CenterPoint Energy, Inc. (CNP) Q4 2010 Earnings Report, Transcript and Summary

Good morning, and welcome to CenterPoint Energy's Fourth Quarter and Full Year 2010 Earnings Conference Call with senior management. [Operator Instructions] I will now turn the call over to Ms. Marianne Paulsen, Director of Investor Relations. Ms. Paulsen?

Thank you very much, Tina. Good morning, everyone. This is Marianne Paulsen, Director of Investor Relations for CenterPoint Energy. I'd like to welcome you to our fourth quarter and full year 2010 earnings conference call. Thank you for joining us today. David McClanahan, President and CEO; and Gary Whitlock, Executive Vice President and Chief Financial Officer, will discuss our fourth quarter and full year 2010 results and will also provide highlights on other key activities. In addition to Mr. McClanahan and Mr. Whitlock, we have other members of management with us who may assist in answering questions following their prepared remarks. Our earnings press release and Form 10-K filed earlier today are posted on our website, which is www.centerpointenergy.com, under the Investors Section. This quarter, we have created supplemental materials, which are also posted under the Investors Section of our website. These materials are for informational purposes, and we will not be referring to them during prepared remarks. I would like to remind you that any projections or forward-looking statements made during this call are subject to the cautionary statements on forward-looking information in the company's filings with the SEC. Before Mr. McClanahan begins, I would like to mention that a replay of this call will be available until 6 p.m. Central Time through Tuesday, March 8, 2011. To access the replay, please call 1-800-642-1687 or (706)645-9291 and enter the conference ID number 35640383. You can also listen to an online replay of the call through the website that I just mentioned. We will archive the call on CenterPoint Energy's website for at least one year. And with that, I will now turn the call over to David McClanahan.

Thank you, Marianne. Good morning, ladies and gentlemen. Thank you for joining us today, and thank you for your interest in CenterPoint Energy. This morning, I will talk about some significant developments that occurred during the fourth quarter and provide details around certain business operations that I believe are of interest to many of you. I will also briefly describe our overall financial results for the quarter, followed by a more comprehensive discussion of our annual results of each of our businesses and our expectations for 2011. Let me begin with our recent Houston electric rate case. The Texas PUC [Public Utility Commission] announced its decision in early February, but has yet to render a written order, so our description is somewhat limited. Although the cash flow impact from this case should be minimal, we anticipate that the decision will have an estimated $25 million to $30 million annualized negative impact on Houston Electric's operating income. We are obviously disappointed in this result. Let me give you a few of the details of the decision, as we understand them today. Rates will be based on a capital structure reflecting 45% equity, up from the current level of 40%. The return on equity was set at 10%. This is an 0.125% to 0.25% lower than the rates most recently authorized for other Texas utilities and reduced the positive effects of the higher equity ratio. We are very disappointed in this aspect of the PUC's decision. The commission reduced Houston Electric's revenue requirement by about $10 million to reflect tax savings in other CenterPoint businesses. This is commonly referred to as the consolidated tax savings adjustment. While it had been -- previously been the practice of the commission to make this type of an adjustment, it did not do so in the recent Oncor case, and we were hopeful the commission would follow the precedent set in that case. The commission had a lengthy discussion about the calculation and indicated that it would initiate a workshop to consider whether this issue should be the subject of a rule making. Rate base was reduced to reflect the PUC's assumptions regarding the company's liability for uncertain tax positions. This change in rate base resulted in a revenue requirement reduction of approximately $17 million. However, a tractor was established to capture the revenue requirement difference between the assumed and actual tax outcome. I might also add that our AMS investment of approximately $121 million was moved from a surcharge into base rates. This change has no effect on operating income since we were already recognizing a return on this investment under the smart meter surcharge. Now let me update you on our advanced technology deployments. The implementation of an advanced metering system in our Houston Electric service territory is progressing well. We are currently installing over 80,000 smart meters per month, and we celebrated the installation of our 1 millionth smart meter last week. We have invested approximately $240 million through December, excluding $100 million we have requested under our DOE grant. Houston Electric will use $50 million of the DOE grant to support our Intelligent Grid Initiative, which is also progressing well. Earlier this year, we began installing remote electronic transmitters on the 1.2 million natural gas meters in and around our Houston service territory. These devices will initially allow us to automate natural gas meter readings and in the future, will enable other functionality. We expect to invest approximately $85 million on this project, which should be completed within 36 months. Now let me turn to our Field Services business. This has been our fastest growing business segment, and we expect significant growth to continue for the next few years. As you recall, we are building two major systems to gather and create production for Shell and in Encana in the Haynesville Shale. The first 700 million cubic foot per day phase of the Magnolia System is complete except for well connects. Construction of the Olympia System and the 200 million cubic feet per day expansion of the Magnolia System are progressing on schedule and on budget. By the end of the first quarter of this year, we expect to have both of these projects substantially completed except for pipeline interconnections scheduled for later this year and well connects. This will bring the total capacity of these two systems to 1.5 Bcf per day. The Shell and Encana contracts provide for annual throughput guarantees upon completion of various milestones that have been or will be achieved throughout 2011. The initial phase of the Magnolia System is flowing at close to contracted volume capacity. We expect throughput on the Olympia System and the Magnolia expansion to increase over the course of the year and be at system capacity by early 2012. Once we complete construction of the current phases of the Magnolia and Olympia Systems, our total investment will be approximately $800 million. Shell and Encana have expansion rights for another 1.3 billion cubic feet per day of capacity, which would cost up to an additional $450 million to construct. For planning purposes, we are assuming that about half the expansion rights will be executed over the next five years. I would also add that we continued to expect mid-teen unlevered return from these investments once production is ramped up to near the contracted capacity. Now let me review the company's overall operating results for the fourth quarter. This morning, we reported net income of $124 million for the fourth quarter or $0.29 per diluted share. This compares to net income of $105 million or $0.27 per diluted share for the same period of 2009. Operating income for the fourth quarter of 2010 was $302 million compared to $299 million for the same period of 2009. Houston Electric's operating income declined by $5 million primarily related to increased expenses for our reliability programs, the timing of energy efficiency expenditures and unplanned environmental remediation costs. Our Natural Gas Distribution segment reported a $13 million decline in operating income. This decline was driven by lower system throughput due to milder weather, higher expenses and improved rate designs that shifted base revenues into the second and third quarters. Operating income for our Interstate Pipelines segment was essentially the same as 2009 as higher revenues, primarily from firm contracts associated with Phase 4 of the Carthage to Perryville pipeline, were offset by lower revenues from ancillary services. Increased operating income of $35 million in our Field Services segment included a $21 million gain related to the sale of a small nonstrategic gathering system in the Texas panhandle. The additional increase in operating income was primarily related to new facilities in the Haynesville Shale constructed since the previous year. Operating income at our Energy Services business declined $21 million due to increased mark-to-market losses on derivative contracts and a contraction in seasonal price differentials. Finally, net income for the quarter benefited from a $24 million reduction in deferred tax expense due to the conversion of certain subsidiaries of cert to LLCs. Now let me turn to our full year 2010 performance. Our reported net income for 2010 was $442 million, a $1.07 per diluted share, compared to $372 million, a $1.01 per diluted share for 2009. Operating income was $1.25 billion in 2010, an increase of more than $125 million or 11% from 2009. Houston Electric reported operating income of $427 million for 2010 compared to $414 million for 2009. This increase was primarily the result of customer growth, increased usage in part due to favorable weather and increased earnings associated with our smart meter investment. Partially offsetting these increases was a $21 million reduction in revenues associated with the credit to customers' bills reflecting the benefit of deferred taxes associated with Hurricane Ike storm restoration cost. We also experienced increased operating expenses due primarily to system reliability programs, increased employee-related expenses and environmental remediation cost. It is worth noting that even in a relatively weak economy, we added nearly 28,000 customers in 2010, a growth rate of about 1.3%. As we look to 2011, we expect customer growth will be at or a little better than what we experienced in 2010, which has helped to offset the estimated $20 million partial year impact from the rate case decision and expected expense increases. The bottom line is I expect Houston Electric to be down some from 2010, absent increased usage from weather or other developments. 2010 was an exceptional year for our Natural Gas Distribution business, which reported operating income of $231 million compared to $204 million in 2009. Operating income benefited from rate changes, lower pension and benefit costs and lower bad debt expense. Partially offsetting these benefits were higher operating expenses, including an increase in depreciation. Over the last several years, this business has worked diligently on reducing customer delinquencies and bad debt expense and is also focused on obtaining necessary rate increases and improving rate design. I'm pleased to say that we continued to see the benefits of those efforts in 2010. As we move into 2011, we believe this unit is poised for another good year. We expect to finalize one small rate case this year, which together with a number of annual rate adjustments, should provide some revenue uplift. Our focus will also continue to be on operational improvements and expense control. Our Competitive Natural Gas Sales and Services business reported operating income of $16 million for 2010 compared to $21 million for 2009. Excluding mark-to-market gains and losses and natural gas inventory write-downs, our Energy Services business would have reported operating income of $18 million compared to $50 million for 2009. This decline was principally the result of reduced wholesale opportunities because of significantly tighter locational price differentials and an absence of seasonal storage spreads. Last year, our retail sales were stable and we added more than 1,000 customers to our total customer base. We expect our retail business to see improvement this year. We believe we have stabilized our wholesale business and expect some marginal improvement. Absent the effects of mark-to-market impacts and inventory adjustments, we expect 2011 to be a better year than 2010 for Energy Services. Now let me turn to our midstream businesses, Interstate Pipelines and Field Services. Our Interstate Pipelines recorded operating income of $270 million for 2010 compared to $256 million for 2009. Our core business continues to perform well, building on its strong fee-based foundation with increased margins from our Carthage to Perryville pipeline as well as increased revenues related to several new firm contracts to serve power generation facilities on our system. Our fee-based margin grew by 4%, but this growth was partially offset by reduced revenues from ancillary services and off-system sales. Our equity income from SESH, our joint venture with Spectra, was $19 million. This compares to equity income of $7 million in 2009, which was reduced by a $16 million noncash charge due to the discontinued use of regulatory accounting. As I mentioned last quarter, we have a backhaul agreement that terminates in the middle of 2011, which will reduce revenues and will also impact the fuel efficiency of Line CP. Offsetting this decline is the addition of about 100 million cubic feet of Line CP capacity available on a forward-haul basis. The overall impact is expected to be about $20 million. To date, we have not secured sufficient new contract revenues to fully offset this impact. We also have some expense pressures stemming from EPA regulations. So without the benefit of higher ancillary revenues this year, which would be driven primarily by change in market conditions, it will be difficult for our Pipeline business to match the operating income we earned in 2010. Our Field Services unit reported operating income of $151 million for 2010 compared to $94 million for 2009. Operating income for 2010 included the $21 million gain associated with the small gathering system we sold in the fourth quarter. The remaining $36 million increase in operating income was primarily the result of the new long-term agreements with subsidiaries of Shell and Encana. Gathering volumes were up significantly in 2010 compared to 2009. Average gathering volumes in 2010 were 1.8 Bcf per day, an increase of more than 50% from 2009. For the month of December 2010, gathering volumes averaged a little over 2 Bcf per day. As we reported last quarter, gathering volumes from our traditional basins have leveled off. Fourth quarter volumes were flat to the fourth quarter of 2009. For the year, traditional volumes were down about 8%. In addition to operating income, we also recorded equity income of $10 million from our jointly owned Waskom facilities compared to $8 million the previous year. As we look to 2011, we expect Haynesville production to increase steadily over the year, and we also expect some increased volumes in the Fayetteville and Woodford shales. We are assuming flat volumes from our traditional fields. Our fee-based revenues will increase as we achieve the milestones for the Olympia System and the Magnolia expansion. Overall, we expect Field Services to achieve significant increases in operating income. Taking into account the performance of all of our business units, I believe that our company performed very well in 2010. I would like to acknowledge the dedication of our employees as they work hard not only to improve the efficiency and effectiveness of our operations, but to strengthen business relationships and capture new business opportunities. We also continue to strengthen our balance sheet, improving our overall financial flexibility and strength. As a result of these collective efforts, I believe the company is well positioned to capture opportunities this year and beyond. Looking to the future, we expect to benefit from our balanced portfolio of Electric and Natural Gas businesses. Near term, Field Services will continue to enjoy the benefits of capital investment opportunities in the shale plays. Longer term, growing service territory should provide good investment opportunities for our regulated businesses. In his remarks, Gary will provide our overall earnings guidance for 2011. In closing, I'd like to remind you of the $0.1975 per share quarterly dividend declared by our Board of Directors on January 20. This marks the sixth consecutive year that we have raised our dividend. We believe our dividend actions continue to demonstrate a strong commitment to our shareholders and the confidence the Board of Directors has in our ability to deliver sustainable earnings and cash flow. With that, I will now turn the call over to Gary.

Thank you, David, and good morning to everyone. Today, I'd like to discuss a few items with you. First, we are very pleased with the steps we have taken during the year to strengthen our balance sheet and to enhance our credit metrics to ensure that we maintain the financial flexibility to effectively execute our business plan. Excluding securitization debt, we reduced our corporate consolidated debt from $7 billion to $6.7 billion at year-end 2010 while funding a capital program of $1.46 billion. Our debt to total capitalization improved from approximately 73% to 67%. In 2010, we raised $416 million of additional equity with the issuance of 33 million shares of common stock. Of this amount, $315 million was associated with an underwritten equity offering executed in conjunction with the announcement of our Field Services business signing excellent long-term agreements with Shell and Encana. The remaining shares were issued as part of our savings plan, dividend reinvestment plan and various benefit programs. At this time, based on the significant steps we have taken the past two years to strengthen our balance sheet and the significant cash we generate from our operations, we have suspended the use of original issue shares for the savings plan and dividend reinvestment plan. Instead, shares will be purchased on the open market to fund these plans. Now let me discuss our capital spending plan for 2011 in total and by segment. We estimate our 2011 CapEx to be $1.34 billion, a decrease of $125 million from 2010. About 77% or a little more than $1 billion of CapEx this year will be spent by our regulated businesses compared to 52% in 2010. Let me give you a breakdown by business. We expect to spend $605 million in our Electric business, an increase of $142 million from 2009, primarily related to our advanced metering and intelligent grid deployments. We expect to spend $263 million in our Natural Gas Distribution business, reflecting an increase of $61 million from 2010 primarily for the remote electronic transmitters that David referred to in his comments, as well as increased spending on improvements related to safety and system reliability. Our pipeline's capital budget is $157 million, which is above the 2010 level of $102 million due primarily to increased maintenance capital and additional spending to ensure compliance with certain EPA rules. Our capital budget for Field Services is $262 million, which is a reduction of $406 million from 2010 as we have completed a significant portion of the spending on the build out of the Shell and Encana projects. This estimate does not include any new capital, which may be required if we were to have a new significant opportunity either in or outside of our current footprint. Along these lines, we have been asked about our financing strategy for any new significant investment in our midstream businesses. Specifically, whether we are considering the formation of an MLP as a financing option. We think the formation of an MLP could be an efficient way to finance new growth as compared to selling common equity. However, our focus has been and will continue to be on executing the optimum financing plan for the company based on our particular circumstances. For example, before forming an MLP, we would need to be confident that there would not be a material negative impact to the credit ratings of the parent company or our utilities subsidiaries. Now let me discuss our current financing activities and financing plan. Thus far in 2011, we have taken two important steps to refinance debt maturities at CERC. First, in early January, CERC should $250 million of 10-year 4.5% senior notes and $300 million of 30-year 5.85% senior notes. The offering was very well received by the market, and we were able to price both series of notes well below the indicative secondary levels. Proceeds from the sale of the notes were used for the repayment of the $550 million of 7.75% CERC notes that matured in February. Obviously, we are very pleased to have the opportunity to replace this 7.75% coupon in CERC with debt having a much lower rate. Also in January, CERC issued an additional $343 million of 10-year 4.5% senior notes and provided cash consideration of $114 million in exchange for 52% of the outstanding $762 million of 7.875% notes due in 2013. We are very pleased with the results of this exchange offer. It has allowed us to significantly reduce the size of the CERC maturity that we were otherwise facing in 2013 and to do so by locking in a refinancing rate on the new CERC debt that is very attractive on an historical basis. So we have both lowered the weighted average coupon on CERC's debt portfolio and extended the average maturity of the debt portfolio. I would also note that we have no material maturities until 2013 at either the parent or its two operating subsidiaries. Let me mention that our various revolving credit facilities terminate in late June of 2012. Consequently, we expect to syndicate new revolving credit facilities later this year. The bank market continues to improve, and we will be seeking to put in place new revolving credit facilities with the appropriate size and tenor with the optimum pricing. Now let me turn to my final topic, our 2011 earnings guidance. This morning, in our earnings release, we announced 2011 earnings guidance in the range of $1.04 to $1.14 per diluted share. I would like to highlight a few of our more important economic and commodity price assumptions behind the business unit performance expectations David discussed in his comment. Our expectation is that the overall U.S. economy will continue to recover in line with consensus economic forecast. But the economy in much of our service territories in particular, Texas, is expected to improve a little more quickly than the broader U.S. economy. As for our assumption relative to natural gas prices, we have assumed a forecast in line with the industry consensus, which is approximately $4 per MMBTU. Our forecast does not reflect a material change in natural gas liquids pricing from 2010 levels. We expect the interest expense to decline in 2011 compared to 2010 based on our recent completed refinancing, and we expect the overall tax rate to be 38% for the year. The share count for the EPS calculation will reflect the full impact of the shares issued in 2010. Our year-end share count was approximately 428 million shares compared to the average share count of 413 million in 2010. This increase in share count impacts diluted EPS by approximately $0.04. As the year progresses, we will keep you updated on our earnings expectations. Now I'd like to turn the call back to Marianne.

Thank you, Gary. And with that, I will now open the call to questions. And in the interest of time, I would ask you to please limit yourself to one question and a follow-up. So Tina would you please give the instructions for how to ask a question?

[Operator Instructions] Our first question will come from the line of Carl Kirst with BMO Capital.

Gary, just kind of keying in on the comments you made, and appreciate the color here. You would nor or you'd made a mention of the questions we're getting on potential financing of new significant projects. And so maybe for you or David, can you sort of comment how perhaps that opportunity is progressing perhaps on a relative basis versus three months ago? Do you find that conversations are heating up on this front, slowing down, staying the same, percolating in the background? Any additional flavor on that?

Carl, we continued to be in very active discussions with a number of producers and this is around projects in our footprint: Haynesville, Fayetteville, Woodford. But it's also around projects outside our footprint, in particular, the Eagle Ford. But we don't expect that the Eagle Ford discussions are near-term decisions. They're sometime later this year, but we're actively looking at it. I would say they're probably more active today than they were three months ago because it's getting closer to a decision point. But there haven't been any official RFPs put out on the -- by the producers we're talking to. So I think they're very active discussions, but I think we probably, before midyear, we'll know if we're going to have any real expansion opportunities outside our footprint.

Great, and I appreciate that color. And then a second question, if I could, and I know this is a little bit of apples and oranges, but I want to get a better sense of the sales and services aspect that David, I think you mentioned, you expect to be improving in 2011 versus, say, for instance, pipeline, ancillary park and loan which is going to basically be staying unchanged. And I perhaps maybe incorrectly, tend to think of both of those as somewhat being linked to volatility perhaps. Can you give me a better sense of perhaps why we should expect to see an increase in the competitive sales and services in 2011? And if you could also give us some more color -- if we look back on prior years, again pre-mark-to-market, there's been a pretty robust earnings range prior and so when you say you expect to do better in 2011, is that nominally or are you thinking that it's going to get back to something like 2009, for instance?

Let me give you a little bit of color around this. As you know, I've told you in the past that we believe our retail business produces operating income in the $30 million to $35 million range. And our wholesale business, in the past, has added operating income above that. We clearly didn't make any money. We, in fact, lost some money in the wholesale business in 2010. Now part of the reason, I believe we're going to do better is, some of the pipeline capacity that we have under contract terminates this year. And so we're not going to have to try to find ways to offset that fixed expense. It's just going to go away, but we're also taking a much different approach to that business. Our goal is to make sure we fully realize the retail businesses' profitability in our CenterPoint earnings and not have the wholesale business, at least in the near term where basis and seasonal price differentials are really small, impact the overall profitability of the company. So we're working hard to make the wholesale business at least breakeven, but hopefully we'll be able to produce a profit and then we'll be able to fully realized our retail business, which is really why we're in this business. We're in it to sell gas to commercial and industrial customers. We have a lot of pipeline capacity, about a Bcf scattered across the country and 10 or 11 Bcf at storage, which we use primarily to serve our retail customers. But we are able to optimize around that. And in the past, some years, we made $30 million, $40 million, $50 million on that. Those days are probably gone at least for the foreseeable future with all the pipeline capacity that's been built, the new reserves and all the storage that's coming in. You never know, there's always disruptions, as you know, weather, hurricanes, something happens that you stand ready to be opportunistic. But our base plan is not based on that. It's to, let's make sure we get the full retail business reflected in earnings and then make sure wholesale is at least breakeven.

Great. I appreciate all that color.

Our next question will come from the line of Reza Hatefi with Decade Capital.

I just wanted to ask a follow-up on your MLP comments earlier. I guess, in the past, you've said MLP would be kind of in your toolbox in case you needed it. And then it sound like today you kind of said the same thing in terms of if your credit and balance sheet and so forth are improved and you need it for financing you would look at it again. Has there been a shift in tone where now it's more of an option to go forward with it? Or is this kind of the same as always?

This is Gary. I think the first thing I'd say is that we have continued to improve our credit metrics as I mentioned and strengthened our balance sheet. And so I do think from the standpoint of optionality around an MLP, be certain we have positioned ourselves better to do so. From a financing perspective, if you look at this year and just to remind you, from a cash flow perspective, we have the benefit this year of -- in 2011 of approximately a little less than $500 million of bonus depreciation, reducing our overall CapEx programs. So we're going to have what I would describe as very limited need for any borrowings this year. So from a financing perspective, I think it really has and we've been consistent of saying that if it's an optimum financing -- in other words, to the extent we have the opportunity, originating new business, that David described earlier, that would require additional capital, we think the MLP certainly could be the more optimum way to finance that. So we continue to work diligently to be prepared if that is in the best interest of the company.

I guess is it fair to assume maybe it's more of a farther out option, maybe 2012 or later because this year sounds like you're doing fine?

I don't think I would reach that conclusion. I would conclude the following or provide you the following guidance: we are going to continuously look at what's in the best interest of the company both from a financing perspective and a capital structure. And we're going to continue to be thoughtful about that. But certainly, one of the key drivers would be the opportunity that we would originate new business that we would need to finance. So I don't want you to read in 2011 or 2012. Just, I think, read in that the company's going to execute within its best interest and the best interest, more importantly, of our shareholders.

[Operator Instructions] Our next question will come from the line of Ali Agha with SunTrust.

David or Greg, I apologize if you addressed it and I missed it in the early part of the call. But could you remind us, what is the final impact of this Houston Electric rate case that just was completed?

I noted that in my comments, Ali. On an annualized basis, the operating income impact is $25 million to $30 million. In 2011, we're thinking it’s close to $20 million because that will not be implemented until the second quarter. And this is a reduction in operating income. Now it has very little -- as a matter-of-fact, it has a slight increase in cash flow. But the operating income impact is negative.

And just related to that, could you also remind us, what was your actual ROE earned by Houston Electric in 2010? And what sort of the embedded ROE in that guidance that you gave us for '11?

That's a good question. I don't have that at my fingertips. Let me tell you where we were and this is a roundabout way of getting to it. In 2009, if you use the same rate base methodology that the commission used in our case, i.e. reducing rate base by our uncertain tax positions, we would have earned about 10.5% on equity. That's pretty close to where we're going to be in 2010. I haven't done the actual calculations, but it'd be about 10.5% and of course they are now saying that we ought to be earning 10%. And that difference between 10% and 10.5% is about $15 million of revenue gone.

I see. So based on that math, you should be pretty much around 10% in '11?

We will -- I hesitate a little bit because we do have this consolidated tax adjustment that the commission made and it's a $10 million adjustment and it's the cut for tax savings in our other subsidiaries, which really don't flow into Houston Electric. So we have to overcome that $10 million reduction to make our full rate of return. Now we're going to work hard to do that, but I can assure you that will happen.

Our next question is a follow-up question from Carl Kirst with BMO Capital.

Just a couple of cleanups, but David, staying on the rate case decision for a second, what would be the timeframe -- I mean how much farther out should be go before we might be re-addressing some of the issues here? I mean, taking off the consolidated tax issue, which I guess making its own focus here. But is it three years, four years, could it even be next year? I'm just trying to kind of get a sense of is the magnitude of the disappointment enough that it could be this time next year looking at another rate case or is it much further out?

It's certainly in this year. It could be perhaps in late 2012, but I don't -- I can't answer that probably the way you'd like for me to because we hadn't really made that decision yet. I will say this. What we're really working on with both the commission and the legislature is a distribution cost recovery factor, which would allow us to make periodic rate changes without a full rate case. Take this regulatory lag out from all the capital we're spending and absent the AMS investment, we're still spending $400-plus million a year. And that has a regulatory impact. So our focus is to try to get this distribution cost recovery factor, give the commission the authority to do it. They took this rule up late last year and decided to not go forward with it until the legislature took a look at it. But that's our focus today as opposed to filing a full rate case to see if we can't get that done in this legislative session.

Great. I very appreciate that. And then two quick follow-ups for Gary. Gary, could just -- you mentioned the bonus depreciation, but I didn't catch the number. Could you just repeat what the bonus depreciation impact is for 2011? And also what year-over-year, if it's material, pension expense increase?

On bonus depreciation, a little less than $500 million in 2011. And we had about a $30 million benefit last year. And then in 2012, we'll also have a $50-plus million benefit from bonus depreciation. So think of this year a little less than $500 million. Also I want you to think of that as being used to fund our CapEx program. I think that's what these tax benefits were designed to do and that's what we're doing, is investing in our businesses. And what was the second question?

Just pension expense year-over-year, I didn't know if it was material or worth noting.

It's probably up about $14 million to $15 million, not material.

Our next question will come from the line of Paul Patterson with Glenrock Associates.

The true-up case in the Supreme Court, what's happened there?

Mr. Rozzell?

I think David calls for me to answer this question because he doesn't like saying we don't have really anything to report, but there have been no developments since the case was argued in October of 2009. So we're continuing to await the court's decision there. There's no statutory deadline by which they have to act. The time when we would have expected to have received a decision from them has come and gone. So I think the only thing that we can say is everyday we're another day closer to a decision.

The contracts, the Interstate Pipeline and the $30 million decrease from all system, ancillary and transportation margins, how much of that had to do with the contract expiration that you were talking about?

The contract, the backhaul contract and the -- and we have some additional capacity that was added as we've put some compression in which was about $100 million that we can get on a forward-haul basis. That had about a $20 million impact on our revenues. Really the -- not having to do with ancillary services, that's on a go-forward basis.

So the $20 million is sort of a run rate going forward, correct?

It is. That's the negative impact, but we're working to offset that. That's kind of what it would look like if we just let it go and not try to offset that. We are trying to both line up additional backhaul contracts, which helps us from a fuel efficiency standpoint as well, as well as we have some capacity on a forward-haul basis we're trying to sell, too. So we're trying to offset that $20 million. To date, we haven't fully been able to do it, but that's the goal of our team, is to make a big dent in that.

And then going out a couple of years now, three or four years, is there any other contracts like this that you see potentially expiring that have a substantial difference from what the market would probably provide if they were to expire?

Not really. The only other ones we have are like on Line CP. We had our initial contracts probably start rolling off in 2015 or 2016. But those were market-based contracts when we signed them, and I don't think they're the same nature as this backhaul agreement. This was a very unique contract at the time and so I don't think we have anything of this nature that's going to be expiring over the next few years.

The 2015 and 2016, how should we think about just sort of how much they're out of the market now, these market-based contracts, when you signed them versus now?

I don't think that they are out of -- Greg, maybe you ought to answer that instead of me trying to fumble it around here.

This is Greg. Basically, our CP capacity, we are currently selling at system max rate and those are the rates we're seeing. And we're trying to negotiate in advance of those contracts rolling off. So while the capacity is still of value, that's our plan and so we extend -- do look to extend those out early.

And then finally on the consolidated tax situation, and I'm sorry I didn't completely grasp everything that you guys were saying, do you think there may be a separate proceeding to deal with that, is that correct?

The commission had a long discussion about this adjustment and whether you should gross it up for taxes. And at the end of the day, they said, let's not gross this up for taxes, but let's have a workshop to fully discuss this adjustment and the tax gross up provision of it. And they'll have that sometime I think this year. If it may lead, it could lead to a rule making. Certainly, we'll be active participants in it. We've disagreed with that provision from the start. It's -- the commission has used it since the mid- to late 90s, and we just fundamentally disagree that you ought to have that kind of adjustment on a stand-alone case.

How does it affect outside of a rate case? Is there any impact that we should think this other than whenever you go in for a regulatory proceedings such as when you went through, is there any sort of true up or anything else we should think about this? It would seem to me that would only be rate case specific.

I think that's a good way to describe it.

And then finally, does it impact the thought process such as the MLP?

I don't think so. I don't think it would affect that.

Tina, do we have any other questions?

We have no further questions, ma'am.

Okay. So then since we have no further questions, we'll end the call. I would like to thank everybody for participating on the call today. We appreciate your support very much. Have a great day.

This concludes the CenterPoint Energy's Fourth Quarter and Full Year 2010 Earnings Conference Call. Thank you for your participation. You may now disconnect.