CenterPoint Energy Inc (CNP) 2008 Q4 法說會逐字稿

Good morning, welcome to CenterPoint Energy Q4 and full year 2008 earnings conference call with senior management.

During the Company's prepared remarks all participants be in a listen-only mode.

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

(Operator Instructions)

I will now turn the call over to Marianne Paulsen, Director of Investor Relations.

Thank you very much.

Good morning everyone.

This is Marianne Paulsen, Director of Investor Relations for CenterPoint Energy .

I would like to welcome you to our fourth quarter and full year 2008 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 2008 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 we 10-K filed earlier today are posted on our website which is www.CenterPoint Energy.com under the investors section.

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 6:00 p.m.

Central time through wednesday March 4, 2009.

To access the replay, please call 1-800-642-1687, or 706-645-9291, and enter the conference ID number 81005183.

You can also listen to an online replay of the call through the website I just mentioned.

We will archive the call on CenterPoint Energy 's website for at least one year.

With that I will now turn the call over to David

Thank you Marianne.

Good morning ladies and gentlemen.

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

2008 was a very good year for the Company.

Our electric and natural gas utilities had very solid performances, nd our interstate pipelines and field services units turned in exceptional results.

Each year since our formation in 2002 we have improved upon a very solid foundation and 2008 was no different.

Not only did we strengthen each of our business units, we also improved the Company's overall financial flexibility and strength.

As we face an economy in decline and uncertain energy markets I believe the Company is well positioned to confront these challenges and emerge even stronger.

This morning I will discuss our 2008 financial results as well as describe the plans and prospects for each business unit as we head in to 2009.

Let me begin with the overview of our fourth quarter 2008 results.

This morning we reported net income of $87 million for the fourth quarter or $0.25 per diluted share, this compares to net income of $108 million or $0.32 per diluted share for the same period of 2007.

The reduction in net income for the fourth quarter is in large part due to higher income taxes, as the effective tax rate for the fourth quarter of 2007 was substantially lower than 2008.

Operating income of $303 million was unchanged from the fourth quarter of 2007.

Our gas distribution business posted an increase in operating income of almost $7 million, due to reduced expenses.

Our energy services business also reported a $7 million increase in operating income, primarily a result of value captured from seasonal price differentials.

Despite continued solid customer growth at Houston electric we recorded reduced operating income of $10 million, stemming primarily from higher transmission costs billed to us by other transmission providers.

Our field services business contributed $2 million more as a result of increased throughput, while our interstate pipelines operating income was $5 million lower due to reduced ancillary services and higher operating expenses.

Let me now turn to our full year 2008 performance.

Overall 2008 was a very good year for us and we continue to make progress in achieving our business and financial objectives.

Net income for 2008 was $447 million, or $1.30 per diluted share compared to $399 million, or $1.17 per diluted share for 2007.

Operating income increased by almost $100 million, to $1.273 billion in 2008.

Let me give you a little bit more detail regarding the performance of each of our business segments beginning with Houston Electric.

Houston Electric reported operating income of $407 million compared to $400 million in 2007.

Beginning in 2008, the Texas margin tax was classified as an income tax and thus did not impact operating income, the 2007 operating income however was reduced by $19 million, due to the previous state franchise tax.

Which the margin tax replaced.

On the other hand, 2007 also included income of $17 million from the final fuel reconciliation associated with our former integrated utility.

So normalizing for these two items, 2008 was slightly better than 2007.

In 2008 we added nearly 31,000 customers to our Houston service territory.

While this is still solid growth, the rate of customer growth moderated in the second half of the year as a result of hurricane Ike and declining economic conditions.

We did see increased customer usage in 2008 due in part to warmer weather.

Our operating expenses were up significantly in 2008 due primarily to an increase in transmission cost.

While we did receive some increase in transmission revenues, the net impact reduced operating income by $22 million, compared to 2007.

We intend to seek legislative or regulatory solutions that would provide for a more timely recovery of these costs.

I cannot talk about 2008 without mentioning the significant role played by Hurricane Ike.

I would once again like to thank our employees and the thousands of mutual assistance workers from around the country who helped to rebuild our system ar Ike devastated our service territory in December of last year.

As a result of their efforts service was restored to most customers within two weeks and to essentially all our customers in 18 days.

The estimated loss of revenue was limited to $17 million, which was partially offset by $10 million in operation and maintenance costs that were postponed because of the storm.

Today, we have incurred approximately $600 million in restoration costs and have only a few invoices still outstanding.

As a result we have lowered our estimate of the total storm restoration cost to between 600 million and $650 million.

These costs are being deferred for future recovery and therefore do not affect our earnings.

Gary will explain the recovery process and expected timing in his comments.

Houston Electric is in the process of installing an advanced metering system as a result of a settlement agreement approved by the Texas PC in December and we continue to explore the implementation of an intelligent grid.

Beginning next month and continuing over the next five years, we will deploy approximately 2.4 million advanced meters across our service territory.

Our capital cost estimate for the deployment is approximately $640 million.

We are recovering the cost through a surcharge which went in to affect earlier this month.

The surcharge for each residential customer is $3.24 per month for the first two years, and is expected to be reduced to $3.05 per month for the following ten years.

This new technology deployment is the first step in moving the electric grid in to the digital age.

Because of the structure of the cost recovery tariff and the timing of deployment we expect the project will have a small negative impact on cash flow, and a small positive impact on earnings in 2009.

Now let me turn to our natural gas distribution business.

This unit reported operating income of $215 million, a slight decline from the $218 million reported for 2007.

Although we added nearly 25,000 customers over the course of the year, the growth slowed markedly in the second half of the year as was the case in our electric utility.

We also benefited from rate increases including a $20 million increase implemented in Arkansas in November 2007.

Unfortunately the benefits of customer growth and rate increases were substantially offset by reductions in customer usage.

We continue to pursue rate mechanisms to decouple revenues from the volume of gas sold to help mitigate the trends of reduced customer usage.

In our Texas Coast jurisdiction gained approval for an annual cost of service adjustment mechanism to recognize changes in usage, operating cost and rate base.

For the last two winters we've entered into weather hedges for our Minnesota and Texas jurisdictions to mitigate weather related usage risk.

Most of our other jurisdictions have some sort of weather normalization or other adjustment mechanisms.

This past November, we filed request with the Minnesota Public Utilities Commission, to increase our Minnesota rates by approximately $60 million, and as part of the filing asked to decouple revenues from the volume of gas sold.

We implemented a $51 million interim rate increase last month subject to refund.

We do not expect final action on our request until late this year, or early 2010.

I would also add that the recent decline in natural gas prices could reduce the amount of rate relief we need in Minnesota if gas prices stay at current levels or fall even further.

Our competitive natural gas sales and services segment reported operating income of $62 million, for 2008, compared to $75 million, for 2007.

Operating income in 2007 reflected almost $24 million more in gains from sales of gas inventory, while in 2008 our operating income increased by approximately $12 million, due primarily to favorable locational and seasonal price differentials.

In 2008 we also recorded $30 million in writedowns of natural gas inventory to lower of average cost or market, compared to $11 million in the inventory writedowns in 2007.

In addition we recorded mark to market gains of $13 million, associated with derivatives we used to lock in economic gains, compared to charges of $10 million in 2007.

Overall our energy services business had a pretty solid year.

Now let me turn to our interstate pipelines unit.

Our interstate pipelines recorded operating income of $293 million for 2008, compared to $237 million for 2007.

Higher income from our Carthage to Perryville pipeline and increased transportation and ancillary services offset higher operating expenses.

Operating income also benefited from an $18 million gain from the sale of two storage development projects offset by a $7 million charge associated with pipeline assets that were removed from service.

In September, the Southeast Supply Header or SESH our joint venture with Spectra was placed in commercial operation and flowing gas primarily to the Florida markets.

SESH is well positioned to serve the Southeast market and there are future expansion options if warranted by market demand.

In 2008 we recorded equity income of $36 million, which included $33 million of allowance for funds used during construction for our interest in SESH, depending on the timing and cost of permanent financing, we expect equity income from SESH to be somewhat less in 2009 than in 2008.

Now let me turn to our field services segment.

We reported operating income of $147 million for 2008 compared to $99 million for 2007.

This business unit benefited from strong drilling activity and increased production in the Mid Continent area in 2008, when it connected a record 475 wells.

Our fuel services business also benefited from the expansion of our jointly owned natural gas processing facilities.

We recorded equity income of $15 million, from this joint venture driven by strong liquids prices compared to $10 million the previous year.

In addition, operating income for 2008 benefited by $17 million from the sale of nonstrategic assets and the settlement of a contractual dispute and by a gain of $7 million associated with system imbalances.

Taking into account the performance of all our business units, I believe the Company had a very solid year and I believe 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 2009.

While we expect this year to be even more challenging than 2008, we also believe that the combination of the stability provided by our regulated electric and natural gas utilities and high level of activity in a number of producing areas served by our pipeline and field services businesses should allow us to achieve solid performance across our various business units.

We expect Houston Electric to continue to perform well, we anticipate that our customer base will grow at a pace comparable to the level experienced in the second half of 2008, but below the rate for the full year.

In addition, we expect to realize an incremental $15 million from the full year impact of a transmission rate increase implemented in November 2008.

Our capital expenditures are budgeted at $422 million.

Including approximately $82 million related to our advanced meter deployment.

In our natural gas distribution utility, we should see the benefits from rate increases including the interim rates in Minnesota, as well as continued expense control measures.

We expect to see customer growth but at levels below those we experienced in 2008.

The real unknown is whether we will continue to see our customer usage decline at the same rates as 2008.

We will maintain our focus on rate decoupling strategies and on operational efficiencies in order to mitigate the impact of reduced customer usage.

Our capital plan for 2009 of $155 million, reflects a decline in capital spending of over 25% from 2008 levels.

We expect our base commercial and industrial sales business to perform at a level similar to 2008.

Early in the year we've seen some positive pricing differentials particularly on seasonal spreads.

Our focus is to continue to expand our customer base while maintaining our low risk profile.

The ability of our interstate pipelines and field services businesses to duplicate their 2008 performances will depend on market dynamics, natural gas prices and natural gas liquids prices.

Nearly 80% of these segments revenues are either capacity payments or fee based providing a significant amount of stability.

The remaining revenues are derived from ancillary services, system management, our gas processing, all of which are dependant to some degree on commodity prices and market dynamics.

Based on the current commodity indices, we don't expect these revenues to be as robust as they were in 2008.

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

This is driving opportunities for both our pipelines and field services.

In December of last year we filed an application with the FERC requesting authorization to increase the capacity of our Carthage to Perryville pipeline by approximately 274 million cubic feet per day through installing additional compression.

This expansion which would increase Carthage to Perryville's capacity to almost 1.9 billion cubic feet per day could be in service by the second quarter of 2010 pending FERC approval.

Our pipelines capital budget will be approximately $200 million, down significantly with the completion of SESH but otherwise comparable to 2008.

Our capital budget for field services is $277 million, for 2009, more than double our 2008 capital expenditures and reflects our success in securing new projects in the shale areas.

In summary, our core businesses provide a significant amount of profit stability, and we continue to invest in new projects that are expected to provide for increased profitability in the future.

We expect to invest almost $1.1 billion this year.

In closing I would like to remind you of the $0.19 per share quarter dividend declared by our Board of Directors on January 22.

This is more than a 4% increase over the dividend we paid in 2008, and the fourth consecutive year that we have raised our dividend.

We believe our dividend actions continue to demonstrate a strong commitment to 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

Thank you, David.

Good morning to everyone.

I would like to discuss a few items with you this morning.

First let me describe the process we are pursuing to recoverer or cost related to hurricane Ike.

The Texas legislator convened last month, we are seeking enabling legislation similar to that which was passed in 2006 following Hurricane Rita, such legislation would provide the legal basis for us to issue nonrecourse storm cost recovery securitization bonds similar to the 3 series of transition bonds the Company has issued in connection with its stranded cost recovery.

The legislation would authorize the Texas Public Utility Commission to review or storm restoration cost and issue a financing order.

Earlier this month Governor Perry designated emergency items for the 2009 legislative session and included in those items was legislation to assist entities in recovering from the 2008 hurricanes.

This emergency designation allows lawmakers to begin considering these issues early in the legislative session and bills addressing this issue filed in both the Texas House and Senate.

Storm cost recovery securitization bonds would have the dual benefit of allowing us to recover our Ike cost in a timely fashion while lowering the ultimate cost to our customers.

We believe that this securitization method of recovery has the support of state and local officials including the Public Utility Commission.

We expect to file with the PUC in March even if the legislation has not yet passed.

We hope to be able to complete the regulatory process and issue bonds later this summer.

I would now like to address our liquidity.

On our last earnings conference call in early November, I told you that in light of the continuing disruptions in the capital market and the incremental liquidity requirements imposed by hurricane restoration work we were taking additional steps to further strengthen our liquidity position.

First I said we were in the process of amending our parent Company credit facility to in effect exclude the storm cost from the financial covenant calculation, by increasing the permitted ratio of consolidated debt to EBITDA by 5.5 times.

The ratio would revert to 5 times at the earlier of December 31, 2009, or when we receive securitization proceeds.

We successfully amended the facility in November, the amendment also makes clear that any nonrecourse storm cost securitization bonds that are issued will not be treated as debt for purposes of the covenant.

Second, I said we were working with our banks to syndicate a new $450 million, 364 day revolving credit facility at Houston Electric.

We successfully negotiated this new facility, which was upsized to $600 million.

We put this facility in place to provide additional liquidity if needed.

At this point we do not anticipate the need to draw on this facility but we think it is prudent to have a backstop facility in place for the next year as protection in this period of continued volatility and uncertain access to the capital markets.

In addition to the revolving credit facility last month CenterPoint Energy Houston Electric issued $500 million of general mortgage bonds due in 2014 with an interest rate of 7%.

I also explained on the call that search receivable facility expired on October 28.

Due to the disruption from Hurricane Ike the due diligence process necessary to implement a new facility was delayed for a few weeks, we successfully closed on the new receivables facility on November 28.

Availability under the new 364 day facility ranges from $128 million, to $375 million reflecting seasonal changes in receivable balances.

These are among the steps we have taken to ensure that we remain in a very strong liquidity position.

As of February 24, CenterPoint Energy had unused capacity of over $2.5 billion, under its various committed credit facilities.

Let me also point out the consolidated group has no material debt maturities until September of 2010, when $200 million of parent Company debt comes due.

We also continue to work with our joint venture partner Spectra Energy on a permanent financing for the SESH project which was placed into service last September.

Once we can access the capital markets in an efficient and cost affective manner, our intention is to do so.

In addition to financing actions I just described we continue to look internally for ways to enhance liquidity position while improving and growing profitability of our businesses.

Our business performance remains solid and generates significant operational cash flow, and we are focused on efficiently managing our working capital.

We will continue to prudently allocate capital to our regulated operations and to value creating opportunities in our pipelines and field services businesses.

As David mentioned our capital budget for 2009 is approximately $1.1 billion.

Permanent financing to fund our capital program will consider the optimum mix of debt and equity consistent with maintaining and enhancing the credit metrics and credit ratings of bot the parent Company and our subsidiaries, consistent with this plan today we filed with the SEC to offer up to $150 million in common stock through a continuous equity offering program, sometimes referred to as an at the market or equity dribble program.

The total amount of equity that we would issue under this program during 2009 can vary depending on market conditions and other factors.

This equity is in addition to the amount of equity raised annually through our employee benefit plan and our investors choice dividend reinvestment plan which was approximately $80 million in 2008.

We have chosen a continuous offering program to maximize flexibility in these volatile markets in terms of how much we issue and over what time frame.

Before I review our earnings guidance for 2009, I would like to discuss the expected impact of pension expense and potential funding requirements associated with our pension plan.

We, like many other pension fund sponsors have experienced a significant decline in the value of our plan assets in 2008.

As a result of decreased asset value as well as changes in plan design and assumptions on the rate of return and discount rate our non-cash, pretax pension expense increase for 2009 is estimated to be $88 million or $0.16 per diluted share.

However, in terms of funding we are not required to make a cash contribution to our pension plan in 2009.

This leads me to my final topic, our earnings guidance for 2009.

This morning in our earnings release we announced that we expect our 2009 earnings to be in the range of $1.05 to $1.15 per diluted share.

This guidance range includes two significant items.

First, as I just mentioned, we will have a non-cash pension expense increase for 2009 of approximately $88 million, or $0.16 per diluted share.

Second, we expect higher interest expense of at least $0.08 per diluted share from the amortization of fees related to Houston Electrics new $600 million credit facility and interest expense on Houston Electrics $500 million general mortgage bonds issued in January.

In addition, our 2008 diluted earnings per share included approximately $0.07 of favorable nonrecurring items in our interstate pipelines and field services businesses.

In providing our guidance we also considered various economic, operational and regulatory assumptions including recovery of costs associated with Hurricane Ike.

We assumed normal weather in the gas and electric utilities and we have not attempted to predict the timing effects of mark to market or inventory accounting on the earnings of our competitive natural gas, sales and service business.

These affects are timing related and ultimately do not impact the economics of the underlying transactions.

Now, let me thank you for your interest in the Company and I will turn the call back to Marianne.

Thanks, Gary.

With that we will now open the call to questions.

In the interest of time I would ask you to please limit yourself to one question and a follow-up.

Would you please give the instructions on how to ask a question?

Thank you.

At this time we will begin taking questions.

(Operator Instructions) Thank you your first question comes from the line of Carl Kirst of BMO Capital.

Good morning, everybody.

Gary can I just focus on the pension expense for a second, is it possible to break that up as far as what you think would fall under possible regulatory allowances versus something that might be associated with the field services or something where it would be up to the parent Company unfortunately to have to swallow?

Okay.

Carl, this is Gary.

About 87% of that increase in the expense will go to gas and electric, certainly during that -- going forward certainly as we seek rate relief that will be considered in those filings.

And just hit sort of on the second question, is with respect to looking at CenterPoint Electric if I recollect correctly the next time you file you use a 2009 test year does the higher pension expense certainly what we are generally seeing with the economy and usage, does that make for a more accelerated filing early 2010 or can you help us out with what your thoughts are at this point?

Carl.

I don't think we can file on the accelerated basis but I think it probably makes it more certain that we would file.

There is a provision that we wouldn't have to go in and file that but if we see these kinds of cost increases and if we are not earning our return we clearly will file as soon as we can in 2010.

Second to follow-up, second question on the midstream I guess I want to get more clarity to the extent you can give it.

What you are assuming guidance with respect to volumes I guess I'm trying to make sure I understand what your expectations are on organic versus what looks to be a fairly robust spend in 2009 relative to prior years?

You talking about throughput primarily?

Yes.

Throughput we expect higher throughput in '09 than we did in '08.

What we are seeing now in the more traditional basins is a reduction in drilling.

But we are seeing a very robust drilling in the shale areas, which is going to more than offset some of the declines we will see in the more traditional basin, so we are assuming a higher throughput in '09 than we saw in '08.

Having said that Carl as you know field services does have some commodity exposure on two fronts.

One, on our typical gathering contracts we have some incentive provisions which if we can run our equipment efficiently we get to basically earn some gas that we sell, and we do that every year.

And then in our processing plants in our jointly owned plants that's, we are exposed to natural gas liquids prices there.

We have made some assumptions in our plan that prices are going to be down fairly significantly for both natural gas and for liquids.

We think there is still some downside there, we are not at the -- we didn't assume the prices we are seeing today and we could see another 10 million or $12 million of potential downside pressure on field services if prices would fall further.

In your assumptions for 2009 you assume that prices could actually decline a little bit more than from where they are today?

Can I understand that?

No, if they do decline.

We made some certain assumptions about price decline.

We weren't as clairvoyant as we should have been I guess and we didn't hit it exactly right, gas prices and liquid prices fallen a little bit further than we thought.

But we think, if they stay where they are, we can still make this plan but there is some downside there I wouldn't want to say there wasn't.

Okay.

Thank you.

Your next question comes from the line of Lasan Johong with RBC Capital Markets.

In your guidance of a $1.05 to $1.15 I'm assuming you've got some share count dilution in there from the $150 million in equity issuance you plan to do.

Can you let us know what that might be?

Well, on the share price, we announced this morning, as I said, $150 million, and I also gave you another number, which is the benefit plans in our dividend reinvestment plan last year we raised $80 million of equity through those so you could assume those two.

But you're not going to assume a price for us so we can figure out the share count?

I don't think so I don't think that would be appropriate.

Fair enough.

Also in the current economic conditions, you had a lot of smaller projects that you could have executed on to push the growth beyond say like the 4 or 5% range.

Are we going to see a slowdown in some of the activity going forward?

Lasan are you talking about field services and pipelines area?

Yes yes.

We continue to see a lot of activity related to the shale areas.

So I think we are -- we are pretty bullish on and obviously gas prices have been falling and most of these producers are hedged for '09.

I think they are keeping their drilling programs up.

So far the shale areas we haven't seen any diminution.

We have seen some in the traditional basins.

I think if you look at our capital budgets for both pipelines and field services and together it's $477 million, we see we have a fair amount of opportunity still in those businesses.

Right, but what about beyond '09?

Yes.

We continue to plan beyond '09.

We do continue to see this ongoing level of activity but it's going to depend a lot on gas prices.

In the shale areas we know that producers are drilling because they sunk a lot of money into these leases and they got to drill or they are going to lose them.

But at some price maybe they wont.

I think at the prices we see today they are still going forward with their drilling programs.

One last question, Gary, do you expect continuing pension funding going forward or do you think this is it for a while?

Well, in terms of, let me break that down.

In terms of pension expense we've given you those numbers as I mentioned in my prepared remarks there's no funding requirement for the Company in 2009.

I think at this point I don't want to predict 2010, it depends on the factors in 2009 or the asset performance and other factors.

So I think we have to wait and see, but certainly for 2009 no funding requirements and we like other companies are hopeful that the markets continue to improve, the equity markets and markets in general.

So hopefully that will happen, we will just have to see towards the end of the year but we will keep you informed of how that progress.

Thank you very much.

You're welcome.

Your next question comes from Barry Klein of Citigroup.

It's actually Faisel from Citi.

Going back to the equity for a second.

Is this -- besides giving you some flexibility, do you have -- you have to do this equity or is it related to rating agency issues or is it related to you keeping the powder dry for maybe opportunities in the asset side you might see?

And wanted to understand the rationale behind the equity.

Well, I think the rationale behind any equity issuance or any debt issuance is the appropriate capital structure and what we looked at, we just described to you this morning $1.1 billion capital program we think in terms of permanent financing it's important to have the correct and right mix of debt and equity that's the driver for our debt financing or equity financing in this case.

I think it's really the -- it's not an issue around pressure from anyone other than to do what should be done in good corporate finances to have the right balance sheet that supports these businesses.

We have very good opportunities, we want to continue to execute those businesses against those opportunities and certainly there is a equity component in terms of our financing plan.

On the cash tax side, with the AMO roll out and the stimulus package, what kind of benefit on the cash side are you guys expecting with this sort of thing or is there a benefit with the AMI rollout--?

There is really not.

Faisel, I think there is a very de minimus amount of cash outlay, something like 20 million, $25 million net in '09.

That probably grows a little bit in the outer years when we get in to the full swing of the deployment.

It's not going to have a significant cash drain on the Company because we are collecting a lot of dollars as we go along.

But having said that as a result of that we are not going to have a big impact on earnings either because we are not going to have all that much invested in this business to earn on.

There is no -- do you guys have any P&L on the potential tax benefit, the stimulus package going to depreciation that sort of stuff?

We haven't, and that would probably improve, it will obviously improve a little bit what I just talked about.

One last question, on the fuel services side you said $275 million in CapEx; is that right?

Yes, 277.

That's a big jump from what you guys did in '08 just field services.

What specifically are those projects related to?

A little more color on that.

They're really related to the shale plays.

We had some very good relationship with very good customers in those shale plays, and they've asked us, we are very pleased to help them get that gas to market.

Those are really shale plays.

We do have some compressor optimization dollars in there where we are moving more to ownership of compressors rather than leasing them, there is probably $40 million or so in there for that kind of program.

It basically improves our ability to serve our customers better and control our fate, but we have had some of that all along each of the last couple of years but I think there is 40 million or $50 million of that kind of expenditure in '09 as well.

Your next question comes from the line of Steve Gambuzza of Longbow Capital.

I want to clarify one thing you had said earlier about the amount of revenues to come from fee based versus ancillary services within field services and interstate pipelines.

I believe you said roughly 80% of the combined revenues in the two segments are fee based in nature and 20% have some element to commodity sensitivity, is that right?

That's right.

That was the combination of pipes and field services that's right.

I guess--.

You have a little higher, not quite as high as field services.

There is roughly $700 million of revenue that you reported in 2008 between the two segments.

More like $800 million.

$800 million excuse me.

And so historically I think you talked about somewhere around $30 million park and loan revenues in interstate pipelines and the field services I think has been historically described as being essentially all gathering based, I was surprised, 20% of the 100 is almost in excess of $150 million of revenue.

I was wondering if you could provide more color as to exactly what those revenue streams are, and you mentioned incentive fees for efficiency and field services, how much is that?

All our contracts on the gathering side are fee based but in sight of those fee based contracts you have a incentive piece in there where you have some natural gas exposure.

It's all around the efficiency of running your compressors and to the extent we can run our compressor more efficient than what the contract calls for then we get an upside in that.

We worked very hard over the years on that and we are continuing to enjoy the benefits of that kind of efficiency.

So that's part of it.

These are fee based contracts but almost every gatherer has this kind of provision it's not unusual for us.

Can you give some sense as to how much incentive benefited '08?

Probably on the order of $40 million probably.

That's not all -- that's kind of our natural gas exposure.

Within field services.

Yes.

Exposure within field services.

Then there would be like another kind of 30 to 40 of park and loan revenues in the pipe.

Is that somewhat accurate?

That has been a level that historically has -- that we probably a little less than that, but that -- we are not counting on that much pals going into '09.

Besides those two buckets is there some other area of commodity sensitivity that would take us to that 20% level beside what you just talked about?

There is a few things.

There's system management, we have straddle plants on our pipeline where we treat gas before we put it into the pipeline system so it's pipeline quality gas and as part of that treating process we keep some of the liquids, that's part of that.

Okay.

Let me think if there is -- there is probably some cross system fees that we include in there also.

Very helpful.

Switching I guess for a moment, the CapEx that you earmarked for 2009, also it looks like a fair amount of CapEx that's earmarked for 2010 in the 10-K relative to historical spending levels.

Do you have contracts on -- with shippers for the 277 that you have earmarked for 2009?

Substantially all of it.

Okay.

Yes we do, now there is some greenfield in there.

What we call greenfield, which are undesignated and will get contract as we go go through the year, but a substantial part of that we have contracts for, yes.

Now we work with our producers very closely to make sure there is not a change in their drilling schedule so we are not going put in a bunch of facilities early and have them sit idle for a while and not get any revenue from them.

We feel pretty strongly that this level is the right level, but we are watching it very closely as you would expect.

And you said about all but like $50 million of the CapEx is going to the shale areas?

There is some other system kind of maintenance capital and things like that we have been drilling in these basins for a long long time, and there is continued some maintenance capital in there, but all of the new growth capital, I would say, is in the shale areas, almost all of it.

We are going to still see some wells drilled in these traditional basins but just not at the pace we've seen in the last four years.

We used connected over 400 wells a year for at least four years and last year we connected 475 wells and a lot of those were in those traditional basins.

That is going to cut back, we know that, we've seen it, what we are seeing though is we are having a pick up in the shale areas and a well produces a lot more per well in the shale areas than in these old traditional basins.

Finally, you had a very high return on invested capital and field services for quite sometime and looks like you are expanding your asset base by almost a third with the capital plan that you have going forward in 2009.

Do you have -- it seemed like there are some puts and takes in terms of some of these incentive fees which may fall off versus all the CapEx going in.

Volumes being up.

Do you have some sense as to where you think your returns on invested capital might be in 2009 relative to 2008?

I'd hesitate to say, I don't think we are going to see a significant decline, there may be some, but we are not anticipating a significant decline and returns on this invested capital.

We are seeing producers starting to -- want us to invest more now.

A lot of producers used to do a lot f this gathering themselves, and I think they are looking to us more to do some of the things that maybe their own internal operations would have done in the past.

So that's giving us a few more opportunities than we have had but from a return standpoint I don't think we are going to see a significant decline in returns.

Thank you very much

Still very attractive projects in our mind anyway.

Thank you for your time.

Your next question comes from the line of Danielle Seitz of Seitz Research.

I just was wondering, wanted to ask about how do you see your request for rate release?

Do you anticipate to file for the recovery of the storms very quickly or do you visualize going for a full fledged rate case based on the fact that you're expanding your equity base, et cetera?

No, we expect to file in mid to late March with the PUC to recover our storm cost.

And then following the legislation that Gary described which would allow us to securitize those costs we are going to ask the PUC to issue a financing order and then we're going to go sell securitization bonds and recover our money and our hope is sometime this summer or maybe late summer, but that's our plan is to get this money back this year.

And you don't anticipate to file for a -- regular rate case for a distribution part of the business?

Not in connection with the storm, we are under a rate freeze now.

We cannot file until next year based on a test year based on end of this year.

We will be watching that and looking at it very closely as you would expect to see when to file but we've had some cost increases here with our pension, which we noted earlier.

And that would tend to make us go in earlier rather than later.

But we are just going to have to wait and get all the numbers in and make sure it's worth filing.

Great.

At this point, what is your ROE on the electric side; do you have a number?

I'm sorry?

The ROE for the Corporation?

It's probably, the ROE authorized is a little north of 10%.

I think that was a settled case.

There worse was no stated return in it.

My guess is that is a fair number.

You're not far from it.

Based on your 2009, estimates?

We think that '08 produced a ROE in the range of 10%.

Okay.

Just one last quick question, O&M pretty robust in '08, do you see roughly the same type of increase in 2009?

Or are you paring down?

What happened in 2008 to a large extent is we had a large amount of transmission costs billed to us from others.

The reason that happened is for two reasons one is there was a fair amount of transmission built by other utilities, they raised their transmission cost factor.

The second is that the way transmission works in Texas, is that we bear a given portion of all of the transmission costs in the state, and our portion, our percentage went up in '08, above '07 because the peak demand in our area was higher relative to the rest of the state than it was in the previous years.

That will move around.

Our guess and our hope is that it's going to go back down to a more normal level which is probably in the 23, 24% level it was above 25% in '08.

So our hope is that we are not going to see those type of increases.

We did file for a transmission increase of our own based on these increases in factors other utilities or charging us.

But the other part which we call the load ratio share we can't file for that until we go in for a general rate increase.

So if that comes down we would get a benefit but our hope is that we are certainly not going to see another $22 million or so which is what the increase was in '08.

That was the biggest part of our O&M increase.

Thanks a lot, appreciate it.

Your next question comes from the line of Yiktat Fung of Zimmer Lucas Partners.

Good morning first of all I have a question about the (inaudible) equity issuance plan, is there an expiration date on this filing?

No, there is not.

This is Gary.

So it could basically -- if you don't finish with the 2009, it could go 2010 or even '11?

Look I'm limited to what I can actually talk about regarding the program.

Your expectation is it would be 2009.

Okay.

So you expect to issue all of it during 2009?

Or is that correct or?

I think Gary is right, we have this thing out there, it doesn't have an end date on it but we don't file it without the intention of somewhat executing against it.

Whether we get it all done in '09 only time will tell, I don't think we can give you much more color than that around it.

You talked about before about targeting an appropriate balance sheet are there some credit metrics or some sort of debt ratio that your Company targets?

Overall these are investment grade businesses we are going to continue, and we have done that over the last number of years to improve our credit metrics.

FFO to total debt greater than 15% and greater than 3 times interest coverage, so we are strong in the utilities and overall we're going to continue to move those directionally to improve them.

And as I said earlier this capital program as we look at permanent financing requires a portion of it to be equity and a portion of it to be debt.

This is a good, we think this is a good tool with a very volatile capital markets, we think the continuous offering program is a good tool to have in our tool box to raise equity and of course we have, as I mentioned, our dividend reinvestment plan as well as our benefit programs that we continuously raise equity with.

Okay.

With regards to the 2009 guidance, is there some way that we can think about breaking out the earnings into the segments?

We don't give segment guidance, we only give Company guidance.

Okay.

Can you at least comment on it directionally?

Are the utility earnings higher or lower?

I tried -- I tried to do that, maybe I didn't do a very good job as I went through my prepared remarks.

Talking about each of the segments and what we expected.

I think probably directionally if you just kind of listen to those remarks I think you would see where we are headed.

All right.

And finally, just to clarify one point.

The transmission cost at Houston Electric they don't get passed through directly to -- the higher cost don't get passed through directly to customers you file to get recovery of it?

Well, we can change our transmission cost recovery factor twice a year.

But that can only reflect a higher cost to us from an increase in a factor or our own transmission cost.

It does not reflect and cannot reflect an increase in the overall load ratio share of Houston Electric, that you do on general rate case.

Like we file for a transmission rate increase of I think we got $17 million or -- in November of last year and that was to reflect these increased costs that we are seeing.

But it doesn't cover all of the increased costs.

I see.

Thank you very much.

Okay.

Your next question comes from the line of Debra Bromberg of Jefferies and Company.

Increased pension expense you are expecting in 2009, could you tell me roughly how much of that would be associated with the electric company?

Let's see, I think we can do that.

And also the 10% roughly 10% ROE the electric company earned in '08 what kind of common equity ratio is that based on?

40% equity, 60% debt.

Was that actual or is that the hypothetical?

That's a hypothetical.

It probably has just a tad higher than that, my guess it's not much higher than that but we try to keep those ratios pretty consistent with the ratios that rates are set on, but it may be a tad above that.

And just one quick question on Hurricane Ike cost recovery if you get a PUC order by year end do you expect to book catch up carrying charges later in the year end and if so is that included in guidance?

We are going to ask, I think for carrying cost as part of this filing.

Which is consistent with what Entergy did in the 2007 or '06 and consistent with what they received.

But the way that will be realized in earnings is over the life of the bonds themselves.

I don't think there is a--.

There is a debt component and an equity component but to answer your question Debra, we don't have that in our guidance.

Because we don't know how that's going to play out and as I said in my comments there's certain factors where we take into consideration, and that's one we can't predict at this point.

Okay, just to follow-up on that pension question?

About 47 -- about 47% of the total.

As I mentioned is in electric.

Great, thank you.

Your next question comes from the line of [Carl Selliston] of Utility Financial.

Good morning.

I was wondering in your discussions with the banks as you went for your new line, was any indication from any of the banks that have been in the prior line, particularly with the leaves that they were having problems relative to everything we are hearing and reading about or are they just willing to write lines regardless and hopefully accept your execution of them when you need the money?

Well, I think it's a combination, it's a good question.

Certainly when we started the indication in that facility, it's $450 million, and we upsized it to $600 million, which I think speaks volumes to the support we had from our bank group.

I think in aggregate, certainly each -- there was at that time significant angst in the bank credit market.

No doubt about it.

Our banks, we have a longstanding relationship with them, they looked at this facility and understood two things.

One, it's a secured facility at Houston Electric and the banks stepped up, understood that, clearly it was priced appropriately for the market at that time.

And so we are pleased that it was upsized from 450 million to $600 million.

I would be less than candid to say otherwise in terms of there was a lot of discussion because the banks were going through their own issues at the time.

We are very gratified with the facility obviously.

When you say priced appropriately, I assume that means that higher levels the way prior credits have within priced?

That's correct.

It would be at higher levels and as this is all filed you can take a look at it.

Basically if drawn it's 2.25 over 2.25 over LIBOR then it has a fee associated, if you are drawing it actually ratchets up.

But as I said, we don't expect to draw on the facility the backstopped credit facility from our perspective.

No, I've just been hearing around the banking community of banks -- you don't make any money in writing a line like this.

You make it when it's exercised.

Therefore they're not happy with the prices that they charged in the first place.

Look it was more expensive than certainly traditional but our banks, as I said, we have a long-term relationship, they understand our business.

They serve these communities and so we were gratified that they stepped up.

Okay, thanks.

We are a little bit over our time but I think we will allow one more question.

Your full-time question comes from Carl Kirst of BMO Capital.

Just very quickly, hopefully end here on a good note.

The CP expansion, the phase 4 the $274 million, obviously Haynesville is exploding whether you have contracts or not.

But the question is os do you have contracts for that 274 and can you give us a sense of what the cost of the added compression is and presumably the rates you are going to get on that will be full tariff rates.

We are close to having a anchor shipper that will take a lot more than typical anchor shipper would take.

The filing we made with the FERC was about $70 million capital spend on that.

So we are very close on getting that contracted.

Can you remind us what full tariff rates are?

For CEGT it's -- well, let's see, what is our MAC rate, $0.25 is CEGT.

It's just part of, this is part of the our CenterPoint Energy Gas Transmission system.

Okay, thank you.

Okay.

Thank you very much.

Thank everyone for participating on our call today, we appreciate your support very much.

Have a good day.

This concludes CenterPoint Energy fourth quarter and full year 2008 earnings conference call, thank you for your participation.