威廉斯 (WMB) 2007 Q3 法說會逐字稿

Good day everyone and welcome to the Williams Companies third quarter 2007 earnings results conference call. Today's call is being recorded. At this time for opening remarks and introductions I would like to turn the call over to Mr. Travis Campbell, head of Investor Relations. Please go ahead, sir.

Good morning everybody. Welcome to our third quarter earnings call. As always, thank you for the interest in the Company. I know many of you have a lot of calls to monitor this morning so we will get right to it. Steve Malcolm, our CEO, will lead it off, followed by Don Chappel, the CFO. Ralph Hill, Alan Armstrong and Phil Wright, will also make some brief remarks.

Before I turn it over to Steve please note that all the slides are available on our website, Williams.com in a PDF format. The press release and the Company's schedules are also available on the website. And this morning we also filed our third quarter 10-Q. Slide 2 and 3 entitled, Forward-Looking Statements, detail risk factors and uncertainties associated with future outcomes. Please review the information on that slide. And also, slide 4, Oil and Gas Reserves Disclaimer, is also important and we urge you to read that slide as well.

Included in the presentation today, as usual, there are various non-GAAP numbers that have been reconciled back to generally accepted accounting principles. Those schedules follow the presentation and are integral to the presentation. With that, I will turn it over to Steve.

Good morning and welcome to our third quarter earnings call. We certainly appreciate your interest in our Company. We had another outstanding quarter, and our core natural gas businesses delivered very strong performances across the board.

Starting with slide 6, I am sure you saw the numbers for the third quarter, our adjusted earnings per share increased 44% to $0.39 from a year ago. Our 2007 picture is getting even brighter as we're bumping up the full year earnings per share guidance by 18%. We expect 2008 earnings to show strength even in a less extraordinary pricing environment. Clearly we are and have been in a robust commodity pricing environment for much of this year. The fact is that for '07 we have been short gas in the Rockies and have taken advantage of the very low prices in that region. However, we would expect that the situation to change somewhat when the Rockies Express Project goes into service.

We look for approximately 15% natural gas production growth in 2008. And Ralph Hill will provide more detail on our outlook here in a few minutes. And we expect to commit more capital to develop our opportunity rich portfolio.

A key theme for Williams, and one that I have stressed often, is that our businesses provide an abundance of organic growth opportunities. That is important to this business, where you see many companies looking to acquisitions to find the growth that will fuel their futures. For Williams much of that growth is well within our reach.

We continued to make progress with respect to other steps being taken to deliver value to our shareholders. I am sure that you noticed that Williams Pipeline Partners filed an amended S1 on Monday this week. And among other things the latest filing includes the expected IPO price of $19 to $21 per unit. As you recall, the pipeline MLP consists of a 25% interest in our Northwest Pipeline. At this stage in the process there is really very little more that we can share about our MLP beyond what you can obtain for yourself in our public filings with the SEC.

We continue to execute on our strategy to drop-down assets into our Midstream MLP. We announced this morning that we have signed a nonbinding letter of intent for Williams Partners to acquire an ownership interest in the limited liability company that owns the Wamsutter system from Williams for $750 million. Alan Armstrong will have more to say about that transaction here in a few minutes.

We're delighted with the progress that has been made on the sale of Power. We have received substantially all consents, and we are now -- we now expect to close the Power sale to Bear during November, and possibly as early as next week.

Finally with respect to the share repurchase, we are off to a strong start, more than 7 million shares during the third quarter at an average purchase price of $31.40, which certainly feels even better today than it did at the time. We're committed to continue execution of the $1 billion program the Board authorized.

Turning to slide 7, which addresses our third quarter strength. I think the quarter was driven obviously by strong NGL margins. We obviously took advantage of the Rockies basis anomaly which created extraordinary processing profits for Midstream. And our transportation and hedging strategy insulated E&P from the challenges that many Rockies producers suffered and continue to suffer as a result of the basis blowout. This highlights the fact that we have stressed many times that we are a Rockies producer, not a Rockies price-taker with just 7% of production exposed to Rockies prices.

Our E&P production outpaced year ago third quarter by 17%. And our new rates on Northwest and Transco continue to drive an increase in Gas Pipeline results.

A couple of points on slide 8, which shows actual segment profit in 2005 and 2006 and forecasted full year segment profit for '07 and '08. The expected uplift from the extraordinary pricing environment that we are experiencing this year is the orange striped block at the top of the 2007 bar on this chart. But even if you would normalize prices for 2007, we would still end up with very impressive 15% growth compared to 2006 levels.

Then we show the guidance range that we're forecasting in 2008. I would encourage you to please take a look in the appendix at a summary of our commodity price expectations that are reflected in this 2008 guidance.

Compared to our 2007 assumptions, we are expecting 2008 to have stronger natural gas prices in the Rockies and elsewhere, higher crude oil prices, but a lower crude to natural gas ratio, which of course drives our processing margins. With that I will turn it over to Don.

Good morning. Let's turn to slide number 10, Financial Results, and I will run through all of these very quickly. Focusing on the bottom line our key earnings measure, the recurring income from continuing ops after mark-to-market adjustments on a per share basis, you can see the increase there of $0.12 over the prior year, or 44%, and the same rate of increase, 44%, on a year-to-year basis.

Next slide please, number 11. This is on both a reported and recurring basis. The non-recurring items are detailed on a slide in the appendix, as is the mark-to-market adjustment. Overall segment profit after mark-to-market adjustment is up $129 million, or 27%. E&P is up about 17%, consistent with our production increase. Midstream is up 29% on the expanded NGL margins, and Gas Pipeline is up 57% on the strength of that rate case.

Gas Marketing Services, which was formally a part of the Power segment provides Gas Marketing transportation storage services to E&P at Midstream and manages certain contracts related to the former Power segment. These former Power sales contracts will result in some earnings and mark-to-market volatility until such positions expire or are sold.

Next slide please, number 13. On a year-to-date basis, again focusing on the recurring results, segment profit after mark-to-market adjustment up $1.721 billion, up nearly $400 million or about 28%. I will turn it over to Ralph.

Let's turn to slide 14. Our accomplishments, production and profit are both up 17% compared to third quarter '06. Also reflected in these numbers were some pipeline maintenance and curtailments that happened in the Rockies, which decreased our production by about 25 million a day. Without those maintenance and curtailments, production we have been up about 20% year-over-year and about 5% sequentially. And that just simply reflects the very tight Rockies pipeline network that is out there, which is expected to improve in '08.

Steve has already talked about that insulating our transportation portfolio insulates our E&P volumes from the basis blowout.

Turning to slide 15. This slide reflects our strong portfolio and our ability to grow organically. As you can see on this slide, each of our larger investment areas have had very robust production growth. In particular looking at the Highlands growth, it does have seasonal swings. So although we're very pleased with 25 million a day and up 98%, the growth is actually greater than that. And as we get into more year-round drilling we will have more steady growth. But our current production in the Highlands is up close to 40 million a day from this 25 million just reported for the third quarter.

Slide 16, this again reflects our dual strength of prolific Rockies reserves and production growth, which we can combine with our ability to sell our gas away from the Rockies. The key on this slide is 7% is priced in the Rockies, as Steve mentioned, which is in the middle of this slide. Our average net realized price after fuel use, transportation and hedge gain was $4.59. And that compares to the Rockies Indexes, as you see there on the bottom of the slide, of $2.90 and $2.90 for Northwest and CIG. And those do not include fuel and shrink, so actually you can see how much better we're doing because we're able to transport our gas away from the Rockies to other areas.

Slide 17, a guidance update. The difference in 2007 on the profit side is purely prices. They are down from our last call, as you have seen nationwide. Note our continued strong production growth offset some of this pricing decrease. Our speed of development strategy is allowing us to drill more than planned, which is reflected in our capital increase in 2007, and also reflects a greater production growth.

For 2008 we are raising guidance in each of our categories. Our profit is up by 5%, capital is up by 17%, and production is up by 6%. This again reflects our ability to turn capital investments rapidly into production and profit.

With that I will thank our employees -- slide 18. I would like to thank our employees for a great quarter and everything they do for us. And I will now turn it over to Alan Armstrong.

Starting here on slide 20. Our recurring segment profit of $300 million for the second quarter of 2007 beat the previous quarterly record of $248 million reported in second quarter '07. And the third quarter 2007 margins were also a record of $0.62 per gallon. And this is driven by our Rockies margin which actually reached $0.83 per gallon in September.

Additional profit assessing investments we have made certainly paid off, and have allowed us to maximize profitability. The key to our success in this area has been solid project management execution. Our team started up our 350 million a day train at Opal on schedule, and within 10% of budget in February of '07. Having this project start up smoothly and on-time has allowed us to realize these great margins. And it provided our customers with the reliable service they bargained for to keep their Jonah and Pinedale volumes flowing as promised.

We also have successfully integrated BASF's interest in the Geismar plant, which contributed nicely to our segment profit in this quarter as well.

And progress has been made in the Deepwater Gulf of Mexico. The Perdido Norte agreements were executed in the third quarter finally with the producer. A lot of very complex issues to deal with there, and we're happy to have that behind us.

Also, in addition as of October 10 agreements were signed to dedicate the Bass Lite gas reserves to our system. The Bass Lite is another tie back to Devils Tower, and will restore some significant Deepwater revenues that we lost this year as other Deepwater volumes declined as expected.

Moving on to slide 21. This graph shows the tracking of margins over the last five years. It also shows growth in our domestic NGL production. And in the light blue bar the amount of liquids we're producing for our own account, excluding discovery -- excluding our discovery in [Oxable] investments.

An interesting datapoint here is also the five year average margin of $0.22. As you can see, we saw margins of almost three times the previous quarters in the third quarter. The environment that drove record margins during the third quarter is certainly alive and well in the fourth quarter; however, we're not planning on these in 2008 beyond -- 2008 and beyond.

Several factors have worked together to create this extraordinary environment. First, the low gas prices in the Rockies caused by infrastructure constraints and very successful drilling programs in the Piceance, Uinta and Jonah, Pinedale Basins. With the addition of new gas transportation capacity out of the Rockies in the near future, we do expect gas prices in Wyoming and Colorado to return to historical norms.

Crude to gas ratio plays an important role as well. Since olefins producers have consistently chosen ethane over heavier feedstock, such as naphtha, it is putting tremendous upward price pressure on ethane, propane and some butanes. We anticipate some of this intense demand to be met by new processing plants in the Rockies and Barnett Shale that are announced to come on in service in 2008.

Moving on to slide 22. Given the year-to-date results, coupled with the strong margin environment outlook for the fourth quarter, we are proud to announce we have increased our 2007 segment profit from $700 million to $850 million, to $950 million to $1.125 billion. I think I like saying billions better there. So we're really excited about seeing this kind of increase. Similarly we increased our segment profit guidance for 2008, but moderately, by $25 million at the midpoint.

Capital spending for '07 remains unchanged at $650 million to $700 million; however, our 2008 capital guidance has been raised from $525 million to $575 million now to $650 million to $700 million. The increase is due primarily to an expansion of our Perdido Norte project, new developments in our Canadian Oil Sands opportunities, and several new expansion opportunities that are merging in the dynamic Western region.

The big driver in our 2007 to 2008 decline from our previous guidance forecast is a planned $350 million drop in NGL margins driven by higher natural gas prices. Also near 2007 and propane and heavier prices are contemplated here, but we expect ethane prices to lower by approximately 20% during this period.

However, if we saw a repeat of 2007 in terms of NGL margins, we would expect an approximate 5% increase in profits next year due to growth project like Bass Lite and our investment in BASF's interest in Geismar. And these will be partially offset by higher depreciation and O&M costs.

Moving on to slide 23. Here we are providing a reconciliation of the current guidance versus earlier guidance for 2007 and 2008. First, I will explain the segment profit guidance changes. Of course, a major factor increasing our segment profit guidance in both periods is NGL margins. Our outlook for NGL margins increased from approximately $0.40 per gallon to $0.54 per gallon for full year 2007.

In 2008 we have increased our margins by roughly $0.06 per gallon, reflecting the higher assumed commodity prices. Total year margin in 2008 is forecast to be approximately $460 million or $0.32 per gallon. This is about a $0.10 per gallon above five year average of $0.22 shown on the previous slide.

Also increasing segment profit guidance is higher margins in our olefins segment for both '07 and '08. This increase is driven primarily by higher margins forecasted at our Canadian facilities, driven by higher propane and butylene mix margins. Propylene and ethylene are fairly flat in our olefins business. And the price forecast that we have in our olefins business is based on the August 30 CMAI price forecast, if you track that.

Increased cost in 2008 reflect higher operating expense attributable primarily to additional overhauls being planned next year. We certainly have tried to limit any downtime on equipment this year with the high margins that we do have, but we will be having to take equipment down in '08 for overhauls. As well, we expect higher G&A costs required to handle the tremendous amount of new growth in the Canadian Oil Sands and Western region that is new to us now.

Lower volumes assumptions reflect the lower volume in the Four Corners where volumes were reduced by about 40 million per day due to a less aggressive assumption about well connects. Now we're not saying that our volumes are actually lower year-to-year by 40 million, we're simply saying that from our previous guidance forecast it is lower. Some of the difficulties out there that have caused us to back off a more aggressive forecast is some land issues on the Hickory Apache Nation and an inability to get on some of the -- our producers to get on to some of the Forest Service lands.

We also projecting some lower volumes in the Gulf Coast. Permian Anadarko's [Boom and new Manson] projects which flow into our [Eastbreak] system.

On the capital guidance side we also increased our gas capital guidance a bit from our second quarter. Primarily this was driven by the Perdido Norte project. We've got -- most of the increase is $40 million. The vast majority of that is covered by rate adjusters that we have with our customers out there, and were set in place to cover things like increase in ship construction cost and steel costs.

We also have some new opportunities out in the Western region. And they're quite a few small projects that I won't list here.

Moving on to the pie chart here, slide 24, this shows the backlog, if you will, of investment opportunities we have. Large Deepwater projects and Rockies opportunities, especially the Willow Creek project dominate the expansion capital and guidance for 2007 and 2008. These new opportunities, along with an expanded time horizon, have contributed to a $200 million increase in the in guidance pie. Specifically the expenditures represented are for all projects started in 2007 through 2012, and include all projected expenditures for projects started during that time line. So we have expanded the time horizon quite a bit here.

The under negotiation pie range has remained steady. The main differences involve the area in which the expenditures occur. Basically we have got volumes -- sorry, some of the projects moving from the Deepwater and into the TXP4 expansion at Echo Springs, and our Canadian Oil Sands.

The pie labeled in development and proposal reflects the tremendous amount of opportunities that we recently identified during our five-year long-range planning process. Examples include adding a couple of potential Deepwater projects to this category, and adding several new Canadian Oil Sands off-gas recovery projects.

The capital range has changed from $700 million to $1.1 billion in the second quarter call to now a range of $3 billion to $4 billion in this call. And again one of the major impacts in this is the change, or the expanded time horizon that we're looking at.

You can see listed below there some of the significant projects that are in guidance and that we are currently working on. And you also can see there then a listing of the operating profit that we would expect to add in the first full year of operations for those assets.

To recap, we have increased our segment profit guidance for 2007 and 2008, reflecting higher NGL and olefin margins and the addition of new opportunities. We, of course, are excited about reaching the $1 billion mark for segment profit this year. And I would remind you we have not raised our guidance in response to the most recent spike in crude oil prices.

Third quarter 2007 has been another record quarter in several ways, including overall margins and Rockies margins in September and also Recurring Segment Profit. Our team's execution on getting Opal expanded and quickly started up this year has produced tremendous shareholder value. Our disciplined approach to capital investments has us producing tremendous returns on capital invested that are unmatched by any of our competitors.

Again, it is important to note that market forces have come together in an unprecedented way to create the opportunity that we have seen here in the third quarter, and we expect here in the fourth quarter as well. We're not planning -- in our numbers we're not planning on a repeat of these conditions in 2008.

We're very excited about our growth opportunities in several of our key areas, as we have mentioned, and these projects will lay a strong foundation for the future. Finally, we will win our share of these projects because our customers do value the intense focus that our organization continues to put on being the most reliable service provider in this sector.

With that, I will turn it over to Phil.

As expected, with the affect of rate cases on Northwest Pipeline and Transco Pipeline, we have resumed flowing substantial free cash flow. Additionally, we're seeing the benefit of having arguably the best pipeline franchises in North America, with an almost unprecedented level of both organic bolt-on type expansions and major extensions of our existing footprint. And our people are doing a great job of working with our customers to position us in those projects.

While I would enjoy doing so very much, I'm not going to detail all of them. But you can see on the map on slide number 67 in your appendix, they are many. I will hit a few highlights.

Our Rockies Connector Pipeline open season closed October 29 of this year. This new pipeline will connect the Rockies Express Pipeline, which terminates in Clarington, Ohio to Transco station 195 in Pennsylvania. The design capacity will be 688,000 dekatherms a day, with a target in-service date of November 2010. The open season resulted in bids in excess of the project capacity. Negotiations of binding precedent agreements with shippers are underway.

On our Northeast Connector expansion open season will end November 5th of this year. This project expands Transco's main line from station 195, the proposed interconnection with the Williams Rockies Connector Project, to zone six markets, providing access to Rocky Mountains supply. The earliest in-service date for that expansion would be November 2010, with a design capacity to be determined by market interest.

Also for Transco this quarter we concluded a successful open season for our Pascagoula expansion. This expansion is a 15 mile 26 inch lateral connecting the Gulf energy clean -- excuse me, Gulf LNG Clean Energy Import Terminal to the Mobile Bay lateral. This is a particularly significant project because it includes and fills up all of the unsubscribed capacity from station 82 to 85. Florida Gas Transmission and Transco will each have an undivided interest in the jointly developed 15 mile pipeline. Transco's share of the capacity is 467,000 dekatherms a day with an anticipated in-service date of October 2011.

We received FERC approval for our Phase IV expansion on Gulfstream. This expansion will provide 155,000 dekatherms a day of firm service to Progress Energy's Bartow Power Plant in Pinellas County, Florida, and consists of a 17.5 mile 20 inch diameter pipeline connecting Gulfstream to Bartow, along with 45,000 horsepower compression. Construction will begin January of 2008 with all facilities ready for service January of 2009.

Turning to the West, during the third quarter the Colorado Hub Connection completed a successful open season. This project is a 28 mile lateral from the Meeker Hub area to Northwest main line near Sand Springs, Colorado. The project is still subject to certain conditions, including obtaining the necessary regulatory approvals for construction of the lateral. And the anticipated in-service date is as early as November of 2009.

Finally, Jordan Cove Energy Project LP and Pacific Connector Gas Pipeline each filed applications with FERC to construct an LNG terminal and an interstate gas transmission system, respectively. This project will provide new LNG supplies to the Pacific Northwest, Northern California, and Northern Nevada. FERC approval is anticipated for fall of 2008 with operations beginning fall of 2011.

With that, I will turn it over to Don.

Let's turn to slide number 29. This is our 2000 and 2008 -- 7 and 8 forecast EPS guidance, again focusing on the bottom line. We have once again increased our 2007 guidance at this point to $1.60 to $1.70 range, as well as for the first time provided guidance for 2008 at an EPS detail level. And that is $1.50 to $1.90. The key drivers of the increase -- excuse me, of the change or increase would be the approximate 15% production increase in E&P, lower NGL margins, with substantially higher Rockies natural gas prices, somewhat higher costs, the full year effect of the pipeline rate case, and the contribution of some growth projects.

Turning to the next slide please. This is segment profit. We've refreshed our guidance for 2007 as well as 2008. You can see the strong increase in 2008 over 2007 for E&P, again on the strength of that production increase. Midstream, as Alan described, down somewhat as a result of a less extraordinary pricing environment with Rockies gas prices coming back to a more normal level, steady contribution from Gas Pipeline. And when we look at Gas Marketing, I would like you to look at the last line in the page, and that is Gas Marketing after eliminating mark-to-market effects. And I think you'll find that in 2008, excluding mark-to-market effects and any non-recurring items associated with gains or loss on legacy positions that we may choose to exit, should be about breakeven.

Turn to the next slide please. This graphic describes somewhat the natural gas price situation. This one is across our entire portfolio. And you can see the red line as the net position, so we are long natural gas in the fourth quarter, and somewhat longer natural gas in 2008, as our E&P production grows somewhat and the hedges are lessened. And again this is a point in time snapshot and certainly those factors will change throughout the year.

The next slide depicts our Rockies natural gas exposure. And you can see in the fourth quarter the red line would indicate that we're short natural gas in the fourth quarter. And by 2008 we're about even natural gas, about flat natural gas. And again what is changing is E&P production continues to increase and the amount hedged is decreasing somewhat. Let me also note that some of the hedges that we have our collars so there is some movement within the price band.

The next slide please, number 33, capital spending. Again we refreshed that guidance, as business unit leaders have described, as we make additional investments in our core businesses. We continue to be opportunity rich and we intend to continue to seize value-adding organic growth opportunities that will continue to add value.

The next slide please, number 34. I will focus my comments on a couple of lines here. Cash flow from operations relatively unchanged at $2.050 billion to $2.3 billion this year, and $2.325 billion to $2.725 billion next year. Again as we have mentioned, capital spending has increased as we capture additional projects. Therefore the operating cash flows, as we have defined it here, which is the difference between cash flow from ops and capital expenditures, has changed somewhat. And we would intend to fund the shortfall with equity proceeds associated with drop-down transactions. And the debt proceeds raised in those drop-down transactions would be used principally for debt reduction in order to maintain our credit metrics at a level that will allow us to continue to improve toward an ultimate goal of the achieving investment grade ratings.

Let me turn it to Steve.

Only two more slides. Slide number 36 shows our earnings per share and share price performance over the last four years. As shown here, our best-of-class suite of assets, our disciplined investment in numerous high return organic opportunities, and a favorable commodity price environment have allowed Williams to grow earnings per share from $0.38 in 2004 to more than $1.60 in 2007, while our share price has moved from below $10 to near $37 this year.

While I don't believe it would be prudent to expect the extraordinary processing margins to continue in 2008, we're nevertheless looking forward to a strong year fueled by impressive natural gas production growth, full year's rate impact on Northwest and Transco, and above historical average processing margins.

Slide 37, to summarize, again strong third quarter performance. All of our businesses delivered in a major way leading to an increase in full year earnings per share guidance of 18%. A prior version of this slide showed that growth of 14%. I apologize for that. We expect 2008 to be even better. In a pricing environment that is less robust than we have seen in 2007, expect our E&P development program to increase production by 15%. And you should expect us to commit more capital to develop in an opportunity rich portfolio.

We are pursuing additional value levers, executing on two MLP strategies. We expect the absence of our Power business to create additional financial flexibility. And we're off to a strong start with respect to our share repurchase program.

We believe the future of natural gas as a preferred fuel is bright, and believe Williams is well situated with its assets and capabilities. With that we will take questions.

(OPERATOR INSTRUCTIONS). Shneur Gershuni, UBS.

Just a couple of quick questions. I guess, if I could start with Ralph, you have mentioned in the past that you've got about 3,800 drilling locations in the Valley, another 37 potentials up top in the Highlands. I was wondering if there has been any development in that respect? Can we see a large step up in those -- in the number of drilling locations over the next couple of months? Has there been significant progress and so forth?

The question is, more locations, you mean? Is that what you were asking?

Yes, exactly.

No, not necessarily. What we have said before is that those locations, particularly in the Valley, were cut off on a lateral reach, if you will, of about 2,000 feet. We have proven that can go out near 3,000 feet on our reaches, our directional reaches now. So ultimately as we continue to do that and get more comfortable at that, we would add locations to our portfolio.

And then as for the Highlands, at this point that is the same kind of technology going on up there, and we have not been able to expand out as much. But again we have only been drilling -- I think we have 100 wells we have drilled in the Highlands so far. We're drilling about another 80 or 90 this year. Expect to be over 100 or so next year. So we continue to delineate, so it would be too early to say if we could add additional locations to that.

Can you talk with respect to performance of the rigs? Are you able to improve on your days of drilling so forth, in terms of drilling costs offsetting inflation and so forth? If you can just give some comments on that.

We feel that, like for example the efficiency rigs, which are the H&P rigs that we brought in, are bringing us around on average about 20% improvement. Some rigs are much higher improvement versus the other rigs in the same fleet, and we are working to make sure all of them get up to the same level. But we would hope to be able to continue that. So a 20% increase in drilling efficiencies through the H&P rigs.

We do have the four Nabors Sundowner rigs on now. And they are just in the early stages of their life with us, and we expect the same kind or better improvements with that. Our goal would be to continue to do that. But so far at least a 20% or so improvement over the field average. And we would hope to do better than that as we continue.

If I could ask one last question, just with respect to gas management. What is the duration of these contracts? I guess what I am heading at is when are we going to start to see an elimination of the mark-to-market adjustments? Is it a couple of years away or is it much longer than that?

We're very much focused on continuing to reduce that as quickly as possible. I think we will be able to manage that down either in the first quarter or early next year to a level that is less troublesome.

Lasan Johong, RBC Capital Markets.

A couple of very quick questions. The 25 million per day constraint in maintenance, was that due to voluntary closures or involuntary closures?

That was unplanned maintenance and some planned maintenance. Is that what you mean? We did not in fact, if you will, shut in, but it was due to -- we were shut in due to either planned maintenance. And any time -- the Rockies are so tight right now even a planned maintenance will backup gas in the Rockies, and certainly an unplanned maintenance will do the same thing.

So part of it was planned and part of it was unplanned?

It wasn't by us. It was by the pipeline transporters out of the region. We are just the shipper on a number of those pipes. But some of it is scheduled on normal maintenance or tie-ins or whatever by pipes, and some of it is just they will have a disruption.

Next year you are projecting both an increase in production and drilling activity for the E&P segment. What is driving that? Is that just looking at pricing and saying, wow, prices are at 850 or 860 now. It looks good, so let's go out and drill more. Or is this driven by just a bigger and better and more powerful pool of opportunities and you're just trying to cull your best out of them, and you just happened to land with these numbers?

It is driven by our ability to continue to do the things better in our efficiencies. We expect to have the same number of rigs running, for example, in the Piceance Valley and the Piceance Highlands, but we expect that we can continue to be more efficient and thus drive down our time of drilling and thus drill more wells.

Can we read more into this than what you are just telling us, i.e. is this saying that your basket of potential inventory has increased?

No, not at this time. I think the inventory is still very prolific and large, it is just that we have a number of locations to get to, as you all know. And what we have been trying to do all along is to continue to do that faster, and in an efficient manner and a safe manner. And each year our team does a little bit better, shaves a little bit of time on various aspects of the drilling and completion program. And thus as we get better, especially with the number of rigs we have and operate now that allows us to drill more wells.

What is your exit rate for the fourth quarter, or what do you expect the exit rate for the fourth quarter?

I don't think I think that at this time because it is a forward-looking rate.

But we had strong growth all three quarters and we expect to continue to grow.

So we can make some inference from that, I suppose?

Well, we have been very successful, so I would guess that -- we're still drilling very rapidly in the basin.

Kinder Morgan and Sempra Energy announced that they are going to do an open season to extend the Rockies Express Pipeline all the way to Princeton, New Jersey. Do you fell that that might conflict with what you guys are trying to do with the Rockies Connector?

Clearly that is in the same quarter and it would envision -- by the way this is Phil Wright responding to you -- it would envision serving the producers out of the Rockies and the markets to the East. We continue to believe that we have a very cost-effective project and very cost-effective things that we can do downstream of station 195 for expansions and present the market with quality alternatives there to consider.

And so, yes, it is a competing project in that sense, but we still believe we have a strong project. And as I said earlier, the bid response to our open season exceeded the capacity, so we're feeling pretty good.

Carl Kirst, Credit Suisse.

Congratulations on another strong quarter here. Just a few one-off questions. The first going back to the shut-ins on the E&P. Ralph, are we seeing the same type of shut-ins here in the fourth quarter, i.e., is this coming from Cheyenne or is this from other issues that should be expected again?

We have seen some -- and obviously the disruption that Cheyenne was one thing. But at this point it is too early to tell if it is going to be the same level. But clearly the capacity out is tied until REX is done. And any kind of maintenance, or even small disruption, will back gas up into the Rockies. So it is an ongoing thing. It has been going really on most of the year, second and third and fourth quarter. We just thought we would talk about it a little bit in the third quarter because even though our production growth was great at 17% production growth, it would have been slightly higher, but we were curtailed. So obviously we are anxiously waiting for the Rockies Express to kick in.

Was it a similar mount amount in the second quarter then?

No, not as much. I don't recall what it was, but there was some in the second quarter also.

Fair enough. Don, Alan, looking at the Midstream, and specifically with respect to risk management, I know you have got the oil price range out there for your 2008 guidance, but at the same time we're looking at [Calloway stripped] at around $88. And there is some concern maybe the first half of '08 we might see some weaker oil prices. Is there any attraction, I guess, towards actually doing some dirty hedges with respect to oil, or if it is liquid enough going out and more aggressively locking in liquids prices?

I will speak to the liquids price issue. I will let Don take on the dirty hedge question there. How is that? On the NGL prices there are some very attractive prices offered, as you probably know if you follow that. There are very steep discounts, particularly if you get into the long dated. Get beyond about six months and you really start to see the spread or the relationships between crude and those NGLs to fall off dramatically. I will tell you that we have done -- we did a small hedge last year. We have a small hedge on now. And we have continued to lose somewhere about 10% below market on those hedges, even though we thought those were really great prices when we put them on.

The good news is on the gas side we've got that covered. I think it is a great question for us on crude oil, especially given the reason spike. And I will tell you that we are following the NGL price offerings very closely, and have been looking at a lot of bids coming in on that, particularly in the first six months of next year. I will turn the crude question over to Don.

Carl, a good question. It is one that we look at regularly. Some of the consideration -- one is if we had hedged we would have missed a lot of the upside. Two, it is a dirty hedge and certainly there is some potential of lack of economic alignment there that could cause a loss, as well as potentially lock in in a profit. There are liquidity issues. Certainly hedging a substantial amount of oil would require a lot of liquidity to support that. And then you get to the accounting issues.

So to date we have chosen not to. It is something we continue to look at. But I can't give you any guidance as to whether or not we will find it to be attractive in the future. To date we have chosen not to do it.

Fair enough. Then lastly, and I will get back into queue after this. Don, with respect to Gas Marketing, I guess I'm looking for a little more color on, absent the mark-to-market or excluding the mark-to-market losses, what predominately was causing that cash marketing loss? Is that still part of the legacy position?

And as a corollary, are the reason why you're going to kind of a neutral position in '08 -- going back to a prior comment you said because hopefully we're going to manage this exposure down in the first quarter -- Is that what gives us confidence to getting to a neutral or positive in '08?

First I will answer -- just mention that the accounting rules didn't allow us to put all of the positions that were associated with the former Power segment into discontinued operations, despite the fact that they really weren't positions that we would expect to continue. So we have something that feels like discontinued operations up in the Gas Marketing segment. Some of the positions we would expect to exit at a gain or loss. And that we're taking steps to exit some of those positions, which would take out some of the -- both the drag on earnings as well as the cash impact.

Beyond that, I think if we really think about the business going forward, again it is principally in support of E&P and Midstream, providing a service, marketing, transportation and storage, and over the long haul we would expect that to be breakeven or better. We do take storage positions from time to time where we will put gas in storage, and in many cases sell it forward, lock in a profit. But even in that case the lower cost to market accounting rules, if there is a decline in the market value, requires to market down. And if the prices come back we can mark it backup. So we're dealing with that. But again I think longer-term we expect this to be a business that is breakeven or better.

The other -- I'm sorry, the other aspect of the question, as you guys look to manage to sell down some of these legacy positions, as you're looking at it today, or post the most recent mark-to-market, on a net net basis are those positions meaningful, material or is it something that is below $50 million that just needs to be gone?

I would say it could be about $50 million, but it certainly -- I wouldn't expect to be all that significant. And again, I think when we talked about the overall gain or loss associated with exiting the Power segment business, we indicated that the overall gain and loss was not expected to be significant. We still view these positions that our legacy positions to be part of the overall exiting of the Power segment. We are required to account for it in separate buckets, but we view it much, much the same.

[Ken Snyder], Citigroup.

It is actually Faisel Khan from Citi. On the Midstream volumes can you just remind us again what the breakdown is of keep-whole POP and POL grouped together in fee-based volumes?

Are you wanting to know that on a volumetric basis?

On a volumetric basis.

I don't have that detail right here in front of me. I can give you a rough breakdown of it. The majority of our keep-whole exposure is in the Rockies. In fact, probably looking at our gas volumes and our shrink volumes is the best way to look at that.

And we have about total MMbtu consumption on the Midstream side is about 400 million a day roughly. That includes discovery and our olefins business as well. And about 65% of that fuel and shrink is in the Rockies, with the vast majority of that being at our Opal facility. Opal is very heavily weighted to keep-whole. Wamsutter is more balanced to fee-based.

And in the San Juan Basin about 15% of our fuel and shrink is consumed in that area. And in the San Juan Basin that mix is -- about 71% of our contract mix is either processing fee or gathering fee, and the balance is keep-whole, and split about 50-50 between keep-whole and percent of liquids. And then the balance of our fuel and shrink is in the Gulf Coast region. And about 40% of our business in the Gulf Coast is fee-based, and the balance being split between percent of liquids and keep-whole.

In terms of your new facilities coming online and new contracts you're signing with customers, what is the breakdown of the type of contracts you're signing in terms of fee-based versus commodity exposed contracts?

We continue to shift contracts to fee-base. For instance, our Cameron Meadows facility is now 100% fee-based. And we continue to do that as producers see the value in the upgrade and are willing to pay us a lot higher fee-based contracts. In this kind of environment we are generally shifting to fee-based contracts, just because they are perceived as valuable by our customers.

In terms of your NGL customers, are you seeing any slowdown in consumption of your liquids volumes to those customers that are chemical or refining customers?

No, in fact if you look at what data is available as to NGL storage, light in storage, that has been getting drawn on pretty hard. Ethylene cracking capacity is way up. Of course we have a good bird's eye view of that from our running our ethylene cracker there and the olefins business at Geismar, so we understand the demands on that side. And there are very strong pools in the ethylene and propylene markets right now. And of course with crude oil being where it is, the heavier products like naphtha that might be cracked are just way too expensive, and so ethane and propane are the desired feedstocks, and there is really a strong pull on that.

On your E&P activities is there any update on any of your exploration activities in the Paradox or anywhere else?

There are several updates I could give you. First in the Barcus Creek area, which is the northern part of the Highlands, we are drilling our fifth well. And as soon as that well reaches TD we will have earned the 11,000 additional net acres. In the Paradox three wells have been -- vertical wells have been drilled to date, with our fourth well is currently going to spud by the end of the year. And we're still evaluating the wells and the results, and so still working through that new area but also drilling ahead.

In the Piceance we have also added a second well to what we're calling a deep well test. And this is to test what is called the Cozzette, Corcoran and Mancos test. And we are in our second well there. We believe that could have a deeper pool of existing -- of reserves below the Williams Fork, so we are drilling our second well there.

In Uinta we are drilling our first well there. And we are drilling ahead -- just started about a week or so ago. So quite a bit of activity there. And that is part of the reason why you saw the update in capital expenditures for exploration. We're moving ahead on all of our projects that I have been talking about for the last couple of calls.

The Uinta Basin, is that a new acreage position that you guys picked up or is that a legacy position?

It is a new acreage position we have been ticking up over the last year and a half, a couple of years. And we have established a pretty solid block of acreage there. And it is still way too early to tell, but it was time to start testing it and we're drilling our first well there.

How many acres do you guys have there?

About 74,000, 75,000 net acres. It is similar to our position in the Piceance Valley in total net acreage.

On the Barnett, I think you guys said you tripled production year-over-year, is that correct?

That's correct.

What is the potential of that -- of the position you guys have there? Is it fair to say we could continue to see a sort of growth given your inventory or --?

Obviously the base volume will continue to go up, but our inventory is well over 100 locations as we speak now, and that could increase substantially with some, if you will, down spacing that is going on in the basin. We have actually five rigs operating now. We intend to be operating in the four to five -- probably more like the four rig level. And we have more locations that we're trying to secure as we speak. There's a lot of deal flow from the -- smaller deal flow in that area, so I think we could continue to see good growth in the Barnett.

In terms of picking up more pipeline capacity out of the Rockies, I think I saw you picked up maybe -- is it 100 million cubic feet a day to SoCal. Is that new or is that old?

That is the current position that has been used somewhat in the Power side of the business that we are now -- we have picked up. And that is new in the sense of we are now moving gas to Southern California on Kern. And that will be part of our portfolio. And obviously it is a very good pricing point for us.

You were able to bring over the Kern River capacity that was at -- the marketing business into your lease capacity?

Yes, we were.

Was there anything else that came out of that portfolio that you guys are deciding to keep?

On the transportation side we had already worked proactively with Bill's Power Group, so most of -- the rest of it was already in our, if you will, in the Williams family and we were already utilizing it.

On the Pipeline side, the higher than expected earnings for the year in Pipelines versus what you had in last quarter, is that a result of the stipulation agreement you guys entered into on the Pipeline side, or is there something else that I missing?

I'm sorry? Stipulation agreement?

I think you guys talked about a stipulation with your customers that you entered into on Transco.

Rate case. Largely up on the rate case and also some effective cost control measures.

Do you have any sort of CapEx or potential project cost for these open seasons that you have outstanding?

We have detailed the ones that we can detail in the exhibits.

Then on the accounting and finance side, your cash tax rate I think next year goes up to 35%. Is that a function of your NOL -- you have kind of used up all your NOLs?

In terms of the cash tax rate, I think it was more a function of some of the nondeductible items that went through income in the past. So again the permanent differences that we have are relatively few. It is really more about the statutory rate adjusted for any nondeductible in terms of the provision. In terms of the actual cash taxes, yes, the absence of the NOL, or the fact that the NOL has been used up, would cause that to rise sharply.

Do you guys have a number in terms of how many shares you repurchased in October? I saw the September and August numbers but --?

They were no additional shares repurchased during the month of October.

Sam Brothwell, Wachovia.

Ralph, you mentioned something about you picked up some acreage in the Uinta. Is that in Colorado or Utah?

That is actually in Utah.

It is in Utah. And you are targeting Mancos?

Actually, we are targeting -- no, in that area we're basically targeting what would be equivalent of what we drill for in the Piceance, which is the [waves four] formation.

But I heard you say something about Mancos in there. I must have gotten --.

That was in the Piceance. We're drilling deeper in the Piceance Valley, targeting a couple -- we are on our second well, which is evaluating the potential that we may or may not have. And it goes from the Williams Fork Formation, also known as the Mesaverde formation, down into the Cozzette, Corcoran and then Mancos.

Then as you look at going forward, I have been hearing a lot about that there is a need for additional clearly takeaway -- take capacity from the Rockies. Do you see the greater opportunity going westbound, or still eastbound, or both? Can you comment on that?

And Phil, to the extent that there is a need for another big pipe East out of the Rockies would you guys look at doing something major in that regard?

This is Ralph. I think there is need for additional capacity, as you have probably seen from all the other producers talking about that and others. I think that possibly an opportunity to go to the West is a good idea. And then to continue to expand, as we have all seen the ability to go to the East, whichever way that actually -- Northeast or maybe the Southeast is also a good opportunity. I think the good idea is -- or neat idea is that several pipelines are talking about those kind of things, and we look forward to hopefully a couple of those actually happening.

This is Phil. Clearly to the extent that some of those make economic sense for us, we're going to be out there aggressively pursuing them.

Robert Lane, SMH Capital.

I know you have already touched on this, but I just wanted to dig a little deeper into the Rockies Connector Pipeline versus Kinder Morgan's proposed pipeline. I know you all said you had been vastly oversubscribed on the deal. But their announcement had come pretty much when you all's open season was over. Is this the type of deal -- if you take a look at your capacity and their capacity, when you add them together it is pretty much well over capacity for what is going to be coming through on that pipeline. Is this a kind of deal where you might downsize a bit, or is it also a kind of deal where you would partner with Kinder Morgan and try to bring that gas East?

This is Phil again. I don't know that I would use the word vastly oversubscribed, but we were oversubscribed. I think we have the right size pipe. I think we have -- for the timeframe in which the market wants to see that capacity there, we think that the shippers have spoken as a market as to when they would like to see that capacity and in what quantity. And your observation that with both pipes there might be an overcapacity situation in that quarter if both of them got built, is an accurate one.

Whether or not we would do something with Kinder Morgan is just a question out there. I personally would think we're going to proceed with our project -- as we go to precedent agreements we would probably just proceed.

Do you have sort of have a -- and I think you might have mentioned this, and I apologize because I had to jump off the call at one point. Do you have a timing at when you're looking to lock down a binding open season?

As I said, we're working on it as we speak, and we hope to have those concluded by the end of the year.

[Gabriel Bradar, K Street Capital].

Just a quick question on the '08 guidance. Can you just talk to the jump in corporate and other costs? I think it is going up by like $80 million or $90 million?

That includes minority interest associated with drop-down transactions. So you saw we announced the Wamsutter drop-down that would be associated with that.

[Mark Arbersabi, Pimco].

Just a question here on your guidance. It looks like CapEx obviously up. Free cash flow is going to be down a bit from prior guidance. It looks like negative free cash flow for the year for '08 guidance. Is that right?

That is correct and that is by design. I think in our prior guidance we included only the capital projects that we had a high level of confidence on. And always had disclosed that it was our goal to drill even faster, as well as to capture the many projects that both Midstream and Gas Pipeline have in front of them. So you should have and should continue to expect capital spending to increase somewhat as we capture those additional value-adding opportunities. So, yes.

Just a quick question here on the credit profile. Obviously you guys have done a great job and everything. I was just wondering when the Power book is sold -- when you close the Power deal this month -- are you going to be making a stronger push to get to investment-grade with the agencies, maybe going back and meeting with them, talking about Power book being gone, or is there something maybe you're going to push out, given what I'm looking at here on free cash flow and so on?

We meet with the agencies every quarter. We will meet with them again following this call. And we are constantly keeping them posted on our activities and our plans. And, yes, we would be hopeful of ratings action, but it is up to the agencies.

Are you thinking it is a definite goal of the Company and the Board to at some point be investment-grade, or is it not really an explicit goal you guys have in mind, I guess, given your opportunities out there?

The number one goal is to drive equity value up on a sustainable basis faster than our peers. So that is the overarching goal. We think that having stronger credit would help us achieve that goal, in that the availability of capital is more reliable, the cost of that capital is somewhat lower, and we can be more opportunistic to seize the opportunities ahead. So we think a stronger credit rating, investment-grade rating is worthwhile, but the overarching goal is to drive sustainable and superior equity value.

Carl Kirst, Credit Suisse.

Just two quick follow-ups and I appreciate the time. The first is on the Wamsutter transaction, the WPZ, it was noted that we were looking around $41 million of EBITDA for the first half of the year. Can that be broken out between how much is fee-based versus how much is commodity sensitive?

First I remind you that first and second quarters were not all that -- that is not where we saw the anomaly, if you will, in margins. But we will be providing some detail on that as we go through the process. I hate to get ahead of ourselves in providing some detail that somebody might rely on or take out of context, so I think we will wait until we have put that detail in writing.

But it is fair to say that given that it has a processing facility it is not 100% fee-based?

That is correct. It is not 100% fee-based.

Fair enough. Then just last question, Ralph. In the appendix you guys annotated your cash costs at roughly the $2.05 million mark LOE, etc., etc. Can you actually break that out on a component basis, if possible?

Yes, I can.

If you don't have it, we can follow up off-line.

I've got it I think. Real quick let me just check one thing. Roughly LOE was in the approximately $0.69 range; Gathering $0.57; operating taxes about $0.44, $0.45; and then G&A in the $0.36 range or so. That might not quite add to $2.05, but it would be close.

Rick Gross, Lehman Brothers.

A couple of quick questions on the E&P. One of the areas that plateaued, or has plateaued for a while, is the Powder River. I know we have had -- the Medicine Bow lateral is going to create some outlet. Obviously it gets you to a restricted point until Rockies Express takes off. You had some water handling problems. But is it basically that kind of mechanical issue, not so much drilling inventory that has flattened that production profile out there?

Our production profile -- we were up 11%, but I think I see what you're saying.

I'm looking at the last three quarter at plus or minus 165 million a day.

I think what you are seeing there is our production is -- has the capability, and currently it is much higher than that. And what is going on is there was an expansion by Fort Union Gas Gathering that needed to occur that is finally in place here in the first part of October, or was in place in the first part of October. That has allowed the -- really the constraint was in the gathering system for our volumes to take off, and it proved quite a bit over that.

It has not been a -- it is clearly not a well performance nor number of locations. It has been the ability to get it out of the gathering and FUGG as they call it, Fort Union Gas Gathering, has taken off and completed their expansion.

You mentioned -- you didn't give a quantity in the San Juan. That also has been an area where you have come off the peak. And I was just curious as to what the volume was there, because you said it had come off because of some maintenance and some other things going on once again in the gathering systems there.

We had volumes that are still in the 150 million a day range, so they have remained relatively flat. They have gone as high a few times in the 155, 160 range, but still in the 150 or so range as we speak in the fourth quarter.

A different subject. Don indicated that you're running through the NOLs and your cash tax rates are going up. How are you guys handling your IDTs for tax purposes? I'm curious as the budget goes up why you wouldn't be sheltering more of your cash taxes?

I would say we are sheltering all that is available to us. We will -- we can provide some additional comments off-line on that.

That does conclude the question-and-answer session for today. At this time I will turn it back over to our speakers for any additional or closing remarks.

I appreciate your questions today. And we are delighted with our third quarter results and looking forward to a very bright future. Thank you.

This does conclude today's conference. We thank you for joining, and have a great day.