OGE Energy Corp (OGE) 2011 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the OGE Energy Corp. fourth quarter earnings conference call hosted by Todd Tidwell. My name is Mahmoud and I am the event coordinator for today. During the presentation, your lines will remain on listen-only. (Operator Instructions) (Inaudible) all parties for this conference is being recorded. And now I would like to turn the call over to Todd Tidwell. Over to you, sir.

Thank you, and good morning, everyone, and welcome to OGE Energy Corporation's fourth quarter 2011 earnings call. I am Todd Tidwell, Director of Investor Relations. 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 provided 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' 2012 guidance. We expect the final Oklahoma rate order sometime in March and will provide consolidated guidance at that time. I would like to remind you that this conference is being webcast and you may follow along on our website at www.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 expenditures. 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 his opening comments. Pete?

Thank you, Todd. Good morning, everyone, and welcome to our call. For 2011, we reported earnings of $3.45 per share compared to ongoing earnings per share of $2.10 in 2010. As you know, much of the increase in earnings was driven by record summer heat in our service territory. It was a 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 a 228-megawatt Crossroads Wind Farm and the $200 million per day South Canadian processing facility, now complete and fully operational.

Our Electric Transmission and Smart Grid projects have advanced on schedule, as well. We are very pleased to have been recognized as the 2011 electric Utility of the Year by Electric Light & Power, capping a year of many accomplishments. Enogex executed on 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 helped position us to deliver our long-term earnings growth target. 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, but 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 and value for shareholders. At the utility, an important open item remains the rate case filed last summer. Hearings are complete and we are awaiting an ALJ recommendation which we hope will be available in the coming days.

As you know, we requested a rate increase of $73 million predicated on [a] plant investment and operating expenses to maintain the high reliability and service standards our customers currently enjoy. The Commission staff, attorney general's office, and others recommend a rate decrease. While the ALJ recommendation is not binding on the Oklahoma Commissioners, we believe it does influence their decision-making. An order is expected in March.

As you may know, we've had some changes at the Commission. We have new Commissioner, Patrice Douglas, appointed by the governor to replace Jeff Cloud, who resigned to pursue a career in private enterprise. This fall, both Commissioner Douglas and Commissioner Anthony will stand for reelection. As I mentioned at the outset, our SBP-approved transmission expansion continues. We have $700 million of such projects at various stages of construction in our five-year forecast, with two transmission lines to be completed this year. At the end of January, the SBP Board approved additional transmission projects.

We expect to receive notice to construct two lines within service dates of 2017 and 2018 with a cost of around $250 million to $300 million. Compliance with pending environmental regulation remains at the forefront of our future investment drivers for the utility. Along the pending regulations that could impact the utility, three regulations have the greatest potential impact. I believe you're all well versed in these regulations. Regional haze has the potential to require the largest investment and would have the greatest impact on our customers. In our case, the EPA has issued a federal implementation plan providing for a five-year compliance timeline, or 2017, that specifies scrubbers as BART, overriding the State of Oklahoma's plan which found low-sulfur coal to be BART.

One portion of the state implementation plan that the EPA agreed with is the installation of low NOx burners. There are currently judicial actions in progress around the regional haze issue. OGE and the State of Oklahoma are seeking an administrative stay request with the EPA. In addition, OGE and the State of Oklahoma have also announced that they intend to petition for review of this determination in the US Court of Appeals for the 10th Circuit. It's difficult to determine the timing and probability of success in these court cases, but we'll keep you updated as they unfold.

Second is the Casper rule which was granted a stay in December with a hearing on the merits scheduled in April. OGE is also seeking review by the court of Oklahoma's inclusion in Casper. While the courts do not specifically grant a stay for the supplemental stage including Oklahoma, the EPA has stated that the stay would encompass the supplemental states. If no changes are granted by the courts, OGE will have until May of 2013 to be in compliance. Our short-term compliance plans could include redispatch, low NOx burners, purchasing credits, purchasing power, or a combination of these.

You will recall that OGE has already agreed to install low NOx burners for regional haze in a state implementation plan although under a longer timeframe. We are doing operational planning regarding the best approach to NOx burner installation. The estimated cost of a low NOx burner is approximately $16 million per unit. Finally, Mac rules are slated to go into effect today, require compliance in three years with a possible one-year extension. Compliance for the Mac rules for OGE primarily relates to mercury and acid gases. We believe that activated carbon injection in the use of DSI on a limited basis will allow us to comply. However, the extra year may be required to complete testing and installation.

As I previously mentioned, we will keep you updated as these events unfold. 2012 will be a year when we will make some determinations on the environmental front. Our Smart Grid deployment, as it relates to installation smart meters, is in its third and final year. At this juncture, almost 600,000 meters are installed. Distribution automation investment continues through 2012, as well. We refer to the 2010 to 2012 period as our Phase 2 of our program, in which investment and operating expenses were covered under a regulatory writer but also guaranteed savings for the customers.

This year we have embarked on a most ambitious volunteer demand response program seeking to enroll almost 40,000 customers with a goal of shaving about 70 megawatts off the peak demand. We have experienced very positive customer feedback from our earlier pilots, which demonstrate our customers have the capacity to deliver these types of savings. Not only do we believe in the favorable economics of shifting peak load but also look to establish ways for our customers to mitigate the impact that environmental [extensions] will have on their monthly bill. During the year, we will be determining the scope of Phase 3 of our deployment which will be focused on expanding distribution automation, utilizing information, new work processes, and systems to be more efficient in providing reliable operations, the introduction of products and services, as well as the expansion of voluntary-based demand response programs.

Turning to Enogex. As we note in our recent 8-K, the steep drop in natural gas prices caused our 2011 volumes to grow less than we expected earlier in the year. We experienced 3% gathering volume growth and 3% processable volume growth in 2011. I'd like to note that our projections are for higher growth rates in volumes in 2012 despite the 40% drop in natural gas prices since November which has slowed our volume growth projections from the leaner gas areas. In 2012, despite these impacts, we are projecting gathering and processing volume growth of around 6% to 10% and at least 15%, respectively. [Weather], gross margin, EBITDA, or other measures, we would expect to report growth.

The development of our Western Oklahoma processing header system, the long-term acreage dedications in natural gas rich basins, our equity partnership with ArcLight and the balance sheet have positioned Enogex well to be successful in this low natural gas price environment. We are staying the course but that does not mean we will not make some tactical changes. In this environment, we will scale back on capital spending and operating expenses where appropriate. We do not believe the $2.50 gas world is here to stay but various forecasts indicate these prices may be with us a while.

As we know, markets work and we expect supply and demand dynamics will influence these price relationships longer term, but in the meanwhile, we are positioned to be able to grow the business. As part of our 2012 outlook, the economic backdrop in the heart of our Oklahoma service area remains strong. Oklahoma City and the state continue to perform well. Our unemployed rate in the metro area is about 5%, one of the lowest in the nation for large metro areas. The state unemployment is about 6%.

We continue to add customers, 7,000 to the system compared to last year. And industrial and oilfield sales continue to do well, driven primarily by the robust energy sector. On a normal weather basis, megawatt hour sales continue to grow at levels consistent with our historical average. We are delaying the release of our consolidated earnings guidance for 2012 until we have a final order from the Oklahoma Commission.

We have released Enogex guidance for 2012, and our portion of earnings is projected to be between $0.80 and $0.95 per share compared to earnings of $0.83 in 2011. Enogex will see the benefit of higher volumes and gathering and processing businesses, including a full year this new South Canadian plant, and a partial year of the Wheeler plant. Of course, the mid-year 2011 key pole to fixed fee conversion for a long-term acreage dedication reduces the processing margin. We are also anticipating the continued build out of the Cordillera acquisition made last year. One of our major customers, Apache, has made a significant investment in purchasing the drilling rights in that same area which we believe is a good sign that economics in the play support producer drilling. Now I'd like to turn the call over to Sean to review our financial performance in more detail. Sean?

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. 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 one-time $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 expense came in on plan and flat to last year. You can see the other drivers on the slide. They are as 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 ongoing net income of $223 million, or $2.25 per share in 2010.

Some of the primary drivers are as follows. Gross margin increased $88 million or 8%. I will provide details of gross margin on the next slide. Operation and maintenance expense increased by nearly $18 million. Almost $5 million of the increase came from riders with direct revenue offsets. The remaining amount of the increase was due to higher salaries and wages and contract professional services.

Depreciation and amortization expense increased $7 million due to additional plant placed into service such as the Crossroads Wind Farm. Likewise, taxes other than income increased due to the higher property taxes associated with these new assets. Overall, our operating expenses were approximately $10 million lower than our guidance due to lower costs associated with riders that have direct revenue offsets such as Smart Grid and demand side management. Net other income and expense created a $4 million positive variance, a result of higher equity AFUDC associated with the Crossroads Wind Farm. Interest expense increased $8 million, resulting from the issuance of long-term debt in June of 2010 and May of 2011, partially offset by the debt AFUDC also associated with Crossroads.

For the year, AFUDC debt was $10.4 million and AFUDC equity was $20 million. Turning to gross margin for the full year of 2011, the utility performed very well and there were several items that contributed to the increase in gross margin. As you know, in 2011 we experienced record heat in our service territory. To put the heat in perspective, cooling degree days were 45% above normal and 19% above 2010. This translated into higher margins and earnings. Compared to 2010 weather contributed $27 million to gross margin, and net of the decrease in the Guaranteed Flat Bill program, weather increased margins by $25 million.

Compared to normal, weather added $56 million of gross margin and $48 million net of the Guaranteed Flat Bill program. In summary, versus 2010, weather added $0.15 per share and versus normal weather $0.30 per share. Another major driver was the recovery of many investments we've made such as the Smart Grid program, Crossroads, and OU Spirit. Also contributing to higher gross margins were increased transmission revenues associated with our SPP projects. Customer growth on a weather normalized basis increased gross margin by $13 million. Although residential, commercial, and industrial growth was close to our historical 1% on a weather normalized basis, we saw growth of 3.7% in oilfield sales and 5.7% in public authority.

Turning to Enogex. For the fourth quarter Enogex earnings, OGE's portion of those earnings per share decreased from $0.22 in 2010 to $0.19 in 2011. On the third quarter call, we were projecting a fourth quarter increase in earnings at Enogex based on 12% volume growth in the gathering and processing businesses. These higher projected volumes did not occur due to a decline in drilling activity precipitated by the sudden and dramatic decline in natural gas prices. In response to the lower gas prices, producers pulled back their drilling rigs in the leaner gas areas, lowering gathering and processing volumes.

Fortunately, we did not see the lower growth rates in the liquids-rich areas of the Granite Wash which has remained economic for producers even in this low price environment. Even though Enogex' volume growth slowed, it nonetheless still grew quarter-over-quarter, and, in fact, gross margins increased by $2 million. Total gathering volumes did increase over 1% and processing inlet volumes grew nearly 4%. Gross margins for the gathering and processing businesses were $36 million and $41 million compared to $29 million and $44 million in 2010, respectively. The increase in gathering was in part due to higher volumes, and the decline in the processing business was primarily due to lower key pole margins resulting from the fixed fee conversion of a major customer in July of 2011.

The transportation and storage margins were basically flat contributing a combined gross margin of $37 million in both 2011 and 2010. You can see the other drivers for the quarter on the slide, including increased ownership of Enogex ArcLight during the fourth quarter. Looking at the full year, Enogex earnings per share to OGE decreased to $0.83 in 2011 compared to ongoing earnings of $0.94 per share in 2010. Operating income expenses and the increased ownership percentage by our equity partner outpaced our growth in gross margins. Let's take a look at some of the key drivers.

Gross margin increased by $18 million or 4%. I will discuss those drivers in a moment. Operation and maintenance expenses increased by $17 million in 2011, almost entirely as a result of system expansion. The increase included higher employee costs related to new hires and increased contract and professional services. Depreciation and amortization expense increased almost $8 million due to higher levels of depreciable plant placed into service. Operating expenses came in on plan with the exception of the Cox City insurance proceeds.

To date, we have received $17 million and the cost of replacement we estimated at $29 million. We are still working with our insurance providers to resolve our claim and final resolution should occur this year. Interest expense was nearly $8 million lower compared to 2010 due to an increase in capitalized interest resulting from higher construction levels, and the replacement of long-term debt in January of 2010 at a lower interest rate. Net income at Enogex grew year-over-year, but because of the contribution from ArcLight late in the year, net income to OGE declined.

Turning to gross margin for 2011. For the year, nearly all of the increase in Enogex' gross margin came in the gathering and processing businesses, driven by higher commodity prices, increased condensate recoveries, and higher gathering volumes. Although Enogex' processing plants saw a decrease in inlet volumes processable volumes,, which include condensate, actually increased 3% over 2010. Gathering volumes grew 3%, and by the end of 2011, Enogex was gathering a record 1.36 trillion BTUs per day.

As I mentioned earlier, condensate was also a major driver in the higher gross margins and contributed $41 million to gross margin, which was $11 million over 2010. Partially offsetting Enogex' higher gross margin was the processing contract conversion of a major customer from key pole to fixed fee. While the terms are lower than current key pole spreads, Enogex secured additional long-term acreage dedication under this contract. Higher commodity prices also fueled Enogex margins, as weighted average prices for NGLs increased from $0.96 per gallon in 2010 to $1.16 per gallon in 2011. Plant efficiencies were also important to processing margins in 2011 in the form of higher recoveries, and will be more so in 2012 as the new South Canadian plant was placed into service in the fourth quarter of 2011.

Before turning to your questions, I would like to discuss Enogex' earnings guidance for 2012. As Todd mentioned, we will provide consolidated and utility guidance once we have a final rate order in Oklahoma. We are projecting OGE's portion of Enogex to be between $0.80 and $0.95 per share compared to the $0.83 per share in 2011. You can see our assumptions on the slide. Enogex' gross margin is expected to increase between $60 million and $75 million compared to 2011. The primary factors driving the projected increase are higher volumes in the gathering and processing area.

The 2012 gathering volume increase is projected to be 6% to 10%, and 15% for the processing business. Looking forward to 2013, volume growth is projected to be 10% to 15% for gathering and 15% for processing, as we look forward to the new McClure plant online in late 2013. New system expansions in Western Oklahoma and the Texas Panhandle are driving this growth. The $200 million per day South Canadian plant came online in the fourth quarter of 2011, and the $200 million a day Wheeler, Texas facility is projected to be fully operational in the third quarter of this year.

We did mention in our 8-K issued in January that volume growth is slowing in our leaner gas regions due to low gas prices. That is still occurring and our growth projections for 2012 would have been greater if gas prices remained higher. In response to the slowdown in drilling activity, our capital expenditures have been reduced by $165 million in 2012 associated with gathering and compression in these lean gas areas. However, when gas prices rebound and volumes increase, we will invest the capital. I want to reiterate that although capital expenditures have been reduced, we still forecast investing $300 million at Enogex in 2012 and have several other projects currently under review.

Though gross margin is growing, so are our operating expenses due to system expansion. Depreciation has the biggest operating expense impact, expected to increase approximately $22 million in 2012. O&M is forecasted to increase $11 million, and then finally, property taxes will also increase due to additional assets being placed into service. Interest expense is projected to climb approximately $9 million at the midpoint due to expansion financing. We are not projecting any changes to ownership percentages during 2012.

In summary, I want to emphasize that although some activity is slowing, Enogex' footprint is well-positioned for volume growth in these rich gas regions, and we have the financial strength and flexibly to continue growing volumes and earnings. So thank you for your support. We will now open up for your questions.

(Operator Instructions) The first question is from Ashar Khan of Visium Asset Management. Over to you, please.

Good morning, Sean. Good results. Can I just ask you, on a previous presentation, you had given us a rate base number for 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 (inaudible)?

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.

Okay. Okay. Thank you so much.

Thanks, Ashar. See you.

Thank you for your question. The next question is from Anthony Crowdell of Jefferies. Over to you, please.

Hey, good morning. I guess two quick questions. One is, could you guys provide an update in Oklahoma of the rate case? Just I guess, what staff has recommended? And also, in Enogex when, I guess, you guys are approved two different regions, like in a West -- where you guys have liquids-rich and East where, I guess, it is drier, can you talk about what the break-even point or where it's profitable at certain gas prices?

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

This is Keith Mitchell, President of Enogex. Keith, if you would handle that.

Sure. And that's right, we do have coverage with our Western Oklahoma processing header, rich areas in Western Oklahoma and the Panhandle of Texas. And a leaner area, kind of in the central part. 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 at the $3.50 range they would probably look to develop those reserves. On the rich areas with the oil prices like they are, that is really what is driving those economics. We don't anticipate the price being down that low.

Anthony, this is Sean. As far as an update on the Oklahoma rate case, we are awaiting the ALJ recommendation. We would expect that any time now. As far as the recommendations, as Pete mentioned, the staff and the Attorney General had recommended actually a rate decrease. The ROE was as low as 9.8%. As you recall, we requested an 11% ROE. There are a lot of adjustments, all parties suggest in these types of filings. But ROE was probably the biggest item.

Okay. I guess I just want to make sure I heard correctly. I guess going back to more the Enogex. On the drier East region, you are looking more like you need $3.50 gas, I guess, for the drillers for it to be, I guess, profitable. On the East, it seemed like gas could be as low as a dollar, just really driven by oil prices. Is that accurate?

On the West side, you can have very low gas prices. That's correct. $3.50, again, that's not an exact number. I will tell you, part of that is the drilling costs. These costs to drill wells, if there is a decrease in rig activity and the cost decrease, that could change.

I guess you guys have a header system that runs between all your processing facilities. Can I think of -- even if a volume decrease in the drier regions through this header system, any development that's going on in the wetter Western region, you could pump that to the processing facilities in the East. Is that accurate or there are some limitations?

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

Great. I will jump back into queue.

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

Hey, guys. Congratulations on a solid 2011. Just have a quick question on Enogex. Saw that the guidance range was pretty wide this year. I just wanted to see what are some of the moving parts that get us from the lower end to the higher end?

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

I thought it was $0.90 to $0.95. Maybe I just --

We certainly narrowed it down as we went through the course of the year. We did tighten it, you're exactly right.

Got you. So I just wanted to get a flavor of some of the things that happened 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 increased -- increase in commodity prices, specifically in gas prices, that encouraged more drilling that would certainly increase the earnings guidance range. Keith, would you add anything to that?

I think that's it. 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 affect that.

Got it. So volume is really the biggest driver here. And kind of the midpoint of your range assumes that -- the volume assumptions laid out on --

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. I don't want to lose that point.

And currently, is ethane in rejection or are you guys 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. Is there any way you could give us a breakout of how much of your volumes actually are able to get to [Mont Bellevue] pricing versus Conway pricing? Is that something that has been increasing?

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

Got you. Okay, guys, thanks very much.

Thanks, Greg.

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

Hi, good morning.

Hey, good morning, Brian.

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've seen.

If you look at all of our gathered volume, it's about 20% would be from the leaner areas. Of course, as the rich gas grows, then, obviously, that percentage of the rich gas comes up.

Right. And just to follow on that comment, you have seen a slowdown 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 and 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. That, of course, will be a big determinant of what Apache's plans are. We believe with that type of investment, they clearly plan on drilling. So we are anxiously waiting for them to get in place. Things like that will have will have a big determinant on the volumes, as well.

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

Yes, 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 -- 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 the fourth quarter, so we will have a full year of those processing efficiencies in our system. Certainly, recall that we brought the Cox City plant 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 are still working with our insurance providers on that. I guess offsetting that, certainly, would be commodity prices. NGL prices are about 10% lower in '12 than they were in '11. Then you've got the fixed fee conversions. The last point I would mention is, 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. Any thoughts on why it has taken this long? I think original expectations were January, then February, and 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 contributes to a lot of it. We had, I guess, January 24th was technically the 180-day period, of which we would have been able to, or are able to introduce rates 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 that we were going to waive and not do that this time.

The ALJ is very thorough. That's the next timeline is getting that report out. So it has just taken longer sometimes. It has, sometimes we go through the path of 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. We hope to get the ALJ report in the next week or so. That will, I think, after about, two weeks after it will be presented to the Commissioners for consideration.

Okay. Just lastly, should we be concerned at all with the loss 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, et cetera?

Yes. We don't think -- there'll be some, obviously, but we don't think it's material considering this is, January and February are not high margin months.

Great. Thank you very much.

Thanks, Brian.

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

Hi, good morning. Most of my operational questions have been answered. But maybe, can you shed any light on how 2012 is kind of running up towards a weather normalized base so far?

January was a lot milder than normal, but that is about all we know.

Okay. 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 do you think someone would base that legal challenge on?

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

Okay. Thank you very much.

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

Hi. Good morning, guys. Just a quick question on your '13 volume growth assumptions that you guys indicated. The processing portion, the 15% increase, can you help us understand what type of breakdown that is in the volume, so you guys have? Is it mostly fixed fee or POP? How should we think of that?

It's a mixture. It's further development of these rich gas areas. We have some under POP, some under POL, and some fixed fee. It really is a mixture of that. A lot of that depends on which producer and which contract, 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.

Okay. And I just want to come back to you again on Enogex for '12. When I look at it here, you have gross margins on your processing side going up by [$50-ish] million. I'm going to guess gathering is going to go up by $10 million to $15 million. I'm 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. We pointed out there about as the business is growing we have more plant in service. We're, obviously, going to have higher depreciation expense. We are also constructing two $200 million a day processing facilities, so we have more people, so O&M expense is 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 a lower commodity price environment. And then I 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 has versus what really was 13% interest for 10 months of 2011.

Right, okay.

So I think your hypothesis is exactly right. Margins are growing. That is what Pete and Keith were referring to. They are growing. It's the line 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 a $50 million, $60 million increase year-over-year in EBITDA.

Okay. And then on marketing, though, are you guys assuming kind of similar to '11, around $15 million of losses?

No.

Is that going to zero or is it going higher?

No, it's going lower.

Oh, okay.

Yes.

No, because other people have been divesting these businesses because they continue to generate losses, and I didn't know this was a driver for you guys to maybe look to divest it?

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

When do those roll off?

The -- '14 and '15, the lion's share of those roll off.

So you'll get about $8 million back in '14 and '15?

Yes.

Great. Thank you.

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

Okay, great. Thank you.

Okay. Thanks, Stephen.

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

Hi. Two quick questions. One, given the growth, especially with the two additional processing units in the wetter gas area at Enogex, could you see the business being in a critical mass by, I don't know, sometime late next year or into 2014 to possibly sponsor an MLP IPO or monetize in some other way? And the question surrounds this $3.50-plus price point for economic dry gas drilling, kind of the middle Eastern Oklahoma. Is your impression that this is kind of ubiquitous funding, ubiquitous [fat] crews, ubiquitous drilling rigs? If you are just 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?

Well, for that last question I'm 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 a 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 any capital budget and capital program toward 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 is still a lot of gas driven. Then it's really more of 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, yes, 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 affects their capital budget. But also what's their inventory of opportunity. Do they have some oil in their portfolio that they could drill?

Critical there is we try to throw out a number like $3.50, but as Keith says, each individual producer has their own different fact situation that will drive that either higher or lower. So you really need to look at who is driving the drilling in each area. Back to the first question, and Sean talked a little bit about that when there were questions around our margins, we continue to invest in Enogex. Obviously, we've talked about our capital budget. As recognized by our growing O&M, we have increased our investment in people.

We have a new -- we have expanded our leadership, bringing on more resources in business development. We have expanded the senior leadership with the President and Chief, separate roles, of Keith and a Chief Operating Officer. So we are making substantial investments in the field, as well. Originally, as you know, we were looking at much higher projections of 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 plans are not nearly as aggressive now 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, our bringing in ArcLight to increase our funding capability. And critical to our sustained growth are these large long-term acreage dedications like the Cordillera acquisition I would point to, which we believe, as you see from our 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, an MLP a more viable opportunity, as well. I think everything we are doing to grow value as it's owned today with us and 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, should even make it a better story for -- should be at some point in time decide to go to the MLP market.

Great. Thank you.

The last question from James Dobson of Wunderlich Securities. Over to you, please.

Hey, good morning, Sean. Good morning, Pete.

Good morning.

Good morning.

We've had a lot of questions on this volume issue. And I thought the easiest way to punctuate it, 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'm 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've provided for 2012?

Yes.

Perfect. That's great. And then, Sean, on the Cox City insurance proceeds, so if you are successful, we'd see another $12 million coming through, $29 million net of the $17 million 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 costs, there would be another $12 million.

Okay, perfect. And then over to the utility. On the transmission projects you were talking about, Pete, for 2017/2018, I noticed in the CapEx slide we got sort of 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 you 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?

First, you're right. We haven't gotten a notice to construct. Generally, we will disclose and put in there our approved projects only, but for 2018, I think CapEx may start in '16, maybe late '15, Sean?

That's right.

And then it would start to work in there. We don't have, I don't think, any breakdown on how that lines out right now. Sean, do you have anything to add to that?

No, we will certainly add that to our schedule once we receive the NTCs and we actually respond and accept those NTCs. I guess, [Jay,] you are thinking about the same way Pete and I are thinking about it, kind of it would be -- it will kind of pick up right where the existing transmissions projects we're building today tail off and come to completion.

That's great. And then on environmental, I'm 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 or 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?

Assuming for scrubbers, you are probably looking at $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 off line to effect some of these changes. It's going to be a real problem for us if we have to go that route. The trade-offs are we're -- on regional haze, again, we are hopeful that we can get some relief from the legal side. We do believe we have a strong case.

Not just that it's costing our customers a lot of money. We think that the regulations -- if one of the conditions is cost effectiveness these numbers, the cost and the O&M factor is not cost effective for BART. We continue to stand by that position. Hopefully, we can get some relief.

That's great. And then last question, Sean. 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 different items in there. So '10, we had the marketing business was part of the holding company. But in addition to that, we also made some contributions to our foundation in 2010. So for the year of 2011, we were right on plan with about a $0.03 loss. Other than some costs for corporate services and things like that and the holding company debt we have up there, I don't see any changes in that.

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

Yes, we gave you guidance of $0.02 to $0.04 for 2011. I don't think the business is materially different, the holding company structures are any different in 2012.

Hey, that's great. Congrats on the results for '11. Thanks, [Jay.] Thanks for your time.

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

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

Thank you. Ladies and gentlemen, your conference call has now ended. You may disconnect. Thank you.