets. We also had higher income tax due to higher pretax income, and a change in the timing of the recognition of book and permanent tax differences in 2004.

During the three-months ended June 30, 2004, Enogex had approximately 2.6 million in net income related to various nonrecurring items. Authorized recovery of previously underrecovered fuel provided a positive earnings contribution of approximately 1.6 million, and Enogex had a gain on the sale of Compression and Processing assets of approximately 1 million.

During the three-months ended June 30, 2003, Enogex had approximately 3.2 million in net income from the authorized recovery of previously underrecovered fuel. As Steve mentioned, we are reaffirming our previous guidance of $1.60, $1.70 per average diluted share for 2004.

Incorporated within our guidance are the following key assumptions -- no change in rates and normal weather at OG&E, positive impact of nonrecurring items, and average diluted shares outstanding of 88.4 million. Based on these assumptions, we anticipate OG&E earnings $120 to $124 million for 2004, Enogex earnings of $34 to $38 million, and the holding company with a projected loss of 13 to 14 million.

And now, I'd like to turn the presentation over to Howard Motley to provide a regulatory update. Howard?

Thanks, Jim. Last year, the Company filed at the Oklahoma Commission a request for approval of a $46.8 million Transportation and Storage contract with Enogex. The parties to the case that filed the responses to OG&E's request and the Company plans to file rebuttal testimony on August 16.

After we file rebuttal testimony, in September, we will have a settlement conference on the case, and on September 16th we will begin the hearing for three days. The case will be heard by an administrative law judge instead of the commissioners, and the law judge will have to issue the recommendations on October 22nd. Anyone that disagrees with the law judge's recommendation can appeal to the commission, and that has been scheduled for November 16th.

This procedure schedule will allow the Company to get a resolution to the Gas Transportation and Storage case by December of this year. Another case in Oklahoma that will be also moving to hearing in the next few months is OG&E's request to the commission to authorize a recovery rider for costs relating to the security of the utilities infrastructure.

The next step in that is response to testimony, and it will be filed August 13th. After we file the responsive testimony, then parties will have a chance to file rebuttal testimony September 13th, and then we have a settlement agreement, or a conference, in October the 5th, and hearings are in November.

Again, this will be heard by an administrative law judge, and the law judge will issue a report by December 17th, and you can appeal that report in January, January the 13th, with hopefully a final order in that case for the recovery rider by February 2005.

And that's kind of the update in Oklahoma. There's no activity in Arkansas right now. I'll turn it back to Steve for a summary.

So to Slide 15 and a summary, before we get to your questions, I think we've had a very solid second quarter. We've been helped by a favorable business environment. We're very pleased to have completed the McClain power plant acquisition, and we do anticipate a rate filing in 2005.

Another regulatory proceeding, our Gas Transportation and Storage agreement, those proceedings should be complete by the year-end 2004, and we feel like our business plan is on track with a focus on continuous improvement.

We are increasing our investment at OG&E, our electric utility. We have a constant focus on what we call our reliability and savings plan, which is very important to us, our customers, and our share owners. Moody's has removed their negative outlook at Enogex, and we are reaffirming our earnings guidance for the year of $1.60 to $1.70 per share.

So now, we will turn to your questions.

Thank you. [Operator instructions.] We will take the first question today from [Paul Debias.] Go ahead please.

Hi. This is Paul Debias. Why have you decided to delay the filing for -- to put McClain in the rate base until next year?

Well, we are looking at our overall cost of service as well as -- and probably most importantly -- the fact that -- and if you remember our prior conversations about our reliability and savings plan, we have increased capital expenditures at the utility this year. We expect to be at about 212 million with a similar amount in 2005, and using a full-year cost of service in 2004 allows us to capture as much as the increased addition to rate base as we can.

Jim, I'd like to -- this is Howard Motley -- I'd also add that we were approved a regulatory asset in the settlement agreement, and so the cost of the plant during this next year for 12 months will not be hitting the profit and loss statement. We'll be accruing that and recovering it in the rate case. So we have a little extra time to file the case without an impact on the financials.

Okay. And do you know when in '05 you would expect to file?

No. We would anticipate a 2004 tester now, so some time in the first half of 2005 would be when we would file.

And will you file something in Arkansas at the same time?

We wouldn't anticipate filing both at the same time. We would typically have Oklahoma first and then Arkansas the follow-up, afterwards.

All right. Thank you.

The next question comes from Paul Patterson, Glen Rock Associates. Go ahead.

Hi, how are you guys doing?

Good. How are you, Paul?

All right. I wanted to sort of touch base with some of the nonrecurring items. Enogex, it looks like you guys are saying it was about 2.6 million versus 3.2 million, and it also looks like there is a $2.1 million tax benefit that you guys got corporate-wide; is that right?

There was -- (multiple speakers)

Or is that recurring? I didn't really gather what that -- ?

It was a one-time benefit that we -- there are two components. There’s a one-time benefit we got from some Oklahoma state tax credits that we got where we filed amended returns and we got -- requested credit for prior years. And then we also had a timing issue where we dealt with the recognition of permanent book tax differences, which over a 12-month period there is no impact -- just benefited in the first and second quarter. It will turn around in the third and fourth quarters.

So how much of the 2.1 is because of the tax credit and how much is just the timing difference?

The 2. -- of the 1.7, I think it would be 1.2 is the tax credit, and the balance will be timing.

Okay. I'm sorry, I thought it said 2.1 for the difference in taxes. Income tax expenses decreased 2.1 million due to the change in the recognition of book taxes and the recognition of additional tax credits? That's what I see in Slide 6?

Yeah. Yeah, okay, yeah. I think -- I gave you the -- well you asked for the total -- there’s 1.7 for the utilities, .4 for Enogex with 2.1 million difference, and 1.2 of the 1.7 at Enogex was a credit. About .2 was a credit of the utility and the rest is all timing.

Okay. And that is in addition to the 2.6 million that you guys have on that Slide 11, I think it is? Is that right?

Yeah. One-time benefit of the tax credit would be an addition of 2.6.

Okay. And then the $600,000 from the renegotiation of the contract, could you -- at Enogex -- could you explain what that is again?

Well, we're just -- we continue to -- and we've talked many times about continuing to work on increasing the returns on -- under our existing asset base. And as we contract expire, we try to negotiate new contracts under more favorable terms where we would either try to purchase gas at a discount to index, or increase the gathering rate, accordingly, and that's just a continuation of the effort to increase our returns under existing customer base.

Okay. So -- (multiple speakers)

(multiple speakers) -- after that began back in 2002.

Okay. So in other words, I mean, we should just see this as contracts that were less favorable, you were able to get more favorable, either because of a change in market conditions or what have you. This isn't just -- you're not restructuring contracts to bring earnings in the near-term, correct?

No. We're just continuing to try to improve our profitability under those contracts as we go forward.

Okay. Great. Thanks a lot.

Next question comes from Doug Fischer, A.G. Edwards. Go ahead, please.

Thank you. Could you -- two things -- could you go over once again what you just covered with Paul on the one-time tax items? I'm not sure I really understood that or got it as clearly as I would like.

Yeah -- (multiple speakers)

The 2.1 is divided into -- how much goes to each unit?

1.7 to Enogex, (multiple speakers)

(multiple speakers) utility – (multiple speakers)

(multiple speakers) excuse me -- 1.7 utility and .4 to Enogex.

Okay. You're coming in real -- you must not be close to the phone. You're not coming in real loudly.

Here let’s move the microphone -- (technical difficulty) 1.7 for utility and .4 to Enogex.

Okay. And then of those amounts, how much is what? Of the 1.7 at the utility, break that down to the pieces then.

1.2 for tax credits, the balance to the timing issues, and then .2 with Enogex and .2.

Okay. Thanks. That's helpful. Then another question, at the utility, remind me why we have fuel recovery mismatches at the utility on a quarterly basis?

Well, we typically don't, Doug. Fuel is a pass-through in Oklahoma, Arkansas and FERC. But in the second quarter of '03 -- and this is an item from 2003 -- we underaccrued fuel in the second quarter. This was fuel that we were able to recover. The result of underaccruing fuel in the second quarter is, it increased our gross margins in 2003 second quarter.

We did accrue that fuel, the remainder of 2003, so over the course of the year, we were balancing the mechanism worked like it did, but it was just an underaccrual issue in the second quarter. And occasionally that will happen, and it happens when you have volatility in gas prices and months where sales ramp up over the prior month.

Okay.

It's an anomaly. It doesn't happen --

I follow you. That's a good explanation, Jim. And then could you -- what are the parties' positions on this transportation case? Can you discuss that a little bit?

Howard do you want to --

The different positions?

Yeah.

Do we have testimony from various interveners and where do they stand?

Yes, the Company asked for $46.8 million in the contract between OG&E and Enogex. The staff of the commission is recommending that amount, the 46.8 million; historically, there won't be a refund, and that we would get to keep that 46 -- or $47 million -- until the next general rate review. And then they're suggesting or recommending the commission, at the next general rate review that we either competitive bid again or come back in and prove that it's a market rate.

So that's kind of the good point of the testimony. The Attorney General's office hired a consultant that's recommending about 30, almost 35 million of the 47 million, and is recommending a refund of about $12 or $13 million. And then have you the industrial class that's recommending about 30.8 million.

So you have a swing pretty low to the industrial class, the customer at this organization is recommending a low amount, and then the Attorney General's a little closer to the staff, and then the staff is recommending 100% recovery for the case.

Okay. So the staff is recommending 44.8 or a different number?

No. They are recommending exactly what the Company asked for -- 46.8 million.

46.8. Okay. And they're not saying anything would be subject to refund at this next general rate review, are they?

No. That would be left up to the next general -- no, the next general rate review will be to step the rate prospectively, right.

Okay. And -- okay. Okay. That's helpful. Thank you very much.

Before we take our last question, I would like to remind all participants that to ask a question, you may press star and one on your touch-tone phone. Next question comes from Jeff Covello, Duquesne Capital. Go ahead, please.

Good morning, how are you?

Good. How are you?

Good. I just wanted to see on this security cost rider case, I guess currently, what sort of cost impacts are you seeing at the utility from that item and what are you looking to recover? Is that more of a forward-looking --

The Company proposed about a -- almost a $40 million of new investment and several million dollars of expense as O&M. The staff has recommended $19 million capital investment, and about $3 million of the O&M for the case.

We sit down with the staff and we're coming to an agreement right now, but I think what it's going to be looking like is the only difference of the two -- between us and the staff -- is the transformer inventory, keeping up with the inventory. So I think we are going to settle the case. Based on the other investments of the 3 million, the rider will bring in about $5 million a year of new revenues to pay for that.

And so after we receive the approval of a recovery rider, then when we start making the investments and we automatically, every 3 months, can adjust that rider up to start recovering the revenue requirement on that investment.

Got it. Got it. And just at the Enogex business. I know ,over time, you guys have worked on limiting your commodity exposure at that business and it seems like you've been able to benefit from some of these higher NGL prices there.

I was wondering what portion of that is just from having higher-price contracts and what is actually from the fluctuation in commodity prices we've seen over the last few months?

Well, we know in processing the increase quarter-over-quarter is essentially all the benefit of higher liquids prices; as we said, liquids were 68 cents versus 55.4 in the prior year's quarter. In the Gathering segment, obviously, we benefit in some intangible ways as well with the commodity price environment.

You know, the default processing fee minimizes the spread between the negative impact to us on the spread between natural gas liquids and natural gas prices as we see these higher natural gas prices, but higher relative liquids prices and we still get the benefit from not only the increase in the spread, as well as the fact that we have rate counts increasing --

Sure.

-- more activity, and that sort of thing. So in the quarter, when we look at Gathering, we see higher fees from the renegotiation efforts. And this is, again, back to the prior question about what's all in that. It's being able to buy gas at a discount, and these are really, probably, in the neighborhood of $2 million margin increase in the second quarter just from the continuing improved profitability under the existing contract.

Got it. Got it. Great. Well, thank you very much.

You're welcome.

Have a question from Doug Fischer, A.G. Edwards. Go ahead.

Just a couple of follow-ups. In your statistics at the end of your release, you show well connects as being up for the year but down slightly for the quarter, and gathered volumes are down ever so slightly as well. Could you give us some color on those numbers?

Sure. You know, in the second quarter, and June especially, we saw a very wet June in Oklahoma and as a result, we saw less new wells connected just because of the inability to spud wells, get to the field, that sort of thing. I think the six-months ended June 30 is representative of the activity that we're seeing on the system. We do have a backlog.

The first part of July was also very cool, I think -- and wet -- and we saw, really, that impact as well on the utility as a lot of home construction was delayed, really, at the end of the second quarter and the third quarter. But we see a continued strong environment, rigs running, continue to be up, and it's really just a timing due to inability to be out in the field.

And the gathered volumes? With all the new well connects, how come we're not seeing a larger increase in that?

Well, gathered volumes are essentially flat and well connects are up for the six-months ended, and volumes are up slightly, and we're drilling wells with high initial flows and high depletion rates. So it's a matter of continuing to need to drill constantly just to keep volumes steady, or for us, slightly up.

It also has something to do with, Doug, on if you're having to get some of the big wells that are coming on, and right now, through the year, we haven't had our share of the big wells, we hope to get those. But again, with the higher depletion rates, you have to run faster and you had probably, historically, to keep your volumes up.

And why would you say, Peter, that you haven't gotten some of the larger wells? Is it just location of where your gathering system is or is it some other competitive issue?

No, I think it's just more location on where the drilling moves around, obviously. And if you happen to have your pipe in the right location, you're going to get locationally, and we're going to get a good part of those, and at this point in time they've been away from our system. But we're still, we think, pretty well positioned, and hopefully we'll revert back towards the average, towards the mean in that regard.

Great. Thank you. That's very helpful.

That is our last question today. I'll turn the program back over to management.

We really do appreciate your interest in the Company. And we will keep working hard on this end. Thank you very much.

That concludes today's conference call. Thank you for your participation. Have a great day. You may now disconnect your lines.