威廉斯 (WMB) 2008 Q3 法說會逐字稿

Good morning, my name is Brandy and I will be your conference operator today. At this time I would like to welcome everyone to the Williams third quarter 2008 conference call. All lines have been placed on mute to prevent any background noise. After the speakers remarks there will be a question-and-answer session. (OPERATOR INSTRUCTIONS) Thank you.

Mr. Campbell, you may begin your conference.

Thank you, Brandy, and good morning everybody and welcome to the Williams third quarter 2008 earnings call. As always, we thank you for your interest in the Company. After my brief comments Steve Malcolm, the CEO, will go through some thoughts and then we'll have our CFO, Don Chappel, briefly talk about our solid third quarter results. Ralph Hill with speak to E&P results and guidance and Alan Armstrong will review the Midstream business. Phil Ride is here with us today to take any questions about the pipeline business. After Alan's remarks, Don will review our thoughts on commodity prices and how they affect our guidance. Steve will then make a few brief closing remarks before we take your questions. I realize there's a lot of calls this morning and that you all have to monitor so we'll try to be brief. Please note that on our website, williams.com, you'll find the slides from this morning. Additionally, there is the appendix that contains all of the data we typically provide. The third quarter earnings press release and all of the Company schedules and the third quarter 10-Q are also available on the website.

This morning we also announced that we're evaluating a variety of structural changes to enhance shareholder value. That press release is also available on the website. Slide 2 & 3, titled "Forward Looking Statements" disclose various risk factors and uncertainties related to future operations and expectations. Actual results, of course, will vary from current expectations due to the factors disclosed. Please review that information. Slide 4, "Oil and Gas Reserves Disclaimer" is also important and we urge you to read that slide, as well. Also included in the material are various non-GAAP numbers that have been reconciled back to Generally Accepted Accounting Principles. Those schedules are available and are integral to the presentation.

So with that I'll turn it back -- turn it over to Steve.

Thank you, Travis. Welcome to our third quarter earnings call and thank you for your participation in the call and interest in our Company. Let's start by looking at slide 6 and some of the highlights. Williams achieved another quarter of strong earnings growth. Net income is up from $198 million in the third quarter of '07 to $366 million in third quarter 08. Year-to-date net income is up from $765 million in '07 to $1.3 billion in '08. As well, recurring adjusted income per share climbed 46% for the quarter from $0.39 to $0.57 and 60% year to date from $1.14 to $1.82. Natural gas production increases 18%, third quarter '07 versus third quarter '8 from 974 a day to 1,146 a day and that production growth was really lead by spectacular 37% growth that we saw in the Powder River. Encouraging initial results in the Paradox Basin, and Ralph Hill will describe that in more detail in a few minutes. And then the last point the effect of two hurricanes and other one-time unusual items certainly impacted our third quarter results.

Looking at slide 7, obviously a strong balance sheet and strong liquidity is critically important in today's market and I think this slide summarizes our position. Total liquidity of more than $3.5 billion as of October 31st. We have over $1 billion of unrestricted cash and cash equivalents. We currently have in place credit facilities of over $2.6 billion of which $2.4 billion is available. Our primary facility doesn't expire until 2012. The total liquidity number does not include the marginless facility that we can use for E&P hedges and we also have excess capacity in the form of synthetic letters of credit that will expire in 2009 and 2010. But please recall that these were put in place when we had the power business and are not needed in our current structure. We will not have significant debt retirements until 2011 and so unquestionably we have a very strong liquidity position from which to fund our growth and in addition to liquidity I have just described in some detail, we continue to generate robust cash flow from operations.

We have, as well, substantial flexibility in our E&P program, which allows us to reduce near-term capital spending by about $1 billion in '09 and '10 so I think we are very well poised to react appropriately depending on where commodity prices head. We can ramp up quickly, take advantage if the prices move up and we think they're going to stay there, or we can cut another significant amount of capital if commodity prices fall lower than our forecast. Nevertheless, on slide 8, in recognition of the market we are scaling back our capital spending forecast. That may not be obvious since our mid point remains at $2.9 billion, but we have, in fact, sidelined about $350 million of projects that we had previously talked about as potential growth opportunities. You'll see that E&P's projected '09 spending is about $700 million below '08 levels and yet we're maintaining prior guidance on production growth of somewhere in the 8% to 10% range. Those numbers are driven on assumptions around lower rig utilization partially offsetting -- offset by higher costs and we expect the sharp cost increases we experienced in '08 to diminish somewhat in '09. In Midstream and Gas Pipes, we're maintaining spending on committed progress and deferring some others.

And so the outlook, now looking at slide 9, the outlook for the remainder of '08 and full year '09 obviously reflects the environment that we're faced with. The financial crisis, the recession have driven energy prices lower and the obvious affect is reduced projections for cash flow and earnings. The commodity prices, you look at '08 versus '09, the midpoint for crude '08 is about $105 a barrel and '09 midpoint is $30 lower at about $75 a barrel. and as well, we're essentially bringing down Henry Hub natural gas by $2 an Mcf. And so you can see how those commodity prices change our expected recurring adjusted earnings per share and the midpoints are shown on this slide and Don will go through that in more detail.

Looking at the next slide, we have announced today our management and board are evaluating a variety of structural changes in the Company as a means to further enhance shareholder value and among those potential changes is separation of one or more of our business units. I think you've seen Williams on many occasions during our long history successfully reshape and reinvent the Company in ways that create the most value. nd in the last few years we've pulled a variety of levers to accelerate value creation, and I'm speaking here about the formation of two publicly-traded MLPs, expanding one of those, WPZ, through the contribution of additional high-quality assets. We divested our power business, and completed a $1 billion stock repurchase program. We've also taken actions to strengthen the Company's credit profile, and as a result, we've earned an investment grade credit rating. Our capital position is sound and our growth opportunities are abundant.

As you well know, we have embraced the integrated model, and I think that we've performed very well. In the three years ending 2007,we delivered 128% total shareholder return. We've talked to you about the merits of that integrated model. We've talked about the fact that the stable and steady cash flows from Gas Pipes form the foundation of our credit, Gas Pipes throws off cash for investment in higher return projects. We've talked about Midstream and -- as being a wonderful internal hedge to our E&P operations, and we've talked about how the Mids -- the integrated model creates real and significant growth opportunities and you'll hear about another of those today. And so, we entered 2008 with great optimism. We had just sold power, and moved into a very strong commodity price environment and began to under perform many of the pure plays. A lot of people kept saying, well what's the catalyst around Williams and, of course, I always thought that our continued strong performance -- strong financial performance should be enough.

Then, we moved into a down commodity market as we've seen here most recently. I thought there would perhaps be some gravitation towards safety and the safety that Williams offered by virtue of its integrated model. We have not seen that occur. And so we believe that we can do more to deliver value to our shareholders in the future and the evaluation that we are announcing today is the next step in our ongoing strategic process. With any changes in the Company's structure, we intend to maintain a strong credit profile. I can't stress that enough. We've worked hard to earn this profile because it has the advantage of reducing risk, increasing our flexibility to successfully compete and seize value creating opportunities and I think it's critical given today's challenging market conditions.

As part of this evaluation we will consider macroeconomic environment, the credit markets, energy price,s among other things, but we believe that it is prudent to begin the evaluation now because these factors can be much different by next year, and so we want to be ready to act when markets improve. So as we are in the evaluation stage, it would be premature to get into further details at this point, but we do expect to announce a specific direction in the first quarter of next year and look forward to updating you then. Now I know that you're going to have questions and we will try to be as responsive as we can, but I hope you understand that we probably can't be more specific than what is in the release. And so, most of our answers to your questions will likely be " I don't know" or " I don't want to speculate" or " It's too early to say."

So with that, I'll turn it over to Don.

Thanks, Steve. Let's turn to slide 12 please. Financial results, I think Steve hit the highlights here. Again, recurring income from continuing ops after mark-to-market adjustments of $0.57, up from $0.39, or 46% increase and on a year-to-date basis $1.82, up 60%. Now let's turn to slide 13. There's a 50,000 foot view and Ralph Hill will talk about E&P. Alan Armstrong will talk about Midstream results and Gas Pipelines are steady so we won't have Phil speak to those results but as you can see focusing on the recurring column, E&Ps results are up sharply at $379 million versus $169 million in the prior year. That's an increase of 124%.

Midstream's off somewhat on lower NGL volumes and -- sales volumes and Alan will speak to that. And as I mentioned Gas Pipelines is steady. If we go down to the last line in the schedule you'll see our Gas Marketing Services, which provide services to E&P and Midstream, as well as manage our legacy positions and our transportation of storage. We had a $45 million after mark-to-market loss there and the factors in that are lower cost of market adjustment in our gas storage inventory totaling $24 million -- and you can see that in the footnote -- as well as a legacy loss related to some legacy positions totaling $10 million. So again, that was largely related to lower cost of market adjustments on our natural gas inventory and most of that inventory's been sold forward at a profit and we'll see the profit on that in the first quarter of 2009. Again, at the bottom of the schedule and in the bold type , the total segment profit after mark-to-market effects of $7 43 million, up 23% from the prior year.

Turning the page, number 14. Same schedule on a year-to-date basis. I won't spend much time on that other than to focus on the segment profit after mark-to-market total at $2.417 billion, up 40% from the prior year.

And with that I'm going to turn it to

Thank you, Don. Pleased to be here today and share a great quarter with you from our third quarter and also demonstrate E&Ps ability to participate with Williams in helping our -- flex our capital spending, maintaining capital discipline and I think the key to that is, while we do this we will be able to maintain our long -- portfolio's long term value. looking at slide 16, quarter-to-quarter highlights third quarter '08 to third quarter '07 we had 18% volume growth, our recurring segment profit was up 124%. That was obviously a function of that volume. And the third bullet, net domestic realized average price increased to 52%. Year to date we're at 20% volume growth, 105% increase in recurring segment profit growth, and our domestic price is up 42% year to date versus last year at this time. On slide 17, again looking at third quarter '08 by itself, our segment profit is up 124%, as shown graphically here by the bars, production's up 18%, and stress once again that our portfolio -- transportation portfolio and hedging program has insulated E&P from the revenues -- our revenues from the Rockies Basis blow out.

Slide 18, looking at each of our areas: Piceance Valley was up 14%; the Highlands was up 44%; as Steve mentioned, the Powder continues to have an incredible year at 37% production growth; Fort Worth, as we continue to ramp up, at 41%; and San Juan continues to actually improve in a very mature basin. The volumes reported on this slide show basically about a 1% sequential quarter decrease and that's also in our management discussion analysis, slightly down from 1,159 second quarter to 1,146. We estimate we had at least 49 million a day, as depicted by the hatched part of this slide, that was shut in due to pipeline curtailments, Hurricane Ike, scheduled and unscheduled gathering, maintenance facilities, imbalances, et cetera, so if you add that back in we actually had a sequential quarter increase of about 3% from the what looks like a 1% decline. So if none of those, what we would term one-time events happen we really would be up about 3% sequentially, so I wanted to point that out on slide 18.

On slide 19, as Steve mentioned and as Bill Barrett reported yesterday, we've had encouraging results in the Paradox Basin, where we currently hold about 220,000 gross acres and 110,000 net acres. In 2007 we drilled three vertical wells, as you all know, and we did a lot of extensive testing and coring and we had encouraging results there. We've now so far in 2008 drilled two horizontal wells and our initial flow rates are very encouraging. The first horizontal test well, which we call [Kosky], which we have a 45% interest in -- obviously Bill Barrett has a 55% interest in -- has a natural gas discovery in the Gothic shale, which I've talked about a little bit before, they flowed an average of 4.5 million a day for approximately 17 days and yielded 20 barrels of condensate, or dur -- and during the final ten days of a 17 day test -- sorry about that. The final well actually produced as high as 5.7 million a day. We are currently shut in awaiting connection to a sales line. Second horizontal well we call the Neely, we successfully completed an eight-stage fracture stimulation along lateral of about 3,655 feet out. Earlier in the flowback process it flowed over three million a day over the final three days of a seven day test so we're very encouraged with each of those.

We've also drilled another vertical well nine miles north of the Neely and we're testing that for coring to make sure we understand the shale. And then we spuded our third horizontal well, which is an offset to the Kosky well. So going forward we're planning to Barrett for -- obviously to delineate these fields to begin working with our Midstream partner at Williams, with Alan Armstrong's group, to set that up to gather this gas and ultimately take this gas to San Juan Basin. As you can see, in 2009 we're drilling up to seven horizontal wells. We obviously continue to plan to conduct extensive production testing and also construct a small processing plant to begin to get this gas, which is pretty rich gas at about 1200 BTU content, so very encouraging results from the Paradox.

On slide 20, our guidance. Looking at 2008 briefly, the 2008 profit guidance change is primarily -- is actually price driven and as we look at the capital spending , it is up from where we were last time, But as we mentioned last time and also when I talked to you at our New York conference, we did say we were seeing cost increases as the year began and those cost increases added about $100 million to the difference there. Our drilling activity as we continued we have additional efficiencies, had new acquisitions in the Piceance Highlands and we also had new acquisitions in the Barnett. We added about another $150 million of capital spending there and about $75 million for land and exploration activity in some of the new areas. Ultimately we came up to our current range of 2,350 to 2,450. Looking at 2009, again the segment profit and DD&A the change there is all price driven. Primarily, 90% of that or more is price driven and looking at capital expenditure let's turn to slide 21.

Capital analysis, where we were previous '09 guide point is on the far left side of this and let me walk you through this slide. Our production mid point was 11% growth. We had intended to, as we moved into 2009, add a rig in the Highlands. As you can see add two rigs in Fort Worth. We had land and other opportunities. We're doing well efficiencies, just meaning we continue to do better -- our team continues does -- on our spud-to-spud ties between wells. We had a number of new exploration opportunities we were looking into and obviously that cost increase that we've seen so far this year was adding to our budget to move it up to more like $2.3 billion. Production growth was at about the 14% to 17%. As we work through the current financial environment that we're all in, we're in the process of -- and this doesn't happen immediately but over the course of the next several months and next year, we will be dropping six rigs in the Piceance, and as you can see that brings us down by $240 million.

Our exploration activity will not be as robust as we had planned. Piceance facilities go along with some of the rigs we're dropping -- you can see that -- it drops down, so all this is showing our capital discipline. I think I'd also like to stress we do preserve all of our value even though we have less activity. We believe we'll continue to see some cost savings. We've seen some start to hit us and that's in there for $75 million. Land, Powder River we'll drill 100 less wells, we'll drill less wills in the San Juan Basin, and we;ll drop two rigs in the Fort Worth, so that drops us, really, to our current '09 guidance mid point of about $1.7 million. Our production still should be in the 8% to 10% range. It could be as high as the 10% range, but we're putting a ra -- at the 10% level, but we're putting a range up there right now as we continue to work through the overall final impact as we drop some of the rigs and show the capital discipline that we are able to employ.

Next slide, please, which I believe is slide 22. This slide you've seen before and answers the time, I'll just basically stress the third -- second bullet there, only 16% of our gas is priced in the Rockies. We also have Midstream consumption that offsets a number of that so you can see we do have a natural hedge in there, so I'm just showing the 16% is really what we do, E& P only, and when you add the Midstream side it really puts us very balanced if not actually slightly short. And our 2009 Rockies exposure is expected to be very similar to 2008 in that pr --- what we've seen so far in 2008 has been 14% to 16%. Final slide, I'll just hit the top bullet of the final slide. Basically, most of our portfolio is held by production so we can and we have decreased our activity which provides capital discipline. We also while doing this will preserve the long-term value growth of this portfolio for future -- our future growth and we also are very encouraged, as our partner was yesterday, for some of the new results in the Paradox Basin.

Turn it over now to

Great. Thanks, Ralph. Midstream's recurring profit for third quarter of '08 was $52 million lower than our third quarter of '07. Unique circumstances contributed as a result and I'll go through the causes. First, as a result the delayed start up of the Overland Pass pipeline capacity allocations targeted at Williams barrels on the Seminole NGL pipeline forced our weather -- western plants into ethane rejection. This caused about 41% lower ethane gallons than we had third quarter of '07. Of course the average higher per unit margins that you see in the quarter were also driven by this lower ethane content in the mixed barrel because, of course, the ethane is the lower-priced portion of that barrel. An even larger impact came from hurricanes on the Gulf Coast, which reduced not only our Gulf NGL production but also our NGL sales in the West, when hurricane disruptions at the Mont Bellview fractionators resulted in a build up of extra inventory from our western plants. This production couldn't be sold in the third quarter of '08 and will show up as incremental revenues in the following quarters as the inventory build up is fractionated and sold.

If Overland Pass pipeline had been operational when expected we would not have faced these allocations and the related ethane rejection. So we certainly saw a tightness in capacity coming on the NGL pipelines out there and that was certainly what prompted us to initiate the Overland Pass pipeline project and unfortunately that coming in a little bit late certainly impacted our volumes for the quarter. Also contributing to our lower third quarter segment profit as compared to third quarter of last year was about $29 million lower margins in our Olefins business unit. Our Gismer plant sustained damage from Hurricane Gustav, which was the first hurricane in early September, and this resulted in about three weeks of downtime. And additionally we built up ethane inventory during the hurricane period that we had to write down at the end of the quarter, as ethane prices declined and we weren't able to consume that and convert it into ethylene.

Higher operating costs in Midstream were a smaller impact and that was driven by about $8 million of hurricane-related repair cost and $7 million of higher depreciation expenses. It is worth noting, in spite of the hurricane disruption our Gulf Coast fee revenues and primarily our deepwater business were slightly higher in third quarter of 2008 than in third quarter 2007, and I'll remind you third quarter 2007 was not impacted by hurricanes. The stronger fee-based volumes were driven by additional production being tied into the East Breaks deepwater system with some new wells coming on there and -- earlier in the year and also, the new [bass] light volumes that are flowing into our Devils Tower infrastructure is now contributing in large ways to our fee-based revenues. Overall, our fee-based revenues grew by $16 million from third quarter of '07 to third quarter of '08 and even more impressive $39 million year to date in '08 versus '07, so our goal of continuing to grow more fee-based business continues to produce for us even in light of some of the set backs we saw in this third quarter.

Moving on to slide 26 here, here we answered the question, what would the quarter have produced without the delay in Overland Pass and the hurricanes, and this slide on 26 shows the impact of allocations, hurricanes and hedges. Now this slide only speaks to the impact associated with our domestic NGL business, so this does not capture anything we saw in the Olefins business here. But first is a depiction of the gallons impacted by these events, so starting on the left side of this graph you can see that the estimated normal equity NGL gallons that we likely would have sold during the quarter as being the bar on the far left there and that would have been roughly 360 million gallons. And next we subtract the estimated volumes that were lost to the allocations on the Seminole system and that was about 60 million gallons. And then this adjustment is followed by subtracting the hurricane-related gallons and first is the inventory build there and of course, again, this is product that we would have sold in the quarter except for the Mont Bellview fractionator being out of service post the hurricanes, and so that's set as raw make inventory in Mont Bellview and hopefully we'll be getting that fraced and sold in the following quarters here. And then finally, the damage from our Gulf Coast facility, so these are direct Gulf Coast-related NGL reductions that you see there, so -- and that's about 16 million gallons for inventory build and about 15 million gallons from the damages there directly.

Next moving over to the impact on the NGL margins, two things effectively netting each other out here. First of all, as I mentioned earlier, our heavier product mix. This was because the lack of ethane that was in our mix actually we had, of course, heavier products and those heavier products were more valuable, which would have driven our number up, and then that was offset, though, by the hedges that we put in place at the first of 2008 and that drove the number down by about $0.'07. And so that collar impact for the quarter was $0.'07 against all of our barrels produced but if you took that against just the ones that we had hedged, it's about $19 million of impact or flattening that we saw in the quarter and most of that was in July and August. Our hedge was pretty close to neutral in September as prices lowered. So overall, the impact was estimated about $40 million in NGL margin and about $90 million of equity gallon in the third quarter of which approximately 16 million gallons should flow back to us.

Moving on to slide 27. We're pleased that our third quarter segment profit benefited from an increase in fee-based business compared to year-to-date 2007. Our fee-based revenues were up over prior year for the third consecutive quarter despite hurricane impacts to our fee-based business. And other than the significant negative impact from the two events we've discussed we had a terrific quarter and are continuing to build to another great year for Midstream. Overall, we estimate the two hurricanes alone damaged our quarter by just over $50 million and the curtailed ethane production out west cost us about $25 million. You can see our estimated impact depicted in the hatch bar there which is roughly 70 -- a little over $70 million there in that hash bar just to try to get to something more normal, barring those incidents.

We are pleased to report that our new western projects, the Willow Creek plant in the Piceance and the Wamsutter plant expansion both to continue --or both continue on schedule and very excited about the way those projects are coming together and the growth that that'll provide us in '09 and '10. Now that our Overland Pass section from Wamsutter to Bushton is up and running our western plants will be in a position to be able to move product out of the west and into market areas for sale, so this allocation problem we have and even the hurricane impact those issues are mitigated heavily going forward. Overland Pass will result in significant lower transportation and fractionation expenses for us and ample capacity for our new production coming out of the Piceance and Wamsutter area in 2010. In addition we should not see the same hurricane effects that we saw as we'll have the capability of fractionating product at Conway and Bushton in the future. This increased reliability for our E&P customers. as well. makes our plants even more attractive in the future. So in short Overland Pass is a great ser -- is a great addition to our offering of services to our customers and we're looking forward to a new and fruitful relationship with One Oak and Overland Pass in the years to come.

There are also good things happening in the deepwater. Three new tie-backs to floating production systems that (inaudible) Discovery release -- recently announced and these should boost our Discovery volumes in the future. In addition, our new deepwater gas and oil pipelines serving Chevron's Blind Faith platform were commissioned amid the some very difficult sea conditions in the third quarter. We are now excited to watch as Chevron's teams brings the new Blind Faith field into production and we're obviously anxiously awaiting that.

Moving on to the next slide here talking about our '08, '09 guidance, we are lowering our '08 and '09 recurring segment profit guidance. This reflects the impact of the allocation issues and hurricanes we saw in the third quarter, and to a much lesser degree softening margins in '08 but certainly in '09 we are predicting much lower margins and that is the major impact for our '09 business. In response to this reduced profitability we're cutting back our capital spending by about $100 million over this guidance period, we've lowered our 2008 capital spending by $200 million, and we've raised our '09 by $100 million. This change is in response to timing on spending on some projects that got moved from '08 into '09 and the cancellation of deferral of some project independence '09. A small portion of the lower 2009 guidance and profit is attributable to the lower CapEx. Also in response to lower forward marking prices we've reduced our forecasted domestic NGL margin guidance by $100 million in 2008 and $200 million in 2009.

Our 2008 NGL margin guidance is also affected by the ethane rejection that occurred in the third quarter due to Overland Pass starting up approximately three weeks later than we had planned, and these reductions in '08 and '09 translate into lower NGL margin guidance ranges on a per gallon basis, as well. It's important to note that although we are lowering our segment profit guidance to an average $1 billion per year through this period, it still represents a tremendous return in free cash flows from this business and that's on approximately $4 billion of net assets. Additionally, we remain very excited about the number of large scale projects that will be placed into service during 2009 and 2010. Of course that includes Willow Creek 1, TXP 4 at Wamsutter, and our very large Perdito Norte project in the western deepwater Gulf of Mexico.

And with that I'll turn it over to Phil Wright -- oh, sorry, Don. Sorry about that.

Thanks, Alan. Just if we could turn to slide 30, this is a summary of our new price assumptions embedded in our forecasts and certainly, 2008 is down somewhat as a result of economic conditions and lower prices and we see big moves in 2009. I'd point out that 2009 assumptions that we're using, the mid points are somewhat below the current strip prices that we saw as of the close yesterday. Yesterday, we saw Rockies close at $5.43, near the top end of our range; we saw San Juan and Mid Continent at $6.49, again closer to the top end of our range; Henry Hub gas for 2009 at $7.69, again closer to the top end of our range; and crude oil prices, WTI crude at $75.47, just above the mid point, so big moves in prices and we've provided this comparison to the prior guidance and the ranges for your reference. But again, I'd think the ranges would appear to be in line with 2009 strip prices and the mid points generally slightly lower than strip.

Turning to slide 31, update on our 2008 forecast guidance. November 6 forecast $2.10 to $2.30, down from our August 7th guidance reflecting these lower prices. And if you turn the page slide 32, 2009 forecast guidance of $1.25 to $2.05, again lowered to reflect sharply lower prices again $60 to $90 crude environment versus $80 to $120 previously and the $6 to $8 Henry Hub natural gas environment versus $8 to $10.50 previously. I would also note that we continue to include in our package here, as well as on our website, our profit volatility relative to sensitivities in oil, NGL, and gas prices and you'll see that on slide 69, it's there for your reference. Turning the page to slide 33, recurring segment profit guidance, and this is a high-level view of each of our business units, and I think Ralph and Alan already have updated you but again, you can see the change there and again, that's largely driven by prices.

Turning the page to number 34. Graphically depicts our Rockies Basis exposure and I think the red line would indicate that we have little to no Rockies Basis exposure in 2008 or 2009. Certainly E&P has some Basis exposure that's been mitigated by firm transport, financial hedges; Midstream has the opposite exposure, and when you net the two together, we end up flat or in 2009 slightly short Rockies Basis. Turning the slide -- page, please, to slide 35, capital spending guidance. Again, Ralph and Alan went through their guidance. Gas Pipeline is relatively steady and the total potential capital that you see in the bottom line there, which I would call now more total planned capital, is down in 2009, about $350 million at the mid point and about $100 million down in 2008, reflecting tightening things up in light of these difficult economic conditions and very tight financial markets. We've deferred many of the additional growth investment opportunities at this time and will move ahead again when conditions improve.

Please turn the page to slide 36. This is a look at how we think about cash flow and liquidity. You can see there 2008 -- I'll just walk through this -- we started the year with $1.234 billion of cash. On October 31st we had $1.1 billion of unrestricted cash and $1.750 billion in total cash and the difference is largely cash that's international. CFFO of 3.1 to 3.3 backing off CapEx in the range of 3.4 to 3.6 and then a number of other factors including dividends, minority interest payments, our previous share repurchase, would leave us with $600 million to $700 million of unrestricted cash at the end of 2008. Add to that our credit facilities that are available to us and we get to about a $3 billion number at the end of the year.

Moving ahead to 2009, again starting with $600 million to $700 million, CFFO in the range of 2.4 to 3.1 and again, the range is largely dependent on commodity prices. Back off 2.8 to 3.1 in capital spending, and then minus our dividends, minority interest payments, and then we have a change in debt somewhere between zero and perhaps as much as $200 million of borrowings, brings us down to a cash balance at the end of 2009 somewhere in the range of zero to $300 million. Add to that credit facilities that are undrawn of about $2 billion -- excuse me, for total liquidity of about $2 billion. I'd also like to note that in our appendix we've included a number of slides relative to derivatives and related counter-party exposure and those are included on slides 70 through 75. We're very comfortable with our derivative counter-party exposure. We think it's well managed and very small in that all of the counter parties are A-rated or better with the exception of about less than $10 million of those counter parties and the total aggregate exposure for those counter parties is $384 million on a net basis after collateral postings.

And with that I'll turn it back to Steve.

Thanks, Don. I have nothing to add at this point, so let's take your questions. Brandy, are you there?

(OPERATOR INSTRUCTIONS)

Sounds like we're having some technical difficulties. Let's give it a few minutes and see if we can get them solved.

(OPERATOR INSTRUCTIONS) Your first question comes from the line of Shneur Gershuni.

I know that you're very restricted on what you can say with respect to the strategic review that's currently under way. I was wondering if it's fair to say that investors can assume that something will actually occur that there will actually be a transaction of some sort where you'll be separating something or selling something, and I was wondering also if you can frame it. You had mentioned in your press release about how you're looking at a scenario where you'd like to maintain a strong credit profile, how that would occur if you were to separate the business, how the credit profile would actually be able to maintain a strong credit profile given that you'd be separating a strong cash flow assets from some assets that are -- for example, like E&P where -- sorry, excuse me -- where you're potentially running beyond your cash flow and so fourth, so I was wondering if you could answer those questions?

Thanks for the question and the short answer is " No". We can't go into too much detail. I think look at our press release. We said that we were going to embark on this evaluation and that we would hope to be able to make an announcement in the first quarter as to what direction that we're headed. We indicated that, obviously, the macroeconomic environment, credit markets, energy prices and all kinds of other variables are going to be considered as part of the evaluation and really have not commented at all as to what the timing of a possible transaction might be. Regarding the credit question again, that's -- I think it's premature for us to try to speculate. I think we made it very clear that an investment grade rating, a strong credit profile is important to us today and it's going to continue to be important to us in the future.

Okay. My follow-up question is just with respect to the Midstream business. There has been a lot of announcements by many of the E& P companies about scaling back CapEx and so forth given the current environment. Based -- I'm sure you guys follow all of the announcements and so forth and I was wondering if you can comment on how you expect that to impact volumes at the Midstream segment and whether you're more or less sensitive to some of the areas that people have been looking to pull back some of their CapEx?

Yes, great question. First of all, starting with the deepwater, deepwater's probably the least sensitive to price just because it takes -- it's such a long-term perspective somebody has to go into that business with because it takes four to five years to -- even in the best case to develop a project out there. So that's probably the least sensitive and we certainly continue to see very robust drilling out there. Out west, if you look at our mix of customer, they're mostly the very large, well-heeled customers like BP, ConocoPhillips are larger customers out there and they have secured capacity out of that area and as far as we know, continue on with very robust drilling plans in those areas. So we're fortunate to have the position we have in the deepwater, and our exposure out west is largely in those basins where we've got very large customers and we're fortunate to have our customer mix we have out there. Having said that, we certainly -- from some of the smaller producers and so forth, I wouldn't -- certainly wouldn't be surprised to see some of the backing off out west but they're just not a very big makeup of our overall customer mix out west.

Okay, just one follow-up question. You gave some great clarity with respect to the margins. With the recent decline in oil prices have you seen a return to the traditional correlations between the NGLs how they would typically react in the -- given the price of where oil is and given where the price of where natural gas is right now?

Particularly on the light end products we have not seen that return. Ethane in particular has been particularly weak as there was quite a few plants that were knocked off by the hurricane, particularly in the Beaumont and Orange area that have not returned to service so we've continued to see fairly weak demand on the ethane side as a result of those plants being down and so we're continuing to see that percentage be a little bit low there. So, that's our current perspective on that.

Great. Thank you very much.

Your next question comes from the line of Carl Kirst with BMO Capital.

Hi, everybody. Steve, recognizing with sensitivity again of what you can say but just to clarify with respect to this review process, is this something where it's a full review where all options are on the table, i.e., sale of what have you, or is this really more looking at restructuring tax free spend only? I just want to make sure I know what the scope of the review is.

Carl, that's a great question but it's one that I'm not going to answer. We are very open minded --

Fair enough.

-- and are going to look at structural changes that may make sense going forward. And again, very open minded regarding the options that we consider.

Okay, no, I understand there's only a limited amount you can say. Ralph, can I just ask a question? Can you help us -- I'm looking at the Piceance, the rigs coming out, I assume that's coming out of the Highlands, I think typically we've tended to think of the valley $4 to $4.50 netback making your 10% after-tax cost of capital returns. If commodity prices were to fall further could you help us rank order where you're seeing the best returns if you will?

The actual rig -- first of all we're dropping some in the Valley also so we're dropping the Valley and the Highlands. We have some great momentum in Trail Ridge area and the Ryan Gulch area that we want to keep so we'll keep some in the Valley -- or in Highlands and so, obviously, then we're dropping some from the Valley. In general all of our projects still at the -- even at the lower October point of view that we are using, the lowest return project we're seeing out there currently is more in the 18% range and the highest is in the upper 30% range. So we actually really -- obviously the Highlands is a little lower than the Valley just by the definition of the additional drilling we have to do, so any additional initially probably would be from the Highlands, and we have a lot of flexibility in what we pull out of the Valley. We don't have as much flexibility out of the Barnett. We have very good returns in the Barnett because a lot of the Barnett leases, this is one of the few places where we have three-year terms and those kind of things, so I would guess additional dropping would -- if that's a question would be from the Valley and Highlands, but probably Highlands first. But we really like the level of activity we have in the Highlands, which is only -- in this - based on the plan we have here is basically four and a half rigs. We have one rig that's going to work at Allen Point, finish up a few of our obligations and then that rig will be absorbed into the portfolio over (inaudible), so we only have four in the Highlands working. In general our portfolio's returns are very strong still and we're running numbers as low as the $4 and $5 case type returns.

$4 or $5 in netback or $4 or $5 NYMEX?

$4 or $5 Rockies.

Rockies, okay. And then Alan, just with respect to your comments on certainly where ethane is and I guess especially where ethane is in Conway, looking at Rockies NGL margins is a little bit more challenging task with the data streams that we have, but what are you seeing right now here in early October as far as spot NGL margins in the Rockies?

Well, again, we clear -- and in either case -- in the case of Overland Pass or in our historical path out of the Rockies on the (inaudible) Seminole System, we clear our ethane barrels at Bellview. Our heavy barrels -- looking forward, our heavy barrels will have the option of clearing at either Conway or Bellview, so -- but to get to your question in terms of spot, it's no different. Our pricing is no different than what you see as the Bellview posted prices for ethane. We do clear some propane and heavy's out of the Rockies that are local fractionators and that typically works out to be anywhere from $0.05 to $0.10 higher than a Bellview pricing.

Okay, great, and then last question, more E&P again. Ralph, with respect to -- I know in the pie chart you had for the third quarter production roughly 22% was being sold into the Mid Continent market. Can you refresh our memory where specifically in the Mid Continent were you guys subject to any of the very low extreme spot prices we've been seeing over the last couple of weeks around Center Point?

Most of ours is -- ultimately, it's piped into the panhandle market, so not as bad.

Okay. Okay, thank you.

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

Thank you. Steve, I know again you're restricted but let me see if I can attack the question from a couple of different angles. My understanding would be that each of your three businesses have very low tax basis so a sale of any one of those three businesses would produce a fairly large tax leak, correct?

Lasan, I don't think we're going to comment on that today, again in terms of the specific form of the transaction, tax basis and any other details. Appreciate the question.

Okay. I would also assume then that E&P on a stand-alone basis and Midstream on a stand-alone basis would have more volatility than if you combined the two; correct?

Well I think that's clearly the case. You can see the portfolio effect within our portfolio today.

And I would guess that the Pipeline business is much more stable and so therefore, on a relative basis can sustain more debt on the balance sheet than either one of those two other businesses?

That's a logical assumption.

Okay, great. A couple questions. Does the hurricane impact add up to about $77 million?

Hurricane effect is $50 million to $65 million.

The $50 million to $65 million was just Midstream impact.

I thought there was $25 million from one and $52 million from the other?

The comment I was making on the -- again those numbers I was quoting that was just impacting our NGL volumes. As I said that $50 million number that I quoted the was leaving out the Olefins impact.

Oh, I see. Okay.

So that's the difference in the way that was broken out.

And net overall CapEx reduction for next year is how much?

CapEx reduction from our prior guidance about $350 million at the mid point.

Okay. And what is your new sensitivity to commodity price changes for '09?

Lasan, that's detailed on slide 69.

I'm sorry, I'm out of the office.

It's fairly complicated so I don't think it's something we can go through. If you want to take a look at that and call investor relations.

Got it. Thank you very much.

Your next question comes from the line of Faisel Khan with Citigroup.

Don, on the slide you detail the cash flow and liquidity, the $1.2 billion, I take it the difference between that and what you reported in your press release of $1.8 billion in cash is the difference that's overseas or unpatriated -- or unrepatriated; is that correct?

It's the interna -- principally international cash, and then it's also some MLP cash, and then call it cash that we're holding that belongs to our counter parties.

Okay, understood.

And that's detailed on slide number 83.

Okay. Sorry I didn't get that far. On the -- going to the Pipeline business, or I should say thinking about getting access of pipeline capacity out of the Rockies, with Rex-- I guess with Rex being delayed a little bit, first -- my first question is how does that affect your guys planning process at E&P, Ralph? And I guess the second question related to pipeline capacity is what needs to get done to get -- to free up some of these issues in the Rockies? Is Ruby a necessity or is there some other pipe out there that makes more sense.

This is Ralph. Let me take the first part of that. Basically factored into our Rockies exposure that we say for 2009, which is going to be similar to what we saw in 2008, which is about 14% to 16% we have factored a delay of Ruby into that, so if Ruby, obviously, would come on -- we're assuming Ruby's very late -- I'm sorry, Rex, it's not Ruby, pardon me. We have factored Rex coming on at the fourth quarter versus earlier -- I think it's supposed to be more like mid year -- so to to the extent it comes on earlier than that, then that number obviously would decrease so our exposure is factored in a decline -- or a delay in the Rex -- I'm trying to get my R's correct -- in the Rex pipeline. We also have added on to our portfolio an opportunity on Bison. But for part two let me let Phil take part two, if that's all right

Faisel, this is Phil Wright. Clearly there's enough gas out in the Rockies to justify construction of a large diameter pipe to the west. The market has indicated to us they prefer a route to Stanfield and in particular, due to market growth our market area customers have signed PAs to support that conviction, if you will. We and our partners are continuing to work to fully subscribe Sunstone. We believe there's enough producer support, or will be, to see a project get built in the originally forecast timeframe but it's also possible that a smaller scale project built later can be attractive to customers, as well. So our strategy is to work with customers to right size and route a project that we think best meets their needs.

Okay. So what you're saying is that there's a first necessity -- the first necessity is to move gas west and then east. Is that kind of how you're thinking about it?

Well that would be our assessment.

Okay, got you. And then sticking with E&P, what's the plan now with the results that you have in the Gothic shale? Where do we go from here?

Well, we obviously we need to hook the wells up and build a smaller processing facility up there initially, or a little plant, which we will do in the next year, get the wells on extended production testing. We're drilling our third horizontal well, which is an offset to the Kosky, and we intend to, with our partners, drill up probably seven additional horizontal wells next year. So really just continue to test it, see what we have and put the wells that we have on -- or that we're drilling now and get them on extended production testing and begin some preliminary facilities. That gas will flow to San Juan Basin, which we think is a good area to do that to, because flow will be in the Northwest pipe down there. So the plan is just to continue to confirm what we have and move from there.

Okay. Got you. And then on the Midstream side the equation, the NGLs that are coming out of storage in the fourth quarter, how are those being priced? Are those being priced related to your hedges you have in place or are they being priced at market?

No. Since there's incremental barrels over and above our hedge in effect that you could say it's one or the other but at the end of the day, the net impact will be at market on those barrels.

Okay.

So they went in -- they would have gone in at a cost of goods sold is what they would have gone into inventory pricing at, so basically that (inaudible) transport price and it will come out at whatever the market is at that time.

Got you. And then you did, I think, address the question on the deepwater projects that you guys are looking at, you're saying that those projects are fairly inelastic to price or because those are long term -- the long- term projects people have contemplated for a while, but what --

Right, and also the combination of the fact that you have to take out very long-term contracts generally around those drilling rigs -- those big deepwater drilling rigs and so people have locked themselves into quite a bit of that capital out there. So there's still plenty of competition for both pipeline capacity and drilling rigs, as we speak. I'd say the risk long term to that -- the risk long term would be the reup of that business if cash flows from the E&P Company started to wane and they didn't have the capitalization to go form with that, but we're not seeing reaction in the current spot pricing that's happening right now.

But the projects you guys talked about in June and July were the potential projects -- the potential TLPs you guys had talked about, those opportunities still remain out there?

Absolutely.

Okay. What about in Canada? We see a number of announcements that some of these upgraders are getting delayed or pushed back. How does that affect your business up there?

Yes, in Canada, much of the business that we were pursuing up there is already existing upgraders. There was a large project we were pursuing that has been delayed that was an upgrader project that has been delayed up there. And so it will impact us some but quite frankly there's probably more opportunity up there than we have the resources to pursue so we're not too terribly disappointed by that at this point in time. But we certainly have -- it certainly will take some of the upside, but again, we've been pretty conservative in assuming what portion of that business we could capture up there.

Okay, great. Thanks guys for the time. Appreciate it.

There are no further questions. Mr. Campbell, do you have any closing remarks?

Yes, I'll -- this is Steve. I would just say that I think that Williams has a very good reputation in terms of doing what we say we're going to do and coming forward with a plan and executing on that plan, and so regarding the announcement that we've made about exploring changes -- structural changes, I think that you can expect that we will announce a specific direction in the first quarter. And so with that, I appreciate your interest and your participation and we look forward to talking with you again.