Good day, ladies and gentlemen, and welcome to the OGE Energy Corp. Fourth Quarter Earnings Conference Call hosted by Todd Tidwell. My name Mamod and I am the event coordinator today. During the presentation your lines will remain on listen-only. (Operator Instructions) I would like to advise all parties that this conference is being recorded. And now, I would like to hand the call over to Todd Tidwell. Over to you sir.

Thank you and good morning, everyone, and welcome to OGE Energy Corp’s fourth quarter 2011 earnings call. I am Todd Tidwell, Director of Investor Relations, and with me today I have Pete Delaney, Chairman, President and CEO of OGE Energy Corp.; Sean Trauschke, Vice President and CFO of OGE Energy Corp.; and several other members of the management team to address any questions that you may have. In terms of the call today, we will first hear from Pete, followed by an explanation from Sean of fourth quarter and the year ending 2011 results. And finally, as always, we will answer your questions. Historically, we have provide earnings guidance for the current year on the fourth quarter call. However, due to the Oklahoma rate case we are going to wait until we receive the final commission order before releasing OGE’s consolidated 2012 guidance. But we will provide Enogex’s 2012 guidance. We expect the final Oklahoma rate orders sometime in March and we will provide consolidated guidance at that time. I would like to remind you that this conference is begin webcast and you may follow along on our website at oge.com. In addition, the conference call and the accompanying slides will be archived following the call on that same website. 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 that we cannot guarantee forward-looking financial results but this is our best estimate to date. In addition, there is a Regulation G reconciliation for ongoing 2010 earnings results in the appendix along with projected capital expenditure. The Enogex processing supplement for 2012 has also been posted on our website under the investor relations tab. I will now turn the call over to Pete Delaney for this opening comments. Pete?

Thank you, Todd. Good morning, everyone, and welcome to our call. For 2011, we reported earnings of $3.45 a share, compared to ongoing earnings per share of $3.10 in 2010. As you know much of the increase in earnings was driven by record summer heat and in service territory. It was the year of operational accomplishments and a year of record investment in our businesses amounting to $1.4 billion. In addition to managing through the record summer heat, we made great progress on key projects with the 228-megawatt Crossroads wind farm and the 200 million a day South Canadian processing facility, now complete and fully operational. Our electric transmission and smart grid project have advanced on schedule as well. And we are very pleased to have been recognized as the 2011 electric utility of the year by electric light and power, capping a year of many accomplishments. Enogex executed on its organic growth projects securing several large, long-term acreage dedications and completed the Cordillera midstream acquisition that positions us for continued growth around what is currently one of the most economic natural gas plays, the Granite Wash. Several of these initiatives undertaken this past year help position us to deliver our long-term earnings growth target, and I will spend some time talking about them. The brevity of my 2011 review today does not reflect a lack of accomplishment or appreciation for the excellent work by our members in 2011 or rather the forward-looking nature of this call. As always, the commodity cycle moves through its paces and the operating environment continually changes around us. Some favorable some not. Requiring us to shift our tactics but not our long-term strategy. I am confident in this management team’s ability to manage our well-positioned portfolio of businesses to continue to produce earnings growth…

Thank you, Pete, and good morning. For the fourth quarter, we reported net income of $36 million or $0.37 per share as compared to net income of $31 million or $0.31 per share in 2010. The contribution by business unit on a comparative basis for the fourth quarter is listed on the slide. And for the full year 2011, we reported net income of $343 million or $3.45 per share, as compared to ongoing net income of $307 million or $3.10 per share in 2010. Recall, the 2010 ongoing results excluded the onetime $0.11 per share charge for the Medicare Part D subsidy. At OG&E, net income for the fourth quarter was $20 million or $0.20 per share as compared to net income of $12 million or $0.13 per share in 2010. Some of the primary drivers are as follows. Fourth quarter gross margin came in stronger as we saw an increase of $18 million or 8%. The biggest drivers were transmission revenues and revenues associated with various investments. Each increased gross margin by approximately $6 million. You will recall that the vast majority of the transmission costs are not borne by our retail customers but paid by SPP customers. Customer growth and New Arkansas rates together added 4 million, while weather added another 3 million. As expected, operation and maintenance expenses came in on plan and flat to last year. You can see the other drivers on the slide as they are a result of additional assets being placed in the service and the long-term debt issuance we completed in May. Now looking at the full-year earnings details for the utility. OG&E reported net income for 2011, of $263 million or $2.65 per share, as compared to ongoing net income of $223 million or $2.25 per share in 2010.…

(Operator Instructions) Our first question comes from Ashar Khan of Visium. Over to your please.

Can I ask just ask you, on a previous presentation you had given us a rate base number of the utility business of about $4.9 billion, is that still a good number to use for 2012?

Yes, that’s a good number.

That’s a good number. And so whatever the ROE comes out, out of the order, can you earn that ROE or should we assume that there could be like a 25 bps to 40 bps lag between the allowed and the earned ROE for footfall?

You know, Ashar, obviously it depends on the ROE, for the first point. But you are very aware of how this works. We do have some regulatory lag inherent in our jurisdictions simply because when I look at our base CapEx it’s probably $100 million above what depreciation and amortization is.

Thank you for your question. The next question is from Anthony Crowdell of Jefferies. Over to you please. Anthony Crowdell - Jefferies & Company: I guess two quick questions. One is, could you guys provide an update in Oklahoma of the rate case. I mean just I guess what staff has recommended and also in Enogex, when I guess you guys are through two different regions, you are like in west where you have guys have liquids rich, and east, I guess where it’s drier. Could you talk about what the breakeven point or where it’s profitable at certain gas prices.

Okay. Maybe we will do the last one first and Keith you want to tackle...?

It’s Keith Mitchell, President of Enogex. Keith, if you would handle that.

Sure. That’s right. We do have coverage with our Western Oklahoma processing at our rich areas in Western Oklahoma and panhandle Texas, a leaner area, kind of in the central part. You know a lot of that depends on the producers drilling costs. We certainly know that at $3 and below they are not going to be drilling the leaner gas area. What we believe to be it’s not an exact price, but we think it’s a $3.50 range they would probably look to develop those reserves. On the rich areas, with the oil prices like they are, that’s really what's driving those economics and so we don’t anticipate the price begin down that low.

Yeah, this is Sean. So as far as an update on the Oklahoma rate case. We are awaiting the ALJ recommendation. We would expect that anytime now. As far as the recommendations, as Pete mentioned, the staff and the attorney general have recommended actually a rate decrease. The ROE was as low as 9.8%. If you recall, we requested 11% ROE. And there are lot of adjustments. All parties suggest in these types of filings. But ROE was probably the biggest item. Anthony Crowdell - Jefferies & Company: Okay. And I guess I just want to make sure I understand correctly. I guess going back to the, more of the Enogex. On the drier east region, you are looking more at like $3.50 gas, I guess, for the drillers for it to be profitable. And on the east, it seems like gas could be as low as a dollar, it’s just really driven by oil prices, is that accurate?

On the west side, we could have very low gas prices, that’s correct. And $3.50, again, it’s not exact number, I will tell you, part of that is the drilling costs. As these costs drill wells, if there is a decrease in rig activity and cost decrease, then that could change. Anthony Crowdell - Jefferies & Company: Now, I guess, you guys have a header system that runs between, I guess, your processing facilities. I mean, can I think of, even if volumes decrease in the drier region, through this header system any development that’s going on in the wetter western, you could pump that to the processing facilities in the east. Is that accurate or no, there are some limitations?

That’s accurate. We have several plants on the Western Oklahoma processing header. Capacity that would have been used for the leaner gas that is now delayed in development, we can take rich gas from the rich gas development areas and move to those plants. And that is exactly our plan.

Thank you for your question. The next question is from Greg Reiss of Catapult Capital Management. Over to you please.

Just have a quick question on Enogex. I saw that the guidance range was pretty wide this year. Just wanted to see what are some of the moving parts that get us from the lower end to the higher end?

Yeah, Greg, this is Sean. I believe the range is just like it was last year. I think we had roughly $0.15 range last year. And....

I thought it was $0.90 to $0.95 -- maybe I will just....

We certainly narrowed that down as we went through the course of the year. We did tighten it. You are exactly right.

Got you. So just wanted to get a flavor of some of the things that ought to happen to kind of get you to the lower versus the higher end.

Obviously, volumes would be a big driver there. If we saw some increased volume activity as Keith was mentioning, obviously if you saw some increasing commodity prices specifically in gas prices that encourage more drilling. That would currently, certainly, increase the earnings guidance range. Keith, would you add anything to that?

Well, I think that we are still evaluating producers capital programs and their drilling programs and so certainly if they were to get into a large capital drilling program in one of our areas that would effect that.

Got it. So volume is really the biggest drive here and kind of the midpoint of your range assumes that the volume assumption is laid out on....

Yeah. And, Greg, I think it’s important to note, the volumes are increasing. They are just not increasing at the rate we originally forecasted. But they are increasing. So I don’t want to lose that point.

And currently, is ethane in rejection or are you recovering ethane.

We are in ethane recovery.

There are a few plants that have access to Conway that we are looking at rejection.

Got it. And is there any way you would give us a breakout of how much of your volumes actually are able to get to Mt. Bellevue pricing versus Conway pricing. Is that something that’s been increasing?

We do expect that to increase, but Greg, we have not disclosed that.

Thank you for your question. The next question is from Brian Russo of Ladenburg Thalmann. Over to you please.

Could you give us a sense of like what percent of processing and gathering volumes are derived from the leaner gas regions versus the liquids rich regions in the Granite Wash? Just trying to get a sense of how much exposure you have on a volume basis to the shut-ins that we have seen.

If you look at all of our gathered volume, it’s about 20% would be from the lean areas. And of course as the rich gas growth than obviously that percentage of the rich gas comes up.

Right. And just to follow-on that comment. You have seen a slow-down in the leaner gas areas, but have you seen an acceleration yet in the liquids rich areas which could create maybe an upward bias to your volumes as we move through the year?

We have seen an increase in the activity in the rich areas. In fact some of the drilling rigs that were in the lean areas have just moved over into those areas. So we still see a lot of activity, both current and planned in the rich gas areas.

Okay. So that kind of dynamic is encompassed in your volume growth guidance?

That’s correct.

And, Brian, as I mentioned in my remarks, Apache made a $2.8 billion acquisition in that area of our Cordillera acquisition. And so that of course is a -- will be a big determinant of what Apache’s plans are, but we believe with that type of investment there, they clearly plan on drilling. So we are anxiously waiting for them to get in place and so things like that will have a big determinant on the volumes as well.

Given that the midpoint of the Enogex guidance which is around $0.87-$0.88, I just curious that the volume growth is quite robust even in a challenging nat gas environment. And I just want to understand more, some of the positive and negative year-over-year drivers of that $0.83. Is it just slightly lower commodity price assumptions and is it, it seems like a bigger driver is the conversion to the fixed fee contract?

Yeah, you know, Brian, I think the conversion, a full year of the conversion would be a big driver. I think the volume from our expectations originally was a driver for the fourth quarter, but maybe it would be helpful. Let me -- if I thought about some of the drivers for 2011, certainly volume growth, you talked about that. You talked about -- we brought South Canadian on at the end of fourth quarter, so we will have a full year of those processing efficiencies in our system. Certainly recall, that we brought Cox City plan back online in the third quarter, and we will have that in our fleet for the whole year. The other thing is we have mentioned that the insurance proceeds, we’re still working with our insurance providers on that. And I guess offsetting that certainly would be commodity prices. You know NGL prices are about 10% lower in ’12 then they were in ’11. And then you have got the fixed fee conversions. And then the last point I would mention is, and as you know, ArcLight made a contribution in the fourth quarter of 2011 and so their ownership interest of 18.7 is expected for the entire year of 2012.

Okay. Great. And just to clarify on the ArcLight ownership. Will they be making an equity contribution in 2012?

We don’t have any plans for them to do that this year.

Okay. And then just lastly on the utility side and the general rate case. I mean any thoughts on why it’s taken this long. I think original expectations were January, then February, now March. Just curious, because Oklahoma has a history of settling cases.

Brian, this is Pete. Procedurally, we went into the holidays there were more witnesses than originally planned. The proceeding went longer than originally planned, and so that contributed to a lot of it. We had a -- I guess January 24 was the technically 180 day period which we would have been able to or able to introduce rate subject to refund. We felt that given the fact that we needed a good decision, we needed a thorough decision. We put it on the record and let them know what we were going to waive and not to that this time. And the ALJ is very thorough. That the next timeline is getting that report out. And so it’s just taken longer sometimes. It has sometimes, we go through the -- past the 180 days. I think our recent history as you said has been settlement which has sped up that process. But given the position of the parties in this case, we were not able to settle it at this point of the process. So it’s working its way through and we hope to get the ALJ report in the next week or so. That will, I think after about two weeks after that, it will be presented to the commissioners for consideration.

Okay. And just lastly. Should we be concerned at all with the lost margin associated with the delay in the rate implementation or are you guys taking measures to kind of offset that maybe by managing your O&M etcetera?

There will be some obviously but we don’t think it’s material considering this is January and February and not high margin months.

Thank you for your question. Andy Bischof of Morningstar is next. Over to you please.

Most of my preparational questions have been answered. But maybe -- can you just shed any light how 2012 is kind of running up towards a weather normalized based, so far?

January was a lot milder than normal. But that’s about all we know.

And then kind of more of a strategic question. What do you think is the likelihood that a Mac rule could face a legal challenge? And what grounds you think someone would base that legal challenge on?

I am not sure I am the right one from a legal standpoint to talk about the strength of the legal cases on the Mac challenge. I know for us, as I in our comments -- my comments, I want to highlight that for us the major issue is the regional haze. And that’s the real, will drive over potentially for scrubbers over $1 billion of investment. Five year timeline is very challenging for us. And that’s the one is really where, primary concern and large impact on our customers. The other ones and Mac, we believe we have the ability how to comply although we may need some additional time for compliance.

Thank you for your question. Stephen Huang of Carlson Capital is next. Over to you please.

Just one quick question on your ’13 volume growth assumptions that you guys indicated. The processing portion of the 15% increase, can you help us understand what type of breakdown that is in the volumes that you guys have. Is it mostly fixed fee or POP or, how should we think about it?

It’s a mixture. You know it’s for the development of these rich gas areas. And we have some under POP some under POL, and some fixed fees. So it really is a mixture of that. And a lot of that depends on which producer and which contracts, where the drilling occurs.

But would the mix as a whole though be consistent with ‘ 12 or is it going to shift in a different direction?

No, I think it would be very similar, as far as the mix.

And then I just want to come back again to the -- on Enogex for ’12. When I look at it here, you have gross margins on your processing side going up by $50is million, I am going to guess gathering is going to go up by $10 million to $15 million. I am trying to get a better understanding as to why net income is kind of flattish relative to going up more. Is the marketing business taking on more losses, is that what the expectation is? Is that where the differential?

No, Stephen -- this is Sean -- no, we pointed out there as the business is growing we have more plant and service, we are obviously going to have higher depreciation expense. We are also constructing two 200 a day processing facilities, so we have more people, so O&M expenses going up. We will incur some additional debt albeit maybe on a short term basis. But there will be debt to finance some of this. We are seeing now lower commodity price environment. And then I have mentioned to Brian earlier, we have the fixed fee conversion which for full year of ’12 versus we had a half year of that in ’11. And then the last thing was the ownership interest. As we mentioned before, we will have a full year of the 18.7% interest that ArcLight versus what really was 13% interest for ten months of 2011.

Right. Okay. And then....

So I think your hypothesis is exactly right. Margins are growing, that’s what Pete and Keith were referring to. They are growing, it’s the items below that that are moving around. It’s the net to OGE that’s actually declining. If I thought about EBITDA, we are looking at $50 million-$60 million increase year-over-year on EBITDA.

Okay. And then on marketing though. Are you assuming kind of the similar to ’11, around $15 million of losses?

No.

Is that going to zero, or is it going higher?

No, it’s going to lower and -- yeah.

Okay. No, because other people have been divesting these businesses and because they continue to generate losses and I don’t know if this is a driver for you guys to maybe look to divest it.

Yeah. And Stephen just to put a little color on that business. We have some long-term, what I would consider legacy transportation contracts on there. That have demand fees about $8 million a year. And that’s what's going on there and just with his low gas price environment there’s no basis around that.

When do those roll off?

’14 and ’15, the lion’s share of those roll off.

So, you will get about $8 billion back in ’14 and ’15.

Yes.

Great. Thank you.

By the end of ’15 we will have $8 million of roll off. That’s correct.

Thank you for your question. Craig Shere of Tuohy Brothers is next. Over to you please.

Two quick questions. One given the growth specially with the two additional processing units in the wetter gas area at Enogex. Could you see the business being at a critical mass by, I don’t know, sometime late next year or into 2014, to possibly sponsoring an MLP IPO or monetize in some other way. And the second question surrounds the $3.50 plus price point for economic dry gas drilling in kind of the Middle Eastern Oklahoma. Is your impression that this is kind of ubiquitous funding, ubiquitous (back) crews, ubiquitous drilling rigs and so if adjust in the money, they will drill. Or given a lot of the companies in the industry having a little trouble getting their arms around their CapEx funding as it is. Is it really a competitive return environment not an absolute return environment.

For that last question I am going to ask Keith to share his thoughts on that, who reads the tea leaves, I guess, of producers behavior.

Okay, Pete. You know I think that certainly lot of producers have various inventories and portfolios of opportunities to drill. Those that have opportunities to drill oil rich plays they are certainly going to take an capital budget and capital program to work those. So to the extent they have a lot of those that will take away capital from some of these leaner areas. We see some that maybe don’t have as much of that opportunity, have more of a portfolio that’s still a lot of gas driven, then it’s really more a return where they want to spend that. So I think that, as far as rigs and crews or capital budgets, those that have choices then, yeah, I think it is pretty much ubiquitous about that. But I do think that a lot of it depends on the producer, what their cash flow dependency is on gas now, so that’s extra capital budget. But also what's their inventory of opportunity, do they have some oil in their portfolio that they could drill.

Yeah, Craig, so there we try to throw out a number like $3.50 but as Keith said it’s each individual producers has their own different fact situation that will drive that either higher or lower. And so you really need to look at who is driving the drilling in each area. Back to the first question, as Sean talked a little bit about that, when there was question around our margins. We continue to invest in Enogex and obviously we have talked about our capital budget as recognized by our growing O&M. We have increased our investment in people. We have expanded or leadership, brining on more resources in business development. We have expanded the senior leadership the President and Chief -- separate roles of the President with Keith and the Chief Operating Officer. So we are making substantial investments in the field as well. Originally, as you know, we were looking at very much higher projections or growth in 2012 and we made the hiring for that growth. Of course some of those tactical adjustments we will make in terms of our hiring were probably not nearly as aggressive down as they were. Given the change in our volume projections which still show growth but less than we expected. I think from a critical mass -- that we have critical mass. We have always -- our strategy is to continue to build sustainable business. Our moving toward fixed fee or bringing an ArcLight to increase our funding capability. And critical to our sustained growth are these large -- long-term, large acreage dedications. Like the Cordillera I would point to, which we believe as we see for numbers going forward, we think positions us well. So everything we are doing to grow our business today and invest in our business which we continue to do so. Also, I think makes, whether the NMLP a more viable opportunity as well. I think everything we are doing to grow value as its own today with us an ArcLight, will also contribute to a more robust MLP. So we still have that option ahead of us. And we continue to look to make Enogex stronger and a more sustainable growth story which, again, I am sure to even make it a better story for, should we at some point of time decide to the MLP market.

Thank you for your question. The last question is from James Dobson of Wunderlich Securities. Over to you please.

We have had a lot of questions on this volume issue. And I thought the easiest way to punctuate is and at least get my mind clear, the guidance you have provided on Enogex, if in fact we see the volume trends in these drier gas basins continuing, and I am referring to the trends you disclosed in the 8-K. If they continue through the balance of 2012, that is included at least as within that range of guidance you have provided for 2012.

Yes.

Perfect, that’s great. And then Sean, on the Cox City insurance proceeds. So is you are successful we would see another $12 million coming through $29 million net of the $17 received in ’11 coming through the Enogex income statement in 2012.

That would be true. Obviously, we are still in discussions with our providers, but that’s where we sit today. So if we receive the full recovery of our estimated cost there would be another 12.

Okay. Perfect. And then over to the utility, on the transmission projects you are talking about, Pete, for 2017, 2018. I noticed in the CapEx slide, we sort of got nothing in ’15 or ’16 for transmission and I assume projects that would be coming on then, would in fact need some capital. So understand it’s early days and we need the letters and the like but how would the $250 million, $300 million spread over that timeframe if in fact you get these letters.

Yeah. First, you are right we haven’t got the notice to construct. And generally we will disclose and put into our approved projects only. But 2018, I think CapEx may start in ’16, maybe late ’15, Sean, and then ramp. So that would start to work in there. But we don’t have, I don’t think, any breakdown on that, how that line’s out right now. But, Sean, do you have anything to add to that.

No. We will certainly add that to our schedule once we receive the NTC and we actually respond and accept those NTC. I guess, Jay, you are thinking about the same way Pete and I were thinking about it. It would kind of pick up right where the existing transmission projects we’re building today. Tail off and come to completion.

That’s great. And then on environmental -- I am sure you guys are thinking about best case and worst cases, all of us are. If we just sort of look at Sooner and Muskogee coal units, and then assume scrubber installation for regional haze, ACI and DSI from Mac, and low NOx burners. What amount of total CapEx are we thinking there?

So assuming four scrubbers and you’re probably looking at -- could be $1.5 billion of investment. Of course that’s going to be a difficult amount of investment to deploy operationally at one point in five years. It’s more than just spending money. You have operational plant -- as you know you have to take these plants offline to effect some of these changes and it’s going to be a real problem for us if we have to go that route. The trade-offs are we are -- on regional haze, again we are hopeful that we can get some relief from the legal side. And we do believe we have a strong case. Not just that it costs our customers a lot of money, we think that the regulations and the -- one of the condition is cost effectiveness. These numbers cost and the whole impact is not cost effective for BART. And we continue to stand by that position. So hopefully we can get some relief.

No, that’s great. And then last question, Sean, and I appreciate you don’t want to give guidance on the utility, but at the holding company, ongoing loss of about $0.09 in ’10. What would you expect for ’12?

Well, so that was in ’10. And so ’10 had a couple of different items in there. So ’10 with the marketing business was part of the holding company but in addition to that we also made some contribution to our foundation in 2010. So for the year of 2011, we were right on plan with about a $0.03 loss. And other than some cost for some corporate services and things like that and the holding company debt we have up there. I don’t see any changes in there.

Got you. So a loss of $0.03 would probably be a good starting point for ’12?

We gave you a guidance of $0.02 to $0.04 for 2011, and I don’t think the business is materially different in -- the holding company structure is any different in 2012.

Thank you. And with that I will hand it back to our presenters for a closing remark.

As always I would like to take the time to acknowledge our members for the dedication to keeping the company moving forward and I would like to thank you all for your continued interest in OGE Energy. Have a great day.

Thank you. Ladies and gentlemen your conference call now comes to an end. You may disconnect. Thank you very much.