Travis Campbell - Head of Investor Relations Steve Malcolm - Chief Executive Officer Don Chappel - Chief Financial Officer Ralph Hill - President of Exploration and Production Alan Armstrong - President of Midstream Gathering &Processing Phil Wright - President of Gas Pipeline

Shneur Gershuni - UBS Lasan Johong - RBC Capital Markets Carl Kirst - Credit Suisse Faisel Khan - Citigroup Sam Brothwell - Wachovia Robert Lane- SMH Capital Gabriel Bradar - KStreet Capital Mark Arbarsebi - PIMCO Carl Kirst - Credit Suisse Rick Gross - Lehman Brothers

Good morning, everybody. Welcome to our third quarterearnings call.

As always, thank you for the interest in the company. I knowmany of you have a lot of calls to monitor this morning, so we’ll get right toit.

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 theslides are available on our website, williams.com in a PDF format.

The pressrelease and the company's schedules are also available on the website, and thismorning we also filed our third quarter 10-Q. Slides 2 and 3 entitled, "Forward-LookingStatements," detail risk factors and uncertainties associated with futureoutcomes.

Please review the information on that slide, and also slide 4,"Oil and Gas Reserves Disclaimer" is also important, and we urge youto read that slide as well. Included in the presentation today, as usual, there arevarious non-GAAP numbers that have been reconciled back to Generally AcceptedAccounting Principles.

Those schedules follow the presentation and are integralto the presentation. With that, I will turn it over to Steve.

Thanks, Travis. Good morning and welcome to our thirdquarter earnings call.

We certainly appreciate your interest in our company. Wehad another outstanding quarter, and our core natural gas businesses deliveredvery strong performances across the board.

Starting with slide 6. I am sure you saw the numbers for thethird quarter.

Our adjusted earnings per share increased 44% to $0.39 from ayear ago. Our 2007 picture is getting even brighter as we are bumping up thefull year earnings per share guidance by 18%.

We expect 2008 earnings to show strength even in a lessextraordinary pricing environment. Clearly, we are and have been in a robustcommodity pricing environment for much of this year.

The fact is that for '07we have been short gas in the Rockies, and have takenadvantage of the very low prices in that region. However, we would expect thatthe situation to change somewhat when the RockiesExpress Project goes into service.

We look for approximately 15% natural gas production growthin 2008, and Ralph Hill will provide more detail on our outlook here in a fewminutes. And we expect to commit more capital to develop our opportunity richportfolio.

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

We are continuing to make progress with respect to othersteps being taken to deliver value to our shareholders. I am sure that younoticed that Williams Pipeline Partners filed an amended S1 on Monday thisweek, and among other things, the latest filing includes the expected IPO priceof $19 to $21 per unit.

As you recall, the pipeline MLP consists of a 25% interestin our Northwest Pipeline, and at this stage in the process, there is reallyvery little more that we can share about our MLP beyond what you can obtain foryourself in our public filings with the SEC. And we continue to execute on our strategy to drop-downassets into our Midstream MLP.

We announced this morning that we had signed anonbinding letter of intent for Williams Partners to acquire an ownershipinterest in the limited liability company that owns the Wamsutter system fromWilliams for $750 million. Alan Armstrong will have more to say about thattransaction here in a few minutes.

We are delighted with the progress that has been made on thesale of Power. We have received substantially all consents, and we now expectto close the Power sale to Bear during November, and possibly as early as nextweek.

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

Turning to slide 7 which addresses our third quarterstrength; I think, the quarter was driven obviously by strong NGL margins. Weobviously took advantage of the Rockies basis anomaly, which createdextraordinary processing profits for Midstream, and our transportation andhedging strategy insulated E&P from the challenges that many Rockiesproducers suffered and continue to suffer as a result of the basis blowout.

This highlights the fact that we have stressed many timesthat we are a Rockies producer, not a Rockies price-taker with just 7% ofproduction exposed to Rockies prices. Our E&P production outpaced year agothird quarter by 17%, and our new rates on Northwest and Transco continue todrive an increase in Gas Pipeline results.

A couple of points on slide 8, which shows actual segmentprofit in 2005 and 2006, and forecasted full year segment profit for ‘07 and‘08. The expected uplift from the extraordinary pricing environment that we areexperiencing this year is the orange striped block at the top of the 2007 baron this chart.

But even if you would normalize prices for 2007, we would stillend up with very impressive 15% growth compared to 2006 levels. Then we show the guidance range that we are forecasting in2008, and I would encourage you to please take a look in the appendix at asummary of our commodity price expectations that are reflected in this 2008guidance.

Compared to our 2007 assumptions, we are expecting 2008 to havestronger natural gas prices in the Rockies andelsewhere, 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.

Thanks, Steve. Good morning.

Let's turn to slide number 10,Financial Results, and I will run through all of these very quickly. Focusingon the bottom line.

Our key earnings measure, the recurring income from continuingops after mark-to-market adjustments on a per share basis, you can see theincrease there of $0.12 over the prior year, or 44%, and the same rate ofincrease, 44% on a year-to-year basis. Next slide please, number 11.

This is on both a reported andrecurring basis. The non-recurring items are detailed on a slide in theappendix, as is the mark-to-market adjustment.

Overall, segment profit aftermark-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 expandedNGL margins, and Gas Pipeline is up 57% on the strength of that rate case. Gas Marketing Services, which was formally a part of thePower segment, provides Gas Marketing transportation storage services to E&Pat Midstream, and manages certain contracts related to the former Powersegment.

These former Power sales contracts will result in some earnings andmark-to-market volatility until such positions expire or are sold. Next slide please, number 13.

On a year-to-date basis, againfocusing on the recurring results, segment profit after mark-to-marketadjustment of 1.721 billion; up nearly $400 million, or about 28%. I will turn it over to Ralph.

Okay, Don, thank you. Let's turn to slide 14.

Ouraccomplishments: production and profit are both up 17% compared to thirdquarter ‘06. Also reflected in these numbers were some pipeline maintenance andcurtailments that happened in the Rockies, whichdecreased our production by about 25 million a day.

Without those maintenance and curtailments, production wouldhave been up about 20% year-over-year and about 5% sequentially, and that justsimply reflects the very tight Rockies pipeline network that's out there, whichis expected to improve in ‘08. Steve has already talked about that insulatingour transportation portfolio insulates our E&P volumes from the basisblowout.

Turning to slide 15. This slide reflects our strongportfolio, 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. Inparticular looking at the Highlands growth, it does haveseasonal swings.

So, although we're very pleased with the 25 million a day andup 98%, the growth is actually greater than that. And as we get into moreyear-round drilling, we will have more steady growth.

But our currentproduction in the Highlands is up close to 40 million aday from this 25 million just reported for the third quarter. Slide 16, this again reflects our dual strength of prolificRockies reserves and production growth, which we can combine with our abilityto sell our gas away from the Rockies.

The key on this slide is 7% is priced inthe 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 RockiesIndexes, as you see there on the bottom of the slide, of 2.90 and 2.90 forNorthwest and CIG. And those do not include fuel and shrink, so actually youcan see how much better we are doing because we are able to transport our gasaway from the Rockies to other areas.

Slide 17, a guidance update. The difference in 2007 on theprofit side is purely prices.

They are down from our last call, as you haveseen nationwide. Note our continued strong production growth offsets some ofthis pricing decrease.

Our speed of development strategy is allowing us todrill 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%.

Thisagain reflects our ability to turn capital investments rapidly into productionand profit. With that, I will thank our employees -- slide 18.

I wouldlike to thank our employees for a great quarter and everything they do for us.And I will now turn it over to Alan Armstrong.

Thanks, Ralph. Starting here on slide 20.

Our recurringsegment profit of $300 million for the second quarter of 2007 beat the previousquarterly record of 248 million reported in second quarter of '07. And thethird quarter 2007 margins were also a record of $0.62 per gallon, and this wasdriven by our Rockies margin, which actually reached$0.83 per gallon in September.

Additional profit [assessing] investments we have madecertainly paid off and have allowed us to maximize profitability. The key toour success in this area has been solid project management execution.

Our teamstarted up our 350 million a day train at Opal on schedule, and within 10% ofbudget in February of '07. Having this project start up smoothly and on-timehas allowed us to realize these great margins.

And it provided our customerswith the reliable service they bargained for to keep their Jonah and Pinedalevolumes flowing as promised. We also have successfully integrated BASF's interest in theGeismar plant, which contributed nicely to our segment profit in this quarteras well, and progress has been made in the Deepwater Gulf of Mexico.

ThePerdido Norte agreements were executed in the third quarter finally with theproducer. A lot of very complex issues to deal with there, and we are happy tohave that behind us.

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

Moving on to slide 21. This graph shows the tracking ofmargins over the last five years.

It also shows growth in our domestic NGLproduction. And in the light blue bar the amount of liquids we are producingfor our own account, excluding our Discovery and [Oxable] investments.

An interesting data-point here is also the five-year averagemargin of $0.22. As you can see, we saw margins of almost three times theprevious 20 quarters in the third quarter.

The environment that drove recordmargins during the third quarter is certainly alive and well in the fourthquarter; however, we are not planning on these in 2008 and beyond. Several factors have worked together to create thisextraordinary environment.

First, the low gas prices in the Rockiescaused by infrastructure constraints and very successful drilling programs inthe Piceance, Uinta and Jonah, Pinedale basins. With the addition of new gastransportation capacity out of the Rockies in the near future, we do expect gasprices in Wyoming and Coloradoto return to historical norms.

Crude to gas ratio plays an important role as well. Sinceolefins producers have consistently chosen ethane over heavier feedstock, suchas naphtha, it is putting tremendous upward price pressure on ethane, propaneand some butanes.

We anticipate some of this intense demand to be met by newprocessing plants in the Rockies and Barnett Shale thatare announced to come on in service in 2008. Moving on to slide 22.

Given the year-to-date results, coupledwith the strong margin environment outlook for the fourth quarter, we are proudto announce we have increased our 2007 segment profit from 700 to 850 million,to 950 to 1.125 -- I think, I like saying billions better there. So, we arereally excited about seeing this kind of increase.

Similarly, we increased oursegment profit guidance for 2008, but moderately by 25 million at the midpoint. Capital spending for '07 remains unchanged at 650 to 700million; however, our 2008 capital guidance has been raised from 525 to 575 nowto 650 to 700 million.

The increase is due primarily to an expansion of ourPerdido Norte project, new developments in our Canadian Oil Sandsopportunities, and several new expansion opportunities that are emerging in thedynamic Western region. The big driver in our 2007 to 2008 decline from ourprevious guidance forecast is a planned 350 million drop in NGL margins, drivenby higher natural gas prices.

Also near 2007 in propane heavier prices are contemplatedhere, but we expect ethane prices to lower by approximately 20% during thisperiod. However, if we saw a repeat of 2007 in terms of NGL margins, we wouldexpect an approximate 5% increase in profits next year, due to growth projectlike Bass Lite and our investment in BASF's interest in Geismar.

And these willbe partially offset by higher depreciation and O&M costs. Moving on to slide 23.

Here we are providing areconciliation of the current guidance versus earlier guidance for 2007 and2008. First, I will explain the segment profit guidance changes.

Of course, amajor factor increasing our segment profit guidance in both periods is NGLmargins. Our outlook for NGL margins increased from approximately $0.40 pergallon to $0.54 per gallon for full year 2007.

In 2008, we have increased our margins by roughly $0.06 pergallon, reflecting the higher assumed commodity prices. Total year margin in2008 is forecast to be approximately $460 million or $0.32 per gallon.

This isabout a dime per gallon above five-year average of $0.22 shown on the previousslide. Also increasing segment profit guidance is higher margins inour olefins segment for both '07 and '08.

This increase is driven primarily byhigher margins forecast at our Canadian facilities, driven by higher propaneand butylene mix margins. Propylene and ethylene are fairly flat in our olefinsbusiness.

And the price forecast that we have in our olefins business is basedon the August 30th CMAI price forecast, if you track that. Increased costs in 2008 reflect higher operating expenseattributable primarily to additional overhauls being planned next year.

Wecertainly have tried to limit any downtime on equipment this year with the highmargins that we have had, but we will be having to take equipment down in '08for overhauls. As well, we expect higher G&A costs required to handle thetremendous amount of new growth in the Canadian Oil Sands and Western regionthat is new to us now.

Lower volumes assumptions reflect the lower volume in theFour Corners where volumes were reduced by about 40 million per day, due to aless aggressive assumption about well connects. Now we are not saying that ourvolumes are actually lower year-to-year by 40 million, we are simply sayingthat from our previous guidance forecast it is lower.

Some of the difficultiesout there that have caused us to back off a more aggressive forecast is someland issues on the Hickory Apache Nation, and an inability to get on some ofour producers to get on to some of the Forest Service lands. We also are projectingsome lower volumes in the Gulf Coast.Permian/Anadarko's, Boomvang and Nansen projects, which flow into our EastBreak system.

On the capital guidance side, we also increased our GAAPcapital guidance a bit from our second quarter, primarily this was driven bythe Perdido Norte project. There we have got most of the increase, 40 million,the vast majority of that is covered, by rate adjusters that we have with ourcustomers out there, and we are set in place to cover things like increase inship construction costs and steel costs.

We also have some new opportunities out in the Westernregion, and there are quite a few small projects that I won't list here. Moving on to the pie chart here, slide 24, this kind ofshows the backlog, if you will, the investment opportunities we have.

LargeDeepwater projects and Rockies opportunities, especiallythe Willow Creek project, dominate the expansion capital and guidance for 2007and 2008. These new opportunities, along with an expanded time horizon, havecontributed 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 timeline. So we have expanded the time horizon quite a bit here.

The under negotiation pie range has remained steady. Themain differences involve the area in which the expenditures occur.

Basically wehave got volumes -- sorry, some of the projects moving from the Deepwater andinto the TXP-IV expansion at Echo Springs, and our Canadian Oil Sands. The pie labeled in development and proposal reflects thetremendous amount of opportunities that we recently identified during ourfive-year long range planning process.

Examples include adding a couple ofpotential Deepwater projects to this category, and adding several new CanadianOil Sands off-gas recovery projects. Capital range has changed from 700 million to 1.1 billion inthe second quarter call to now a range of 3 to 4 billion in this call.

Andagain, one of the major impacts in this is the change, or the expanded timehorizon that we are looking at. You can see listed below there some of the significantprojects that are in guidance, and that we are currently working on.

And youalso can see there a listing of the operating profit that we would expect toadd in the first full year of operations for those assets. To recap, we have increased our segment profit guidance for2007 and 2008, reflecting higher NGL and olefin margins and the addition of newopportunities.

We, of course, are excited about reaching the $1 billion markfor segment profit this year. And I would remind you, we have not raised ourguidance in response to the most recent spike in crude oil prices.

Third quarter 2007 has been another record quarter inseveral ways, including overall margins and Rockiesmargins in September and also recurring segment profit. Our team's execution ongetting Opal expanded and quickly started up this year has produced tremendousshareholder value.

Our disciplined approach to capital investments has usproducing tremendous returns on capital invested that are unmatched by any ofour competitors. Again, it is important to note that market forces have cometogether in an unprecedented way to create the opportunity that we have seenhere in the third quarter, and we expect here in the fourth quarter as well.

Inour numbers, we are not planning on a repeat of these conditions in 2008. We are very excited about our growth opportunities in severalof our key areas, as we have mentioned, and these projects will lay a strongfoundation for the future.

Finally, we will win our share of these projectsbecause our customers do value the intense focus that our organizationcontinues 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 NorthwestPipeline and Transco Pipeline, we have resumed flowing substantial free cashflow. Additionally, we are seeing the benefit of having arguably the bestpipeline franchises in North America, with an almostunprecedented level of both organic bolt-on type expansions and majorextensions of our existing footprint, and our people are doing a great job of workingwith our customers to position us in those projects.

While I would enjoy doing so very much, I am not going todetail all of them. But you can see on the map on slide number 67 in yourappendix, they are many.

I will hit a few highlights. Our Rockies Connector Pipeline open season closed October29th 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-servicedate of November 2010. The open season resulted in bids in excess of theproject capacity.

Negotiations of binding precedent agreements with shippersare underway. Our Northeast Connector expansion open season will end November5th of this year.

This project expands Transco's main line from station 195,the proposed interconnection with the Williams Rockies Connector Project toZone 6 markets, providing access to Rocky Mountainssupply. 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 successfulopen season for our Pascagoulaexpansion. This expansion is a 15 mile 26 inch lateral connecting the Gulf LNGClean Energy Import Terminal to the Mobile Bay lateral.

This is a particularlysignificant project because it includes and fills up all of the unsubscribedcapacity from station 82 to 85. Florida Gas Transmission and Transco will eachhave an undivided interest in the jointly developed 15 mile pipeline.

Transco'sshare of the capacity is 467,000 dekatherms a day with an anticipatedin-service date of October 2011. We received FERC approval for our Phase IV expansion onGulfstream.

This expansion will provide 155,000 dekatherms a day of firmservice to Progress Energy's Bartow Power Plant in Pinellas County, Florida,and consists of a 17.5 mile 20 inch diameter pipeline connecting Gulfstream toBartow, along with 45,000 horsepower compression. Construction will beginJanuary of 2008 with all facilities ready for service January of 2009.

Turning to the West, during the third quarter, the ColoradoHub Connection completed a successful open season. This project is a 28 milelateral from the Meeker Hub area to Northwest mainline near Sand Springs, Colorado.

The projectis still subject to certain conditions, including obtaining the necessaryregulatory approvals for construction of the lateral. And the anticipatedin-service date is as early as November of 2009.

And finally, Jordan Cove Energy Project LP and PacificConnector Gas Pipeline each filed applications with FERC to construct an LNGterminal and an interstate gas transmission system, respectively. This projectwill provide new LNG supplies to the Pacific Northwest, Northern California,and Northern Nevada.

FERC approval is anticipated for fall of 2008 withoperations beginning fall of 2011. With that, I will turn it over to Don.

Thanks, Phil. Let's turn to slide number 29.

This is our2007 and 2008 forecast EPS guidance, again focusing on the bottom line. We haveonce 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 detaillevel, and that is $1.50 to $1.90.

The key drivers of the change or increase would be theapproximate 15% production increase in E&P, lower NGL margins, withsubstantially higher Rockies natural gas prices,somewhat higher costs, the full year effect of the pipeline rate case, and thecontribution 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 strongincrease in 2008 over 2007 for E&P, again on the strength of that productionincrease.

Midstream, as Alan described, down somewhat as a result of aless extraordinary pricing environment with Rockies gas prices coming back to amore normal level, steady contribution from Gas Pipeline. And when we look atGas Marketing, I would like you to look at the last line in the page, andthat’s Gas Marketing after eliminating mark-to-market effects.

And I thinkyou'll find that in 2008, excluding mark-to-market effects and anynon-recurring items associated with gains or loss on legacy positions that wemay choose to exit, should be above breakeven. Turn to the next slide, please.

This graphic describessomewhat the natural gas price situation. This one is across our entireportfolio.

And you can see the red line as the net position, so we are longnatural gas in the fourth quarter, and somewhat longer natural gas in 2008, asour E&P production grows somewhat and the hedges are lessened. And againthis is a point in time snapshot, and certainly those factors will changethroughout the year.

The next slide depicts our Rockiesnatural gas exposure. And you can see in the fourth quarter, the red line wouldindicate that we're short natural gas in the fourth quarter.

And by 2008, weare about even natural gas, about flat natural gas. And again what's changingis E&P production continues to increase and the amount hedged is decreasingsomewhat.

Let me also note that some of the hedges that we have are collars, sothere is some movement within the price band. The next slide please, number 33, capital spending.

Again,we've refreshed that guidance, as business unit leaders have described, as wemake additional investments in our core businesses. We continue to beopportunity rich and we intend to continue to seize value-adding organic growthopportunities that will continue to add value.

The next slide please, number 34. I will focus my commentson a couple of lines here.

Cash flow from operations relatively unchanged at2.050 billion to 2.3 this year, and 2.325 to 2.725 next year. Again as we havementioned, capital spending has increased as we capture additional projects.Therefore the operating cash flows, as we have defined it here, which is thedifference between cash flow from ops and capital expenditures, has changedsomewhat.

And we would intend to fund the shortfall with equity proceedsassociated with drop-down transactions. And the debt proceeds raised in thosedrop-down transactions would be used principally for debt reduction, in orderto maintain our credit metrics at a level that will allow us to continue toimprove toward an ultimate goal of achieving investment grade ratings.

Let me turn it to Steve.

Okay. Only two more slides.

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

While I don't believe it would be prudent to expect theextraordinary processing margins to continue in 2008, we are neverthelesslooking forward to a strong year fueled by impressive natural gas productiongrowth, full year's rate impact on Northwest and Transco, and above historicalaverage processing margins. Slide 37, to summarize, again strong third quarterperformance.

All of our businesses delivered in a major way leading to anincrease in full year earnings per share guidance of 18%. A prior version ofthis slide showed that growth of 14%.

I apologize for that. We expect 2008 to be even better.

In a pricing environmentthat is less robust than we have seen in 2007, we expect our E&Pdevelopment program to increase production by 15%. And you should expect us tocommit more capital to develop in an opportunity rich portfolio.

We arepursuing additional value levers, executing on two MLP strategies. We expect the absence of our Power business to createadditional financial flexibility.

And we're off to a strong start with respectto our share repurchase program. We believe the future of natural gas as apreferred fuel is bright, and believe Williams is well situated with its assetsand capabilities.

With that, we will take questions.

Hi. Good morning, guys.

Just a couple of quick questions.Just I guess, if I could start with Ralph, you have mentioned in the past thatyou've got about 3,800 drilling locations in the Valley, and another 37potentials up top in the Highlands. I was wondering if there has been any development in thatrespect?

Can we see a large step up in the number of drilling locations overthe next couple of months? Has there been significant progress and so forth?

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

Yes, exactly.

No, not necessarily. What we have said before is that thoselocations, particularly in the Valley, were cut off on a lateral reach, if youwill, of about 2,000 feet.We have proven that we can go out near 3,000 feet on our reach, as ourdirectional reach is now, so ultimately, as we continue to do that and get morecomfortable at that, we would add locations to our portfolio.

And then as for the Highlands, atthis point that's the same kind of technology going on up there, and we havenot been able to expand out as much. But again we have only drilled in -- Ithink we have 100 wells we have drilled in the Highlandsso far.

We are drilling about another 80 or 90 this year. Expect to be over 100or so next year.

So we continue to delineate, so it would be too early to sayif we could add additional locations to that.

Okay. And can you talk with respect to performance of therigs?

Are you able to improve on your days of drill and so forth, in terms ofdrilling costs offsetting inflation and so forth? If you can just give somecomments on that.

We feel that, like for example, the efficiency rigs, whichare the H&P rigs that we've brought in, are bringing us around on averageabout 20% improvement. Some rigs are much higher improvement versus the otherrigs in the same fleet, and we are working to make sure all of them get up tothe same level.

But we would hope to be able to continue to do that. So a 20%increase in drilling efficiencies through the H&P rigs.

We do have the four Nabors Sundowner rigs on now. And theyare just in the early stages of their life with us, and we expect the same kindor better improvements with that.

So, our goal would be to continue to do that,but so far at least a 20% or so improvement over the field average, and wewould hope to do better than that as we continue.

Great. And if I could ask one last question, just withrespect to gas management.

What is the duration of these contracts? I guess,what I am hitting at is when are we going to start to see an elimination of themark-to-market adjustments?

Is it a couple of years away or is it much longerthan that?

We are very much focused on continuing to reduce that asquickly as possible. I think, we will be able to manage that down either in thefirst quarter or early next year to a level that is less troublesome.

Great. Thank you very much.

Good morning. A couple of very quick questions.

The 25million per day constraint in maintenance was that due to voluntary closures orinvoluntary closures?

That was unplanned maintenance and some planned maintenance.Is that what you mean?

Yes.

We did not in fact, if you will, shut in, but we were shutin due to either planned maintenance. And anytime the Rockies are so tightright now even a planned maintenance will backup gas in the Rockies,and certainly an unplanned maintenance would do the same thing.

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

It wasn't by us. Obviously, it was by the pipelinetransporters out of the region.

We are just the shipper on a number of thosepipes. But some of it is scheduled on normal maintenance or tie-ins or whateverby pipes, and some of it is just they will have a disruption.

I see. Next year you are projecting both an increase inproduction and drilling activity for the E&P segment.

What's 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 biggerand better and a more powerful pool of opportunities, and you are just tryingto cull your best out of them, and you just happen to land with these numbers?

It’s really driven by our ability to continue to do thingsbetter in our efficiencies. We expect to have the same number of rigs running,for example, in the Piceance Valleyand the Piceance Highlands,but we expect that we can continue to be more efficient, and thus drive downour time of drilling and thus drill more wells.

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

No, not at this time. I think, the inventory is still veryprolific and large.

It's just that we have a number of locations to get to, asyou all know, and what we have been trying to do all along is to continue to dothat faster, and in an efficient manner and a safe manner. And each year ourteam does a little bit better, it saves a little bit of time on various aspectsof the drilling and completion program.

And thus as we get better, especiallywith the number of rigs we have and operate now that allows us to drill morewells.

Okay. What’s your exit rate for the fourth quarter, or whatdo you expect the exit rate for the fourth quarter?

I don't think I can give that at this time, because it's aforward-looking rate. But we had strong growth all three quarters, and weexpect to continue to grow.

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

Well, we have been very successful, so I would guess that weare still drilling very rapidly in the basins.

Okay. Kinder Morgan and Sempra Energy announced that theyare going to do an open season to extend the Rockies Express Pipeline all theway to Princeton, New Jersey.

Do you feel that that might conflict with whatyou guys are trying to do with the Rockies Connector?

Well, clearly that's in the same quarter, and it wouldenvision -- by the way, this is Phil Wright responding to you -- it wouldenvision serving the producers out of the Rockies andthe markets to the East. We continue to believe that we have a very cost effectiveproject and very cost effective things that we can do downstream of station 195for expansions and present the market with quality alternatives there toconsider.

And so, yes, it's a competing project in that sense, but westill believe we have a strong project. And as I said earlier, the bid responseto our open season exceeded the capacity, so we are feeling pretty good.

Thank you very much.

Good morning, everybody, and congratulations on anotherstrong quarter here. Just a few one-off questions, the first going back to theshut-ins on the E&P.

Ralph, are we seeing the same type of shut-ins here inthe fourth quarter, i.e., is this coming from Cheyenne or is this from otherissues that should be expected again?

Well, we have seen some, and obviously the disruption at Cheyennewas one thing, but at this point it's too early to tell if it's going to be thesame level. But clearly the capacity out is tied until REX is done.

And anykind of maintenance or even small disruption will back gas up into the Rockies. So it's kind of an ongoing thing.

It has been going reallymost of the year, second and third and fourth quarter. We just thought we wouldtalk about it a little bit in the third quarter because even though ourproduction growth was great at 17% production growth, it would have beenslightly higher, but we were curtailed.

So obviously, we are anxiously waitingfor the Rockies Express to kick in.

Was it a similar amount in the second quarter then?

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

Okay. Fair enough.

Don, Alan, looking at the Midstream, andspecifically with respect to risk management, I know you have got the oil pricerange out there for your 2008 guidance, but at the same time we are looking at[Calloway stripped] at around $88. And there are some concern maybe the firsthalf of '08 we might see some weaker oil prices.

Is there any attraction, I guess, towards actually doingsome dirty hedges with respect to oil or if liquid enough going out moreaggressively locking in liquids prices?

I will speak to the liquids price issue. I will let Don takeon the dirty hedge question there.

How is that? On the NGL prices there aresome very attractive prices offered, as you probably know if you follow that.

There are very steep discounts, particularly if you get intothe long dated. Get beyond about six months, and you really start to see thespread or the relationships between crude and those NGLs to fall offdramatically.

I will tell you that we did a small hedge last year; we havea small hedge on now, and we have continued to lose somewhere about 10% belowmarket on those hedges, even though we thought those were really great priceswhen we put them on. So the good news is on the gas side we have got thatcovered.

I think, it's a great question for us on crude oil, especially giventhe recent spike. And I will tell you that we are following the NGL priceofferings very closely and have been looking at a lot of bids coming in onthat, particularly in the first six months of next year.

I will turn the crudequestion over to Don.

Carl, a good question. It is one that we look at regularly.Some of the consideration, well, one is if we had hedged we would have missed alot of the upside.

Two, it is a dirty hedge, and certainly there is somepotential of lack of economic alignment there that could cause a loss, as wellas potentially lock in a profit. There are liquidity issues.

Certainly hedginga 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's something wecontinue to look at. But I can't give you any guidance as to whether or not wewill find it to be attractive in the future.

To date, we have chosen not to doit.

Fair enough. And then, lastly and I will get back into queueafter this.

Don, with respect to Gas Marketing, I guess, I'm looking for alittle more color on, absent the mark-to-market or excluding the mark-to-marketlosses, what predominately was causing that cash marketing loss? I mean is thatstill part of the legacy position?

And kind of as a corollary, are the reasonwhy you are going to kind of a neutral position in '08 going back to a priorcomment you said because hopefully we are going to manage this exposure down inthe first quarter, I mean is that what gives us confidence to getting to a neutralor positive in '08?

First I will answer. I just mentioned that the accountingrules didn't allow us to put all of the positions that were associated with theformer Power segment into discontinued operations, despite the fact that theyreally weren't positions that we would expect to continue.

So, we have something that feels like discontinuedoperations up in the Gas Marketing segment. So some of the positions, we wouldexpect to exit at a gain or loss and that we're taking steps to exit some ofthose positions, which would take out some of the -- both the drag on earningsas well as the cash impact.

Beyond that, I think, if we really think about the businessgoing forward, again it's principally in support of E&P and Midstream,providing a service, marketing, transportation and storage and over the longhaul we would expect that to be breakeven or better. We do take storage positions from time to time where we willput gas in storage, and in many cases sell it forward, lock in a profit.

Buteven in that case, the lower of cost or market accounting rules, if there is adecline in the market value, it requires to mark it down. And if the pricescome back, we can't mark it back up.

So we are dealing with that. But again Ithink longer-term we expect this to be a business that's breakeven or better.

And the other aspect of the question, as you guys look tomanage or sell down some of these legacy positions, as you are looking at ittoday or post the most recent mark-to-market. On a net-net basis are thosepositions meaningful, material or is it something that's below $50 million thatjust needs to be gone?

I would say it could be above $50 million, but certainly Iwouldn't expect it to be all that significant. And again, I think, when wetalked about the overall gain or loss associated with exiting the Power segmentbusiness, we indicated that the overall gain and loss was not expected to besignificant.

We still view these positions that -- our legacy positionsto be part of that overall exiting of the Power segment. So we are required toaccount for it in separate buckets, but we view it much, much the same.

Great, Very helpful. Thanks, guys.

It's actually Faisel Khan from Citi. Good morning.

On theMidstream volumes, can you just remind us again what the breakdown is ofkeep-whole POP and POL grouped together in fee-based volumes?

Faisel, are you wanting to know that on a volumetric basis?

On a volumetric basis.

Volumetric basis. I don't have that detail right here infront of me.

I can give you a rough breakdown of it. The majority of ourkeep-whole exposure is in the Rockies.

In fact, probably looking at our gasvolumes, our shrink volume is the best way to look at that.

Okay.

And we have about total MMbtu consumption on the Midstreamside is about 400 million a day roughly. That includes Discovery and ourolefins business as well.

Okay.

And about 65% of that fuel and shrink is in the Rockies…

Got it.

-- with the vast majority of that being at our Opalfacility. Opal is very heavily weighted to keep-whole, Wamsutter is morebalanced to fee-based.

And in the San Juan Basin about 15% of our fuel andshrink is consumed in that area. And in the San Juan Basin that mix is about 71% of ourcontract mix is either processing fee or gathering fee, and the balance iskeep-whole, and split about 50-50 between keep-whole and percent-of-liquids.

Okay.

And then the balance of our fuel and shrink is in the GulfCoast region, and about 40% of our business in the Gulf Coast is fee-based, andthe balance being split between percent-of-liquids and keep-whole.

Okay. And then in terms of your new facilities coming onlineand new contracts you are signing with customers, what is the breakdown of thetype of contracts you are signing in terms of fee-based versus commodityexposed contracts?

We continue to shift contracts to fee-based. 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 lothigher fee-based contract. So, in this kind of environment, we are generally shiftingto fee-based contracts, just because they are perceived as valuable by ourcustomers.

Okay. And in terms of your NGL customers, are you seeing anyslowdown in consumption of your liquids volumes to those customers that arechemical or refining customers?

No, and in fact, if you look at what data is available as toNGL 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 viewof that from running our ethylene cracker there in the olefins business atGeismar, so we understand the demands on that side.

And there are very strong pulls in the ethylene andpropylene 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 tooexpensive, and so ethane and propane are the desired feedstocks, and there isreally a strong pull on that.

Got you. On your E&P activities, is there any update onany of your exploration activities in the Paradox or anywhere else?

Several updates I could give you. First in the Barcus Creekarea, which is the northern part of the Highlands, we are drilling our fifthwell.

And as soon as that well reaches TD, we will have earned the 11,000additional net acres. In the Paradox, three vertical wells have been drilled todate, with our fourth well is currently going to spud by the end of the year.And we are still evaluating the wells and the results, and so we are workingthrough that new area, but also drilling ahead.

In the Piceance, we also have added a second well to what weare calling a deep well test. And this is to test what’s called the Cozzette,Corcoran and Mancos test.

And we are in our second well there. We believe thatthat could have a deeper pool of reserves below the Williams Fork, so we aredrilling our second well there.

And In Uinta, we are drilling our first well there, and weare drilling ahead -- just started about a week or so ago. So quite a bitactivity there, and that’s part of the reason why you saw the update in capitalexpenditures for exploration.

We are moving ahead on all of our projects that Ihave been talking about for the last couple of calls.

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

It is a new acreage position we have been picking up overthe last year and a half, a couple of years, and we have established a prettysolid block of acreage there. And it’s still way too early to tell, but it wastime to start testing it, and we are drilling our first well there.

How many acres do you guys have there?

About 74,000, 75,000 net acres.

Okay.

It's similar to our position in the Piceance Valley…

Right.

-- in total net acreage.

Okay. And on the Barnett, I think you guys, probably saidyou tripled production year-over-year, is that correct?

That is correct.

What is the potential of the position you guys have there, Imean, what -- is it fair to say we could continue to see a sort of growth givenyour inventory or…?

Well, obviously, the base volume will continue to go up. Butour inventory is well over a 100 locations as we speak now, and that couldincrease substantially with some, if you will, down spacing that’s going on inthe basin.

We have actually five rigs operating now. We intend to beoperating in the four to five -- probably more like the four rig level.

And wehave more locations that we are trying to secure as we speak on. There's a lotof deal flow from the -- smaller deal flow in that area.

So I think, we couldcontinue to see good growth in the Barnett.

Okay. And then on your -- in terms of picking up morepipeline capacity out of the Rockies, I think, I saw that you picked up maybe-- is it 100 million cubic feet a day to SoCal, is that new or is that old?

Well, that is a current position that it's been usedsomewhat in the Power side of the business, so we have picked up. And that isnew in the sense that we are now moving gas to Southern Californiaon Kern, and that will be part of our portfolio.

And obviously, it’s a verygood pricing point for us.

So you were able to bring over the Kern Rivercapacity that was at the marketing business into your lease capacity?

Yes, we were.

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

On the transportation side, we had already workedproactively with Bill's Power Group, so the rest of that was already in our, ifyou will, in the Williams family, and we were already utilizing it.

Okay. Thanks.

And on the pipeline side, the higher thanexpected earnings for the year in pipelines versus what you had in lastquarter, is that a result of the stipulation agreement you guys entered into onthe pipeline side, or is there something else that I am missing?

I'm sorry, stipulation agreement?

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

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

Okay. Do you have any sort of CapEx or potential projectcost for these open seasons that you have outstanding?

We have detailed the ones that we can detail in theexhibits, Faisel.

Okay. And then on the accounting and finance side.

Your cashtax 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 afunction of some of the nondeductible items that went through income in thepast. So again, the permanent differences that we have are relatively few.

So, it’s really more about the statutory rate adjusted forany 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 wouldcause that to rise sharply.

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

They were no additional shares repurchased during the monthof October.

Okay. Thank you for the time, gentlemen, I appreciate it.

Hi. Good morning, everybody.

Can you hear me?

Yes.

I’m sorry. Ralph, you mentioned something about you pickedup some acreage in the Uinta, is that in Colorado or Utah?

That’s actually in Utah.

It’s in Utah. And you are targeting Mancos?

Well, actually we are targeting -- no, in that area we arebasically targeting what would be equivalent of what we drill for in thePiceance, which is the Williams Fork Formation.

Okay. But I heard you say something about Mancos in there, Imust have gotten?

That was in the Piceance. We are drilling deeper in the Piceance Valley…

Got you.

-- targeting a couple -- we are on our second well, which isevaluating the potential that we may or may not have, and it goes from theWilliams Fork Formation, also known as the Mesaverde formation, down into theCozzette, Corcoran and then Mancos.

Got it. Okay.

And then as you look at going forward, I havebeen hearing a lot about there is a need for additional clearly takeaway, takecapacity 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 bigpipe East out of the Rockies, would you guys look atdoing something major in that regard?

This is Ralph. I think there is need for additionalcapacity, as you have probably seen from all the other producers talking aboutthat and others.

So, I think that possibly an opportunity to go to the West isa good idea. And then to continue to expand, as we have all seen theability to go to the East, whichever way that actually -- Northeast or and theSoutheast is also a good opportunity.

So, I think the good idea is or neat ideais that several pipelines are talking about those kind of things. And we lookforward to hopefully a couple of those actually happening.

Sam, this is Phil. Clearly to the extent that some of thosemake economic sense for us, we are going to be out there aggressively pursuingthem.

Okay. Thanks a lot.

Good morning, guys. I know you have already touched on this,but I just want to dig a little deeper into the Rockies Connector Pipelineversus Kinder Morgan's proposed pipeline.

I know you all said you had beenvastly oversubscribed on the deal. But their announcement had come pretty muchwhen your open season was over.

Is this the type of deal, if you take a look at your'scapacity and their's capacity, when you add them together it's pretty much wellover capacity for what is going to be coming through on that pipeline. Is thisthe kind of deal where you all might downsize a bit, or is it also the kind ofdeal 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 wordvastly oversubscribed, but we were oversubscribed.

I think, we have the rightsize pipe. I think, we have, for the timeframe in which the market wants to seethat capacity there.

We think that the shippers have sort of spoken as a marketas to when they would like to see the capacity and in what quantity. Andthere’s your observation that with both pipes there might be an overcapacitysituation in that quarter if both of them got built, is an accurate one.

And whether or not we would do something with Kinder Morganis just a question out there. I personally would think we are going to proceedwith our project -- as we go to precedent agreements we would probably justproceed.

Okay. Do you also have a time -- and I think you all mighthave mentioned this, and I apologize because I had to jump off the call at onepoint.

Do you have sort of a timing at when you are looking to lock down abinding open season?

Well as I said, we are working on it as we speak, and wehope to have those concluded by the end of the year.

Okay. Thanks so much.

Hello. Can you hear me?

Yes.

Yes.

Okay. Just a quick question on the '08 guidance, can youjust talk to the jump in corporate and other costs?

I think, it's going up bylike 80 or 90 million?

That includes minority interest associated with drop-downtransactions. So you saw we announced the Wamsutter drop-down, it will beassociated with that.

Okay. Thank you.

Hello. Can you hear me?

Yes.

Hey, there. Thanks.

Just a quick question here on yourguidance. It looks like CapEx obviously up.

Free cash flow is going to be downa bit from prior guidance. And it looks like negative free cash flow for theyear for '08 guidance.

Is that right?

That's correct and that’s by design. I think in our priorguidance, we included only the capital projects that we had a high level ofconfidence on.

And always we had disclosed that it was our goal to drill evenfaster, as well as to capture the many projects that both Midstream and GasPipelines have in front of them. So, you should have and should continue toexpect capital spending to increase somewhat as we capture those additional value-addingopportunities.

So, yes.

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

We meet with the agencies every quarter. We will meet withthem again following this call.

And we are constantly keeping them posted onour activities and our plans. And, yes, we would be hopeful of ratings action,but it's up to the agencies.

Are you thinking it's a definite goal of the company and theBoard to at some point be investment grade, or is it not really an explicitgoal you guys have in mind, I guess, given that you have opportunities outthere?

Well, the number one goal is to drive equity value up on asustainable basis faster than our peers. So that's the overarching goal.

Wethink that having stronger credit would help us achieve that goal, in thatavailability of capital is more reliable, the cost of that capital is somewhatlower. And we can be more opportunistic to seize the opportunitiesahead.

So we think a stronger credit rating, investment-grade rating isworthwhile, but the overarching goal is to drive sustainable and superiorequity value.

Okay. And that would be great.

That's helpful. Hey, thanksagain.

Thanks for your time.

Thanks you.

Sorry, guys, just two quick follow-ups, and I appreciate thetime. The first is on the other Wamsutter transaction, the WPZ, it was notedthat we were looking around $41 million of EBITDA for the first half of theyear.

Can that be broken out between how much is fee-based versus how much iscommodity sensitive?

Well first, I will remind you that first and second quarterswere not all that -- that's not where we saw the anomaly, if you will, inmargins.

Correct.

But we will be providing some detail on that as we gothrough the process. I hate to get ahead of ourselves in providing some detailthat somebody might rely on or take out of context.

I think, we will wait untilwe have put that detail in writing.

Okay. But it is fair to say that given that it has aprocessing facility, it's not 100% fee-based?

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

Okay. Fair enough.

And then just last question, Ralph. Inthe appendix, you guys have sort of annotated your cash costs around roughlythe 2.05 million mark LOE, etcetera, etcetera.

Can you actually break that outon a component basis, if possible?

Yes, I can.

And if you don't have it, we can follow up offline.

I've got it, I think. Real quick, let me just check onething.

Roughly LOE was in the approximately $0.69 range; gathering, 57;operating taxes about 44, 45; and then G&A in the $0.36 range or so. Thatmight not quite add to 2.05, but it would be close.

That’s very helpful. Thanks, guys.

Okay.

Hi. Good morning.

A couple of quick questions on theE&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, and it's goingto create some more outlets.

Obviously, it gets you to a restricted point until RockiesExpress takes off. You've had some water handling problems.

But is it basicallythat kind of mechanical issue, not so much drilling inventory that hasflattened that production profile out there?

Well, our production profile -- we were up 11%, but I thinkI see what you are saying.

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

Right, I think what you see in there is our production hasthe capability, and currently it is much higher than that. And what is going onis there was an expansion by Fort Union Gas Gathering that needed to occur thatis finally in place here in the first part of October or was in place in thefirst part of October.

And that has allowed the -- really the constraint was inthe gathering system for our volumes to take off, and improve quite a bit overthat.

Okay.

So it has not been a – it's clearly not the wellperformance, nor the number of locations, it has been the ability to get it outof the gathering and FUGG as they call it, Fort Union Gas Gathering, has takenoff, and completed their expansion.

Okay. And you mentioned -- you didn't give a quantity in theSan Juan.

That also has been an area where you have come off the peak. And Iwas just curious as to what the volume was there, because you said it had comeoff because of some maintenance and some other things going on once again inthe gathering systems there.

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

Okay. A different subject.

Don indicated that you arerunning through the NOLs and your cash tax rates are going up. How are you guyshandling your IDCs for tax purposes?

I am curious as the budget goes up why youwouldn't be sheltering more of your cash taxes?

I would say we are sheltering all that is available to us.Rick, and we can provide some additional comments offline on that.

Okay.

That’s it. Thank you.

Yeah. I appreciate your questions today.

And we aredelighted with our third quarter results and looking forward to a very brightfuture. Thank you.