CenterPoint Energy Inc (CNP) 2009 Q4 法說會逐字稿

Good morning, and welcome to CenterPoint Energy's fourth-quarter 2009 earnings conference call with senior management.

During the Company's prepared remarks all participants will begin a listen-only mode.

There will be a question-and-answer session after management's remarks.

(Operator Instructions).

I will now turn the call over to 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 2009 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 2009 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 Friday, March 5, 2010.

To access the replay, please call 1-800-642-1687 or 706-645-9291 and enter the conference ID number 498-30-541.

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.

Thanks for joining us today, and thank you for your interest in CenterPoint Energy.

In view of the weak economy and some very challenging energy markets, I believe our company performed pretty well in 2009.

That took hard work and dedication on the part of our employees, and I'd like to begin by acknowledging their accomplishments.

We improved the efficiency and effectiveness of our operations, strengthened business relationships, captured new business opportunities and continued 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 face the uncertainties in the economy and energy markets and emerge even stronger.

This morning I'll discuss our 2009 financial results, as well as describe the plans and prospects for each of our business units as we head into 2010.

Let me begin with an overview of our fourth-quarter 2009 results.

This morning we reported net income of $105 million for the fourth quarter or $0.27 per diluted share.

This compares to net income of $87 million or $0.25 per diluted share for the same period of 2008.

Operating income for the fourth quarter of 2009 was $299 million compared to $303 million for the same period of 2008.

Our regulated electric and natural gas distribution utilities achieved solid results this quarter.

Houston Electric's operating income increased $6 million, primarily due to customer growth, higher transmission-related revenues and earnings related to our advanced metering investment, partially offset by reduced energy demand and higher labor cost.

Our natural gas distribution segment reported a $3 million increase in operating income, primarily from rate increases and lower bad debt expense, partially offset by an $11 million increase in pension expense.

The energy markets had a greater effect on our other business units.

Our Interstate Pipelines and Field Services segment were each down $4 million.

Our pipelines were impacted by reduced ancillary revenues, primarily as a result of lower off-system sales.

Field Services revenues were down as natural gas and liquids prices we received dropped from 2008 levels.

Due to reduced basis differentials, operating income at our energy services business declined by $5 million.

Overall, however, this was a solid quarter which, again, demonstrates the benefit of our balanced portfolio.

Let me now turn to our full-year 2009 performance.

Our reported net income for 2009 was $372 million or $1.01 per diluted share compared to $446 million or $1.30 per diluted share for 2008.

Operating income was $1.124 billion in 2009 compared to $1.273 billion in 2008.

While operating and net income were down from what was a banner year in 2008, I believe that there is much about 2009 to make us optimistic about the future.

Let me give you a little more detail regarding the full-year performance of each of our business segments.

Our regulated transmission and distribution utility, Houston Electric, reported operating income of $414 million compared to $407 million for 2008.

This increase was primarily the result of higher transmission-related revenues, customer growth and income from our investment in an advanced metering system offset in part by reduced energy demand and higher operating expenses.

Operating income for 2008 was negatively impacted by $7 million as a result of Hurricane Ike, but included a gain of $9 million for a land sale and $5 million from a state franchise tax refund.

In 2008 we're adjusted for these items.

In 2009 operating income would have been up $14 million or approximately 3.5%.

It is worth noting that even in a weak economy we added over 29,000 customers in 2009, a growth rate of almost 1.5%.

As we have discussed in the past, Houston Electric is progressing well in implementing our advanced metering system.

During 2009 we installed over 150,000 smart meters along with the supporting communications equipment and information systems.

We are currently in negotiations with the Department of Energy for $200 million in federal stimulus funds composed of $150 million to accelerate the implementation of our advanced metering system and $50 million to support our intelligent grid initiative.

Assuming that the project is funded in accordance with our application, we will accelerate our AMS deployment to substantially complete the project in 2012 rather than 2014 as originally planned.

Because the DOE requires matching expenditures, there will be some acceleration of company funding, but we don't expect it to be material to either cash flow or earnings.

Finally, in our stranded cost true-up appeal, the Texas Supreme Court heard oral arguments last October.

All briefs have been submitted and we are now awaiting the court's decision.

There is no statutory deadline for the court to act, but we anticipate a decision sometime this year.

Now let me turn to our natural gas distribution business.

This unit reported operating income of $204 million compared to $215 million in 2008.

Operating income benefited from rate increases totaling $36 million and lower bad debt expense of $15 million.

Offsetting these benefits were increased pension expense of $37 million, higher operating expenses, primarily employee-related costs, and higher depreciation and taxes.

This business unit has worked diligently on reducing customer delinquencies and bad debt expense and I'm pleased to say that we saw the benefit of that effort in 2009.

Unfortunately, unlike our electric utility, our natural gas utilities cannot defer pension expense increases.

Had it not been for these increases, this business unit would have had an outstanding year.

Over the last several years our natural gas utilities have been focused on obtaining necessary rate increases and improving rate design.

Last July we filed two gas rate cases.

In our Houston service territory, which now covers 30 cities serving nearly 1 million metered customers, we requested a revenue increase of a little over $20 million.

Earlier this week the Texas Railroad Commission authorized a $5 million base rate increase.

Recovery over three years of $2.6 million of Hurricane Ike related costs and lower depreciation rates than requested.

We are disappointed in a number of aspects of this decision and we'll have to evaluate when another case will be necessary.

In Mississippi we filed a $6.2 million rate increase request.

We subsequently reached an agreement with the Commission that allows us to retain the benefits from an asset management agreement and were able to withdraw this request for rate relief.

In our Minnesota rate case, which we filed with the Minnesota Public Utilities Commission in November 2008, we asked to increase rates by $60 million and to decouple revenues from the volume of gas sold.

In January of 2009 we implemented a $51 million interim rate increase.

In January of this year the Minnesota Commission approved a $41 million increase and a three-year decoupling pilot.

With this decision we now have decoupled cost recovery from the volume of gas consumed for approximately one-half of our 3.2 million customers.

Our Competitive Natural Gas Sales and Services business reported operating income of $21 million for 2009 compared to $62 million for 2008.

We recorded mark to market charges of $23 million in 2009 compared to gains of $13 million in 2008.

As you know, these mark to market impacts are associated with derivatives we use to lock in economic gains.

In addition, in 2009 we recorded a $6 million write-down of inventory to lower average cost per market compared to a $30 million inventory write-down in 2008.

Excluding these items, our energy services business would have reported $50 million for 2009 compared to $79 million for 2008.

This decline was principally the result of reduced wholesale opportunities because of significantly tighter locational price differentials and an absence of summer storage spreads.

However, our retail sales were stable in 2009, and we added nearly 1,400 customers to our total customer base.

Now let me turn to our Interstate Pipelines unit.

Interstate Pipelines recorded operating income of $256 million for 2009 compared to $293 million for 2008.

2008 included a net gain of $11 million associated with the sale of two storage development projects offset by a write-down of pipeline assets removed from service.

Adjusting for these two items operating income decreased approximately $26 million.

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 9%, but this growth was more than offset by reduced ancillary services as well as incremental operating cost associated with new facilities and increased pension expense.

Our equity income from ongoing operations from the Southeast Supply Header, or SESH, our joint venture with Spectra, was $23 million for the year.

However, this income was partially offset by a $16 million non-cash charge to reflect SESH's discontinued use of regulatory accounting.

In 2008 equity income was $36 million, primarily from allowance for funds used during construction.

Last March our Interstate Pipelines group signed an agreement with Chesapeake to take 80% of the capacity on the Phase IV expansion of our Carthage to Perryville pipeline.

We completed these facilities and began the contracted service at the beginning of this month, two months ahead of schedule.

Last November we signed a joint development agreement with a subsidiary of FPL Group to explore constructing a new pipe in North Louisiana, primarily focused on moving natural gas from the Haynesville Shale area.

We are currently in discussions with possible shippers to assess the size, timing and scope of a potential new pipeline.

Now let me turn to our Field Services segment.

We reported operating income of $94 million for 2009 compared to $147 million for 2008.

Operating income for 2008 included gains of $17 million associated with the sale of non-strategic assets and the settlement of a contractual dispute.

The remaining $36 million decrease in operating income was primarily the result of significantly lower natural gas and natural gas liquids prices in 2009.

Field services achieved a 23% increase in core gathering margins, primarily associated with the Haynesville, Fayetteville and Woodford shales.

These new volumes more than offset the reduced gathering in our traditional natural gas basins, resulting from the significant decline in drilling activity in those basins.

In addition to operating income, we also recorded equity income of $8 million from our jointly owned natural gas processing facilities compared to $15 million the previous year.

Again, the decline was primarily due to lower liquids prices.

Last September we signed long-term agreements with subsidiaries of Shell and EnCana to provide gathering and treating services for their growing Haynesville Shale natural gas production.

We acquired facilities that are gathering and treating production of over 100 million cubic feet per day and are expanding these facilities to gather and treat up to 700 million cubic feet per day.

We are well underway having completed several significant milestones.

Overall investment in this project is expected to be around $325 million.

In 2009 we invested more than $175 million in acquiring and expanding the facilities and expect to spend approximately $80 million this year.

The agreements with Shell and EnCana have minimum volume commitments and provide us exclusive rights to gather and treat their natural gas production in designated Haynesville acreage.

As part of the agreements, EnCana and Shell can commit to additional volumes and, if they do, we will further expand the facilities to gather and treat up to an additional 1 billion cubic feet per day at a capital cost of up to an additional $300 million.

This expansion can be requested in increments of 100 million cubic feet per day to coincide with increases in their Haynesville production.

Most of our contracts in the shale production areas include acreage dedications, volume commitments and/or guaranteed return contracts.

We are also beginning to see a resumption of drilling activity in our traditional gathering footprint, although drilling levels there remain well below 2008 levels.

Taking into account the performance of all of our business units under demanding conditions, I believe the Company had a very solid year.

Moreover, I believe we are well positioned as the economy improves and energy markets rebound and that our overall financial results continue to demonstrate the benefits of our balanced portfolio of electric and natural gas assets.

Now let me turn to our outlook for 2010.

We believe that the combination of the stability provided by our regulated electric and natural gas utilities, and the high-level of activity in a number of producing areas served by our pipeline and Field Services segments, should allow us to achieve solid performance across our various business units in 2010.

We expect Houston Electric to continue to perform well.

However, operating income will be reduced by $24 million to account for the effect of deferred taxes associated with Hurricane Ike.

This deferred tax effect will decline each year, but will last for the 13-year duration of the storm cost recovery bonds.

We anticipate that our customer base will grow at a pace comparable to the level experienced in 2009.

In addition, we expect to file a transmission rate case this fall to reflect increased transmission investments and recover the remaining $20 million of Hurricane Ike related restoration costs associated with our transmission system.

Under the terms of a 2006 settlement that froze rates through June of this year, we are required to file a rate case unless the PUC staff and interveners suspend such requirement based on an earnings monitoring report we will file with the PUC next week.

We are currently assessing whether or not we will file a rate case even if we are not required to do so.

Capital requirements for our electric business are budgeted at $560 million, including approximately $167 million related to our advanced meter deployment.

Our Natural Gas Distribution utility should continue to see the benefits from rate increases and rate decoupling as well as ongoing expense control measures.

We expect to see residential customer growth similar to the levels we experienced in 2009 and some additional benefits associated with the asset management agreements entered into this past year.

Our capital plan for 2010 of $210 million reflects an increase in capital spending from 2009 levels, primarily for system and public improvements.

Our Interstate Pipelines will realize the benefits of the Carthage to Perryville Phase IV pipeline expansion project which went into service in February.

We believe we are well positioned to capture ancillary revenues when market dynamics and commodity prices rebound.

We are pleased with the additional fee-based contracts added in 2009, which will provide further stability to earnings.

We continue to see a very high level of drilling in the shale areas, particularly the Haynesville, Woodford and Fayetteville shales.

This is driving opportunities for both our pipelines and Field Services.

Increased gathering volumes from the Haynesville and Fayetteville shale areas are expected in 2010 and, as a result of the contracts entered into in late 2008 and in 2009; we expect our Field Services results to improve this year.

Current natural gas and natural gas liquids prices are also running at or above prices we experienced in 2009.

Our pipelines capital budget will be approximately $171 million, or about the same as 2009.

Our capital budget for Field Services is $226 million for 2010.

We spent about $350 million in 2009 which was a record for this business units and reflected significant investments in the shale areas.

Gary will provide our overall earnings guidance for 2010 in his remarks.

In closing, I'd like to remind you of the $0.195 per share quarterly dividend declared by our Board of Directors on January 21.

This is a 2.6% increase over the dividend we paid in 2009 and the fifth 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 would like to discuss a few items with you.

As David mentioned, 2009 was a very challenging year for the overall economy and for energy markets in particular.

In addition to these challenges, we began the year with a number of significant concerns about the overall strength of the capital and bank markets following a very difficult second half of 2008.

In spite of these challenges our businesses performed well, which again highlights the benefits of our balanced portfolio in delivering stable earnings and cash flow.

We're also pleased with the steps we took during the year to significantly improve our balance sheet, enhance our credit metric and expand our available liquidity in order to ensure that we maintain the financial flexibility to effectively execute our business plan.

Let me discuss some specific improvements.

Excluding securitization debt we reduced our corporate debt from $8.1 billion at year-end 2008, to $7 billion at year-end 2009 while funding a capital program of approximately $1.1 billion.

Our debt to total capitalization improved from approximately 80% to approximately 73% at year-end 2009.

We ended the year with net debt of $6.4 billion, a reduction of over $1.6 billion from 2008, which includes $589 million of available cash.

Subsequent to year end we continued to pay down debt to reduce the negative carry associated with our significant cash balance.

We redeemed approximately $45 million of 6% convertible subordinated debentures due in 2012.

In addition, we've repurchased three series of 5-1/8% secured pollution control bonds totaling $290 million at 101% of their principal amount.

Let me point out that we have the ability to remarket these pollution control bonds in the future if beneficial.

We also executed a number of financings as well as operational improvements to enhance our strong liquidity position.

As you know, we have had and will continue to have a relatively large capital budget which includes franchise required capital in our regulated operations combined with a number of very attractive projects, particularly in our field services segment where producer activity remains strong especially in the shale production areas.

To ensure that we maintain the financial flexibility to effectively execute our business plan, we raised approximately $504 million of additional equity through the sale of approximately 46 million shares of common stock last year.

Of this amount $280 million came from an underwritten equity offering in conjunction with the announcement of our Field Services business signing excellent long-term agreements with EnCana and Shell to expand gathering and treating facilities in the Haynesville Shale.

The remaining equity was raised through the sale of stock in a continuous offering program and the issuance of stock through our savings plan and dividend reinvestment plan.

In November Houston Electric recovered its distribution-related storm costs associated with Hurricane Ike through the issuance of approximately $665 million in storm restoration bonds.

These bonds were issued at very favorable interest rates and will provide significant savings to consumers over the next 13 years compared to traditional cost recovery methods.

Just as important, the legislation that authorized these bonds also gave the PUC ongoing authority to allow a utility to recover costs associated with future hurricanes and other natural disasters through securitization financing.

In August SESH secured permanent financing through the issuance of $375 million of senior notes with CERC receiving a construction loan repayment of $186 million.

In addition to the sources of cash from financing, we continue to manage our working capital requirements very efficiently.

Our Natural Gas Distribution business entered into a number of asset-management agreements that reduced our working capital requirements and optimized the operations of our transportation and storage capacity.

These agreements benefit our customers through regulatory approved sharing arrangements.

We also benefited from the continuation of bonus depreciation in 2009 and are hopeful legislation will be enacted to continue it in 2010.

With the improvements we have put in place in 2009, the absolute level of our working capital needs has decreased.

Now let me touch on liquidity.

In October CERC extended its receivables facility for another year with the size of the facility ranging from $150 million to $375 million, consistent with the seasonal changes in receivable balances.

In February of this year we amended the financial covenant in our $1.2 billion bank credit facility to permit approximately $800 million of additional debt in the event we were to have another storm in our service territory requiring us to incur significant cost to restore power to our customers.

This is similar to the amendment that we obtained after Hurricane Ike struck our service territory, but instead of having to wait to seek covenant relief after the fact, we now have an agreement with our bank that the covenant will automatically adjust should another major storm strike our service territory.

We were very pleased to have had the support of 100% of our bank group on this amendment.

We ended 2009 with $589 million of available cash and no significant borrowings under any of our credit facilities.

Our improved liquidity, significantly lower leverage and improved cash flow metrics better position us to continue the effective execution of our business plan in 2010.

Now let me turn to my final topic, our 2010 earnings guidance.

This morning in our earnings release we announced 2010 earnings guidance in the range of $1.02 to $1.12 per diluted share.

However, as you compare our 2010 earnings guidance to our prior-year results, I would like to highlight a few items.

First, our business units' financial performance will improve as the combination of the earnings stability provided by our regulated operation and the high level of activity in a number of gas producing areas where our pipeline and Field Services businesses have made significant capital investments, will allow us to achieve improved operating income in 2010.

Second, we expect to benefit in 2010 from reduced net interest expense.

Third, we expect our tax rate to return to a more normal level in 2010 of approximately 37.5% compared to a 2009 tax rate of 32%.

And then forth, as I mentioned earlier, we raised equity last year to support our value growth initiatives, and we ended 2009 with approximately 392 million shares outstanding.

Finally, as you know, in providing guidance we have routinely excluded the effects of mark to market and inventory accounting as they are timing related and we do not try to predict the potential impact to income from our pending true-up appeal, the change in the value of Time Warner stock and the related then securities or any mandated accounting changes that may occur during the year.

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.

With that we 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.

Tina, would you please give the instructions on how to ask a question?

(Operator Instructions).

Carl Kirst, BMO Capital.

Good morning, everybody.

If I could actually start in the pipeline side, I just wanted to get a little bit better sense of the drivers behind the lower off-system sales, if that was a reflection of basis.

So trying to get a sense of what was behind that.

And then in general for 2009, what was coming from ancillary services and park and loan and how do you expect that to contrast in 2010?

Yes, Carl, let me give you on the first point, off-system sales driven by two factors.

One was basis was much tighter across the year than in 2008 and that was a big piece of it.

But we're also running our pipeline at a much higher capacity factor.

Not a lot of excess capacity that we can sell on a daily firm or an interruptible basis, and that clearly had its impact as well.

So I think those two items are the biggest driver for off-system sales.

The other pieces, you know, in ancillary services we have [PAL] service, we have system balancing, we have system management, we have processing.

All of those kind of move around depending on really the -- some was on the behavior of our customers, and then some is just on where gas is moving in from.

But I would say processing, because of the drop in liquids, was a fairly significant piece of the drop in 2009 compared to 2008.

And then just with respect to outlook in 2010, as far as how you expect those buckets to be moving around.

Have we very much based out on those dynamics?

Are we looking at obviously higher commodity prices, but I guess to the extent that basis differentials are probably going to remain tight here and you guys are running at high utilization, that may be the element that doesn't come back?

Yes, I think that's right.

We -- it's hard to estimate ancillary services, as you know, because it's really based on market dynamics.

We saw a very steep decline from 2008 to 2009 for the reasons that I think we're all aware of what happened in the energy markets.

I think the steepest decline is behind us, but we can still see some movement both up and down.

I think off system sales, though, because just the fullness of our pipeline, it would be a little hard to see a rebound there.

But we could see a little bit more of the other services than we saw in 2009.

It's just really hard to predict.

The good news is our core business, our fee-based business which is, as you know, demand-based and not volume-based, it's solid, and it will be even increasing over 2009 levels with the Phase IV Carthage to Perryville and some other projects that we've put in service.

So I think the overall business is very well positioned.

Ancillary services will drive whether or not you get a big increase over 2009.

Great.

And just a very quick follow-up.

David, you mentioned you're still assessing whether or not you guys might be filing a rate case on HL&P in 2010.

Does that mean we should assume the expectation of the ROE for HL&P this year is basically in that 10% range?

We had a pretty good year at Houston Electric.

HL&P is an old term there, Carl.

Thank you.

Sorry.

But we did get -- on an adjusted basis we're probably at pretty close to 11% ROE.

On a weather adjusted basis we're probably close to 10% ROE.

And then depending on where your capitalization is, we believe we ought to have about a 45% equity level in the business and not a 40% equity level.

But we're pretty close to earning our authorized rate of return on a weather adjusted basis.

But there are some things that we're not recovering.

For example, we're deferring these pension costs.

They're very significant.

Even if we don't get an earnings uplift, we certainly would get the cash flow and start covering this pension expense and rate.

So lots of things we have to think about there before we make that decision.

PUC staff and interveners can require us to go in and file in June of this year based on a December 31, 2009 test year.

We file that report on Monday.

And so they'll take a few weeks I'm sure to look at it, and then we'll start talking with them.

But we're earning pretty close, maybe a little bit less than we think the real return is.

I think the Commission is looking at 10.5% ROE, in that range, and I think on a weather-adjusted basis we're earning less than that.

Great.

Appreciate the color.

Faisel Khan, Citigroup.

Good morning.

You had a lot of headwinds in 2009, $37 million of pension headwind in the gas utilities, you've got $55 million on the commodities side, the Field Services business and as Carl was pointing out, the $32 million in ancillary sort of headwinds you had and $29 million in lower cost to market and kind of mark to market adjustments in 2009.

I'm just trying to figure out, for your 2010 guidance, what do you assume about any of these things kind of coming back or if at all and turning the other way?

Let's take commodity prices.

We went from $1.50 on liquids to $0.80 in 2009.

We went from probably $7 to about half that -- $7 in 2008 to half that in 2009.

Prices today are running ahead of those, but it's hard to predict exactly where that's going to go.

We know that it's going to depend in part on demand for gas and how fast this economy comes back.

But certainly gas prices today are in that $5 range, so they're a little above 2009.

We are not predicting big increases in commodity prices in our forecast.

We have some slight increases, especially on liquids prices, but I'd also probably need to remind you that in 2009 we did fix some natural gas prices in advance of the year, so we got some gas sold at $5 give or take a few pennies, which is about where the price is today.

So we're predicting a little uptick in liquids prices, maybe a little bit in natural gas, but not much.

In terms of ancillary services, I think we addressed that when I talked to Carl.

We could see some bounce back, but we're not counting on a lot of bounce back there in our earnings guidance.

And there's just not anything we can do with this pension increase until we get our gas rates to fully reflect these increases.

And they don't yet.

We do have a little bit in the Minnesota rates, and I don't think that the recent decision we got for Houston really reflects the level of expense we're incurring there.

They used some averaging that really didn't reflect the actual expense we were incurring.

And the level of earnings for the competitive natural gas business for 2010, are you expecting that to roughly be the same as 2009?

I think that 2009 was a little unusual.

If you adjust all those figures out where -- it's probably in the $40 million to $50 million level on a normalized basis if you take out mark to market and inventory write-downs.

It's really a wholesale issue.

Our retail business I think is really doing well.

We had strong results in 2009 in the face of a weak economy where we were able to maintain our retail sales there and our margins there.

But basis differentials and storage spreads are weak, and it's all going to depend on where they go.

We've assumed a little bit of rebound, but not a huge rebound.

Okay, fair enough.

And on the commodity price side, is it fair to say that you've got a fairly muted expectation for NGL prices for this year, maybe similar to last year to some degree?

That's exactly what we're doing, Faisel.

It may be a few pennies above what we realized, but we're not projecting a big increase there.

That's fair.

Thank you very much.

I appreciate it.

Ali Agha, SunTrust Robinson.

Good morning.

I wanted to check and, David, just be clear on when you were talking about the ROE's at Houston Electric, were you saying those numbers based on a 40% equity ratio or the 45% that you think is appropriate?

That's based on actual capital structure.

That's what we have to file on at -- when we file this earnings monitoring report, which it's probably closer to 45% than it is 40%.

Okay, and is the authorization at 40%?

The rates that we have in place today were based on a 40% equity, 60% debt with an 11.25% ROE.

Let me back up a minute; I think I'm mistaken.

The ROE's that I noted were based on a 40% equity level.

They were all 40%, okay.

Yes.

I'm going to double check that because I had recalled that differently, but --.

Okay, and one other question, David.

As you were pointing out, your results in the segment should be improving 2010 over 2009, but if you look at the businesses right now in terms of the capital you've invested and the returns you're getting, would you -- how would you rank them in terms of the returns being commensurate with the capital invested?

Which businesses, Ali?

I'm just thinking across the four or five segments you operate in and I'm just looking across-the-board.

Let me kind of take each one of them.

I think if you look at the results of our regulated utilities, Houston Electric is doing just fine.

We've made lots of improvements in our gas LDCs, but we're still not earning in a double-digit digit level.

It is a high single-digit, and we continue to improve that certainly from what it was a few years ago.

So I would say that that one is still work in progress but much better than it was in the past.

Our Field Services investments we feel very good about and they're very attractive.

And we believe in fact we are getting a compensatory return, and we're creating substantial shareholder value there.

Our pipeline is pretty much a solid regulated return in the pipeline side.

You're talking about 12% to 13% ROE's, and I think we've been achieving that except for one exception, which is SESH.

And it just cost a lot more than we thought.

Okay, thank you.

Steven Gambuzza, Longbow Capital.

Good morning.

I wasn't clear from the comments earlier whether you were assuming increased GAAP pension expense in 2010 earnings guidance versus the realized amount in 2009.

No, it's going to be about the same level.

It could be a tad lower just because our pension assets are a little better than we had experienced at the end of 2008.

So I think that we're going to see a little bit improvement in pension expense there.

Okay, and I guess the point is that you're still not recovering this amount in your rates, so there is some upside in 2011 to the extent you can recover this level of cost in your rates?

Steven, that's the real issue.

We've got this -- last year we had $37 million in pension expense just because assets fell so far at the end of 2008.

And it's not fully reflected in rates.

We're chipping away at it, but it's not there yet.

And the same thing is going to occur in 2010.

But it's not going to be quite the impact because I think the pension expense is going to come down a little bit.

Okay, and then, I appreciate you commented on this already, but I just want to make sure I understand.

With respect to Field Services and the pipeline segments -- maybe we could address each separately.

When you think about the commodity headwinds that impacted your realized margins in 2009 versus 2008 it sounds like you are expecting a small improvement in both those sequentially in 2010 versus 2009.

Is that correct?

I think we will have a little -- we are not predicting a big increase related to commodity price uptick.

There will be a little bit.

And I think you can think of 2009 more of a base year.

2008 was just a year where energy prices were much higher than we've experienced in a long, long time.

We were fortunate.

We took advantage of it.

Our shareholders got the benefit of it.

But that is not something we predict that is going to occur each and every year.

So when we think of these businesses, we think of 2009 as kind of the base year and the way to base your thinking.

We think there could be some upside there if energy prices firm up, but I -- we are not predicting a huge amount.

And I would say that on the pipeline side they are a little bit sensitive to price, but it's more sensitive to basis and things of that nature and not just price.

So if prices for NGLs and gas and base differentials were to kind of stay around where they are, at least relative to where the forward curves are now, if that were just to kind of stay relatively constant throughout the year, is it fair to say you would not be experiencing negative year-over-year comparisons on your margin lines as we roll through the quarters?

I think that is fair.

It doesn't quite translate the same way in the pipeline, certainly in Field Services.

But I think that is a fair generalization, Steven.

Okay, thanks a lot.

Daniele Seitz, Dudack Research.

Thank you.

I was wondering, is there a way of isolating the earnings that you are getting from the smart meters investment since I believe it is a rider?

Or is it not possible?

Let me kind of give you a kind of -- it's in the kind of $10 million, $12 million range.

That's the revenues less expenses.

This is kind of a -- we true this up and we don't earn more than our authorized return.

So it's in that level, what drops to the operating income line.

Okay, great.

And in terms of the back to those pipeline and Field Services areas, you do have an expansion of the base in the pipeline areas, so that is a reason for upside, correct?

Yes, we do have Phase IV Carthage to Perryville that went into service the beginning of this month, and so we'll get the benefit of that.

And we had some contracts that weren't in affect the full year of 2009, so we'll get the benefit of that in 2010 as well.

And of course we continue to look for other opportunities, but most of those, if they're significant, they'll take a few months to get in place.

Okay, great.

Thanks a lot.

The other thing, Daniele, is we have the Shell EnCana projects.

Certainly we're investing a lot of money.

We expect those volumes to ramp up kind of throughout the year 2010.

And we also had some projects in the Fayetteville and Woodford area, and we think we're going to see some ramp up in those areas as drilling picks back up.

In the Fayetteville area we saw some slight reduction in drilling in the fourth quarter, really related to pipeline capacity coming out of that area.

There were some shut-in pipes and some rigs left the area.

We expect those to come back, and as they do we expect volumes to pick up from those areas as well.

Do you have a sense, I mean just a hint as to what type of increase you're looking at, something sizable?

We feel pretty good about where Field Services is headed.

I'd be hesitant to predict exactly.

You know, we had an increase of 23% in core margins in 2009 over 2008.

And I think we can see a double-digit increase there.

I'm not going to -- I can't really say exactly how much, but we think that we ought to get some good increases in Field Services if the drilling continues.

Great.

Thanks a lot.

Vedula Murti, CDP.

I'm wondering in terms of, if we take a look forward here in 2010 in particular, given the large equity issuances that you had during the year of 2009, aside from maybe dividend reinvestment at a fairly modest level, should we really be expecting any more incremental equity?

Or are there some projects that you're looking at similar to EnCana Shell that it might be possible that would require some funding?

No, in terms of this last year we raised a significant amount of equity.

This year we're going to continue our benefit programs, and that's what you'd look in terms of share count increase at about the same level as last year on those benefit programs.

In terms of any additional equity, it would really only be related if we had the good fortune of having a very significant, very accretive project.

And maybe I'll just make a point about this.

Our cash flow from operations in 2010, plus if you recall, I mentioned we had a significant amount of cash on hand, plus this fairly minimal equity we raise sort of routinely through our benefit programs will certainly fund our CapEx program or dividends and including this maturing debt, the $200 million maturing debt.

So we feel really good about our financial position in 2010 to execute our business plan.

Okay.

And probably a follow-up on Faisel's question.

There were several items he mentioned, but could you kind of frame it in aggregate right now kind of what you think is the earnings opportunity from fixing pensions and some of the other issues that the gas LDCs, etc., what type of a potential net income delta that we have and opportunity to work up over a period of time?

Well, it's kind of hard to just look at expense numbers.

If you look at where we're earning at the gas LDCs, I said that let's just call it 9% or so, we've got a rate base of well over $2 billion or about $2 billion.

And so you can kind of -- and assuming about a -- in most cases we have 45%, 50% equity levels.

You can back into kind of what it takes to get to a full rate of return whether it's 10.5% or whatever you're assuming.

So there is some nice upside there.

And then you have -- and part of the reason we're not earning our rate of return is because of the pension.

It's a big part.

If we would have been earning or recovering our pension expense my expectation is we'd have earned our regulated rate of return.

So that's an upside down the road.

It takes time to get those in.

We talked about Houston Electric, and we've got some sizable investments ahead of us in Field Services, but we spent $350 million, 80% of which was for growth projects if not more.

So those projects are going to pay off for us in the long run.

Those are over the next 10 years we're going to get the benefit of all those investments, and we'll to continue to make investments.

We've got a $225 million or so capital budget for Field Services this year, and there could be more if Shell EnCana decides to exercise their option to expand our facilities to get more production out.

I guess what I'm -- so it sounds like to me that if we think about 2010 versus 2009 and then kind of going forward a little bit that in terms of the earnings per share improvement over time that we may have a chance to see maybe something more above trendline in the next couple years as you make up some of these shortfalls as well as the incremental capital investment.

So would that be fair to think that after 2010, assuming that we have a reasonable -- a somewhat reasonable economy, that for a short period of time you can be above trendline as these things work?

I don't think that's an unreasonable assumption.

It's hard to know what the trendline is, and it takes time to get all our rates right in our regulated utilities.

But I'm very optimistic on our Field Services side.

I think we have some opportunities to improve earnings on our regulated utility.

So -- and we're not earning our full return today in some of those utilities.

So I think there's some upside there, yes.

All right.

Thank you very much.

Lasan Johong, RBC Capital Markets.

For some reason I got cut off after a while, so I might have missed a couple things.

But I was wondering if you could tell me what's involved in the asset management business for Minnesota.

We didn't do any asset-management agreements in Minnesota.

We've done these really in Arkansas, Mississippi, Oklahoma and Louisiana.

This is where we basically -- somebody else manages the storage and pipeline capacity, basically provides us gas.

And to the extent they are able to optimize those assets above what the regulated utility would do, because that's not in the business that we're in, we share in their profits.

So it's that kind of arrangement.

It's becoming more and more common across all gas LDCs, and we've done it for a number of our jurisdictions but not all of them.

I see.

Do you see acceleration in drilling in areas where there's more liquids, or is it just straight across-the-board liquids or no liquids?

Do you see a lot more drilling everywhere or just confined to liquids rich areas?

No, I would say that if you looked at 2009 it was in the shale areas, shale areas that Haynesville, Fayetteville, Woodford -- they don't have a lot of liquid, so it is not a liquids play there.

Our traditional basins, yes, there's lots of liquids, but we saw drilling really fall off in 2009.

Now we have seen an uptick in drilling in our traditional basins and that could bode well for us.

But the majority of the wells that are being drilled are in the shale areas, and you don't have a lot of liquids out of those.

And are you seeing a lot of competition for Field Services and pipes or gathering business in the Haynesville?

Yes.

There's plenty of people that are involved in that area and are competing along with us for the same opportunities we see there.

So yes, there's lots of competition there.

And do you see any opportunities in the Eagleford?

We haven't been involved in the Eagleford with our Field Services business.

We own capacity, whole capacity on both NGPL and Kinder Morgan, and we certainly are involved in talking with players in that area.

But we haven't been involved from a gathering or treating standpoint.

Do you plan to or do you want to?

Well, I mean, I think it's a very attractive area.

It's not -- we haven't been in that area before.

I think if we went to that area we'd go with a long-term customer that we've had that wanted us to do it, and we'd love to get involved in it, but we just haven't operated in South Texas.

That's not where we've been focused.

Understood.

Thank you.

Raymond Leung, Goldman Sachs.

Thanks for taking my question, but just to clarify with respect to your spending and capital needs, do you guys anticipate the need for external debt financing for 2010.

And if you could provide us some color on that.

No, as I mentioned, Ray, and we don't expect to.

We have a maturing debt at the parent company.

We'll pay that off.

And in terms of, again, cash flow from operations will still be strong.

And again, I point you to the cash on hand at the end of the year, although we've paid some debt down as well since then.

But we'll fully fund our CapEx program, fund our dividends and so we are issuing, as I mentioned through our benefit programs, more on a routine basis some equity we think as a thoughtful way to do that.

But we're fine interns of our financing for the --.

Okay, great.

Thank you.

We're over time actually, and we've got -- I think we'll take one more question.

Debra Bromberg, Jefferies & Co.

Could you say what the projected rate base level is for the electric company in 2010?

It's between -- about $3.5 billion I think give or take.

That's average for the year roughly?

I'm thinking that's kind of the end of 2009.

We've got a substantial capital budget there, but you have to set aside the amount of AMS because we're already kind of dealing with that under a separate case.

And we're going to spend about $400 million on top of the advanced metering.

So we're going to bill rate base maybe $100 million in 2010.

So I would say that maybe average for the year would be between $3.55 billion and $3.6 billion.

And also, my understanding was that at Encore's rate proceeding a few months ago, Chairman Smitherman had commented that he might be open to potentially higher authorized common equity ratios at the T&D companies from the traditional 40% that they've been going with the last few years.

Are you aware of any further comments from either any of the commissioners or staff regarding the common equity ratio since then?

I am not aware of any other comments.

I am aware of what he said on the record and I think that's exactly what he said is that he would be open and maybe thought it was appropriate to have a little thicker equity ratio.

Encore hadn't requested it, so we don't know what the other two commissioners were thinking, but I do think that there's an opening there.

All right.

Thank you.

Thank you.

All right.

Thank you very much to everyone.

I would like to thank you for participating on the call today and we appreciate your support very much.

Have a great day.

Ladies and gentlemen, this concludes CenterPoint Energy's fourth-quarter 2009 earnings conference call.

Thank you all for your participation.

You may now disconnect.