威廉斯 (WMB) 2009 Q4 法說會逐字稿

Good day, everyone, and welcome to the Williams Companies fourth-quarter year-end 2009 earnings release conference call. At this time for opening remarks and introductions, I would like to turn the call over to Mr. Travis Campbell, Head of Investor Relations. Please go ahead, sir.

Thank you and good morning, everybody. Welcome to our fourth-quarter call this morning. As always, thanks for your interest in the Company. As we have done in the last few quarters, Steve Malcolm will review a few slides. Be aware though that all of our business unit heads and Don Chappell are available here to take questions, which we will do right after Steve's remarks. Also, as usual, we have put together our data book that includes the information that we typically provide each quarter.

So this morning on our website, williams.com, you should be able to find the slides, the data book and the press releases that were issued earlier today. Those press releases are the release detailing our 2009 results, as well as an additional release reporting our 2009 natural gas reserves.

Last evening I'm sure you also saw the release announcing the completion of the asset contribution between Williams and Williams' partners, WPZ. I should note that post that transaction WPZ is a significant part of Williams. WPZ will be having their 2009 earnings call this morning at 10:00 AM Eastern. At that time WPZ management will be available to talk more about their results and their future. It might be worthwhile to tune in for that call as well.

At the beginning of the slide deck are the forward-looking statements and disclaimer on oil and gas reserves. Those are important and integral to our remarks, so you should review those. Also included are various non-GAAP numbers that have been reconciled back to generally accepted accounting principles. Those schedules are available and follow the presentation.

So with that, I will turn it over to Steve Malcolm.

Thank you, Travis. Welcome to our fourth-quarter earnings call. Thank you for your continuing interest in our Company, and, as Travis said, we are going to use the same format that we have used in our last few earnings calls. I will be the sole presenter, but the entire team is on hand to answer any questions. We continue to get good feedback on that approach, and we will continue it today.

So starting with slide four, I believe -- yes, slide four, this slide talks a little bit about our 2009 results, recent developments. Let me pick through the list here fairly quickly. 2009 recurring adjusted income was $552 million or $0.94 a share for 2009. I think most importantly we completed our asset contribution transaction with WPZ, which is clearly designed to drive growth and value creation for our shareholders. Our year-end 3P US and international reserves are up 14%. We continued the expansion of our Marcellus shale position with a new long-term agreement with a major producer which will expand our business in the Marcellus and allow us to construct a new 28-mile natural gas gathering pipeline which will move gas into Transco. Construction on that project is expected to begin the latter part of 2010 and expected to be placed into service during 2011.

We also brought other expansion projects into service on Transco and Northwest. I'm speaking here about the Sentinel expansion Phase 2, which is a little over 100 million a day of additional capacity which went into service in the fourth quarter of '09. The Colorado Hub project, which increases access to the Piceance Basin for our Northwest pipeline customers, that went into service fourth-quarter 2009. And our Eminence storage enhancement project, which was placed into service in October of 2009. As well, we recorded peak day delivery records on all three of our pipelines this winter. It is good to see that our pipes are getting strong usage during the peak days.

The next slide is slide five. This is a slide that investors have appreciated in the past, and so I will spend a few minutes on this slide. It shows the reconciliation of how our domestic reserves grew during the year. So starting with that first bar there, we ended last year with 4.34 Tcf of proved reserves. We added 159 Bcf through the Piceance acquisition that we closed in the third quarter. Our well head production was 435 Bcf.

Then we go to the next three bars which show how the new SEC rules for reserves flowed through our numbers. And so this year the rules call for using the 12-month average price for the year rather than the year-end price. And this resulted in a basin price of just over $3, which is a 33% drop from the price used for our year-end 2008 proved reserves. So, at the lower price, we had a 336 Bcf of price-related revisions.

Also, the new SEC rules are much more specific about what undeveloped locations can be counted as proved. The rules restrict development time to five years and require for the first time that we consider the conversion ratio of probable to proved locations in our drilling program. This rule requires we reclassify 496 Bcf from proved back to probable.

On the plus side, the new SEC rules for the first time allow us to count un-drilled locations that are more than one offset away from a producing well as proved where we have reasonable certainty of production. This allowed us to add 454 Bcf as shown on the next bar.

We also added a net 570 Bcf of proved reserves through the drill bit, making our net proved reserves at the $3 price, 4.255 Bcf. This is a very similar result as we have had the previous several years, in spite of using a capital budget of about half the level from 2008, which reflects the strength of our overall 2009 drilling program. However, since the 2009 price was unusually low and is much lower than current gas price expectations, the next couple of bars show important price sensitivities. Our proved reserves are 4.581 Bcf if we simply add a $1.00 to the SEC price. Hence we get back all most all of our price-sensitive reserves at about $4 in the basin.

As an apples to apples comparison, our proved reserves using the same price that we used last year, or $4.61 in the Rockies, our proved reserves are $4.632 Bcf. This constitutes 7% reserves growth in a year where we significantly reduced capital spending and 167% domestic reserves replacement. We reduced our three-year finding and development costs to $2.38 per Mcf and our one-year drillbit only F&D was $1.53. We are very pleased about this reserve's performance, which continues our multiyear trend of strong proved reserves growth and best quartile F&D costs.

Looking at proved, probable and possible reserves, the 3P side of the world, the story gets even better. We ended last year with 12.6 Tcf of domestic 3P reserves and have now grown that 14% to 14.4 Tcf of domestic 3P reserves.

Turning to slide six, I'm not going to spend much time on this slide. This judge shows US and international reserves, and I think the key takeaway here is that proved, probable and possible, 3P reserves, are up 14% year-over-year.

Slide seven yesterday we closed our $12 billion strategic transformational restructuring designed to drive growth and shareholder value. Clearly it significantly accelerated our drop-down strategy, and let me quickly run through the key points. This transaction created a large diversified MLP that has an investment grade credit rating, much more reliable access to the market. It significantly increases our capital availability and proves, I believe, the competitiveness of our Midstream and Gas Pipeline operations. E&P and Canadian projects will be funded from their own cash flows and WMB funds and WPZ distributions. Importantly, Williams is able to maintain scale, earnings, cash flows, IDRs and control of the assets. This deal enhances our Williams growth profile, and I think overall simplifies our corporate structure and creates a public marker in terms of being able -- having investors being able to value our Company.

The next slide I think shows that Williams and WPZ interests are clearly aligned. The moves that we have made result in two well-capitalized entities that are better positioned to pursue value-adding growth strategies. Certainly growth and projects at WPZ lead to more value at Williams. And, as you can see on the slide here, the ability of WPZ to fund capital projects for its midstream and Gas Pipeline projects means that Williams can focus free cash flow on growth and diversification of our E&P portfolio.

On the WPZ side, increased EBITDA and distributable cash flow translate into higher earnings per share for Williams, and as PZ increases its unit distributions, Williams receives more cash. And through Williams significant ownership position in PZ, Williams will enjoy the value benefit of growth in PZ's unit price.

Slide nine, please. Our guidance is unchanged, but just as a reminder, as you can see here, we expect that earnings growth will continue in a very strong fashion. And yes, improving energy commodity prices do play a role in that earnings growth through 2011, but, as you can see in these arrows in the lower left-hand corner, we expect our earnings growth to be significantly greater than the improvement in commodity prices during that period. The green arrow shows 99% growth in our adjusted earnings-per-share from 2009 to 2011, and we do not need $100 oil, we do not need $10 gas in order to get there. You can see what assumptions that we are making with respect to crude oil prices and natural gas prices during the period, and importantly, the midpoint of our guidance range for 2011 moves us close to the record high earnings that we produced in 2008. So clearly we are investing today in future growth. We have projects coming online this year and in the future that we expect to make significant contributions to our earnings growth.

Slide 10, please, here we take a look at what the 2009/2011 growth looks like from a segment profit standpoint, and overall we are expecting to increase our total recurring adjusted segment profit by nearly 50% from 2009 to 2011. We expect to see a greater than 100% growth in our E&P segment profit based on higher commodity prices and by 2011 increased production volumes. And in the WPZ and other, of course, we are expecting increases there associated with the many growth projects that we are investing in over that time period.

Slide 11, this slide shows the maintenance capital and growth capital for WPZ and E&P. This is a good reminder of the clear path that we have to our earnings growth. We are investing in excess of $3 billion in growth projects during 2010 and 2011, and I would remind you we are making investments with a continuing commitment to live within our means.

Slide 12 I'm not going to spend much time on this slide. This type of slide is appreciated by investors. It simply shows the specifics on some of the growth projects and growth CapEx that we will be spending in 2010 and 2011 on WPZ and on E&P projects. You might be surprised when you see a fairly large number that shows up under the other category, and I would just remind you that much of that capital is tied to the Canadian NGL pipeline, which is a new 12-inch pipeline project that will transport NGLs and olefins from our extraction plant in Fort McMurray to our Redwater processing facility. It is expected that we will be spending somewhere between $275 million and $300 million on that project constructed using cash previously generated from our Canadian operations or other international projects, and construction is expected to begin in November of 2010 with an anticipated in-service date in the second quarter of 2012.

Slide 13, the next few slides offer detailed comments on growth projects within all three of our business units, and I will start with some comments on E&P. Certainly in the E&P space, most of our capital, most of our growth will be focused in the Piceance Basin. So it is always worthwhile to emphasize the value-creating strength of our Piceance Basin strategy. Clearly this is a world-class resource. The drilling economics of our shale play is strong. I've got -- my next slide talks a little bit about the typical well economics for a Valley well. And just to foreshadow for you, the returns, we re looking at after-tax returns based on current prices, current costs and the current basis differential. We are looking at after-tax returns in the 53% range. So clearly this is a world-class resource that has drilling economics that match those that people are talking about in the various shale plays. As well, our costs are low. We have a track record of high returns. We enjoy the benefits of scale. I think you know that there is extensive infrastructure in place, including our own gathering, processing and pipeline assets, and compare that, please, to the extensive investment that is still needed in some of those new shale plays.

So we expect to grow production. Our capital guidance numbers deliver about 12% production growth in 2011. But, as the last bullet mentions, we are poised as we check signposts along the way, as we see what future prices are doing, and as we get through the heating season, we are poised to begin to accelerate our drilling activities by midyear. And such an acceleration could, if we decide to proceed with that, could increase our production growth to back to the 20% range by 2011. You know we have been at that rate in the past, and I think this demonstrates our ability to ramp up quickly if the commodity prices are attractive.

I mentioned earlier, next slide 14, is an update of our typical well economics for a Piceance Valley well. I think we talked about this during our May call. Just to compare the numbers, our net cash margin back when we talked about this in May was $2.60. Our after-tax IRRs were 28%, and you can see we are now looking at a net cash margin of 3.45, after-tax returns north of 50%, and it is simply a case of higher prices, lower basis differential translating into higher returns for a typical well in the Piceance Valley.

Slide 15, please. This just highlights some of the strategic growth projects in the Midstream space. Obviously we are very excited about expanding our footprint in the Marcellus. Of course, we did the Laurel Mountain JV in 2009. We have expanded upon that with what we are calling the Springville project, which I described earlier, which expands our business in the Marcellus, has us building a 28-mile natural gas gathering pipeline from a central delivery point in Susquehanna County, PA to Transco in Luzerne County, PA, a 20-inch pipeline which is expected to be placed into service in 2011.

Other major PZ projects, Perdido Norte we are expecting to begin contributing to segment profit in mid-2010. Wamsutter TXP4 we expect to bring an additional 350 million a day of processing capacity on stream at our Echo Springs plant in late 2010, and the Willow Creek will be enjoying a full year of operations at Willow Creek. We achieved full processing operations in September of 2009 and are currently recovering up to 20,000 barrels of NGLs at that facility.

Slide 16, please, gives you again a quick overview of all of the projects that we have in the Gas Pipeline space. We continue to receive long-term customer support to expand our footprint, along Transco, along Northwest pipeline, and along Gulfstream. I would remind you the blue box projects are in guidance. The gray box projects are not in guidance. And some of the more significant projects noted here, the 85 North Expansion is a $240 million expansion from station 85 North to Zones 4 and 5, adding over 3 million a day of capacity. That will be a two phased project going into service in mid-2010 and mid-2011. We have the Rockaway Lateral, which is a $120 million lateral into National Grid's Distribution System in New York; the Midsouth Project, $195 million expansion from Station 85 to points North. So a lot of exciting projects, and again all of these are backed by long-term customer support.

I'm going to pause here for a minute in terms of my slides and go through some Q&A. We did it last time, and it seemed to play well. But we have been getting some questions from investors and some of the common themes of those questions I might cover right now. There have been a lot of questions on drilling costs in the Piceance. Have we had any ability to lock in any of the costs? And, as I'm sure you are well aware, the costs for drilling and completion came down in 2009, and we have made efforts to try to contain future increases for 2010. And some of the success that we have had, we have locked in dayrate costs for all of our rigs through 2010 in the $16,000, to $17,000 per day range, and I would remind you that's about $2000 to $4000 a day lower than the average rates in 2009.

Pumping service costs for cement and stimulation are also under price agreements through 2010. Other key service costs such as mud, water handling, rentals, construction, these are all looking to stay flat with 2009 based on discussions with many of our vendors. Probably the only area where we are seeing some upward price pressures on steel costs.

We have also had a lot of questions about midstream economics. People have recognized that economics are very strong right now, and they have been asking, what is our outlook for the future? And so you're absolutely correct. Our realized margin has risen from a three-year low of less than $0.20 in the first quarter of 2009 to more than $0.50 in the fourth quarter of 2009. And given the current market and our assumptions about commodity relationships, the 2010 and 2011 margins should easily surpass what was achieved on average for all of 2009 and could even exceed the high point that we achieved in the fourth quarter of 2009. We also continue to be very pleased and optimistic regarding demand for our NGLs and the resulting NGL margins.

Ethane demand in the US pet-chem industry average in excess of 900,000 barrels per day in the fourth quarter of 2009, and this is a new record high for demand on a quarterly average basis. We continue to expect to see demand stay high as the global oil to gas relationships continue to place the US pet-chem industry in a very competitive position globally, as well as the continued conversion to a more light-end feedstock slate. NGL inventories continue to get worked off as the combination of gas plant production and other sources are not able to keep up with demand. And so this inventory work-off will continue to put strength around our NGL pricing complex as has been recently exhibited in the NGL to oil ratio, which is now exceeding 60% on a composite basis versus a year ago's quarterly average of about 55%.

So let me turn now to our concluding slide. I think it is slide 17. This shows just the key takeaways around the theme that Williams is a winning long-term investment. Certainly, as we have gone through the slide deck here, I hope you believe that we have a wealth of value-creating growth opportunities which lead to the sustained growth ahead as reflected in our 2010 and 2011 guidance. The transformational transaction will clearly help fuel that growth. The integrated businesses, the integrated model, I believe, gives us a competitive advantage, particularly as we intend to increase our footprint in the Marcellus. I believe that we are able to offer producer customers a more comprehensive midstream pipeline and gas marketing solution to their service needs. The Piceance Basin is a world-class resource, continues to perform very positively, and I think I would refer you back to the very attractive Valley returns that are reflected on that slide.

We are committed to financial discipline as we grow. We have achieved investment grade ratings, we intend to keep those ratings, and I think the final point, we expect 2011 earnings-per-share to be double our 2009 performance.

So with that, we will be delighted to take your questions.

(Operator Instructions). Craig Shere, Tuohy Brothers Investment Research.

Two quick questions. Ralph, can you talk through what basins were most affected by each of the respective price-related and five-year SEC development rule reserve revisions? And Steve, can you put more flesh on the bone regarding what kind of price points you are looking at before you start to decide to press harder on the gas pedal for E&P production?

On the price side, really it is proportional to the amount of reserves we have in the various areas. So, on the 336 Bcf price revision, first of all, about 100 or so Bcf of that was just the tail of reserves that would come off and become economic based on the lower price way out in the future. We obviously believe those will come back, but proportionally most of our reserves are in the Valley and the Highlands. So, thus, on a proportional basis, they came out of the Valley and the Highlands.

Okay. And the five-year -- (multiple speakers)

The five-year was interesting. Really the way that works is about 80% of that was in the Highlands, and the way that truly works is that it is very complicated. But in the past, basically if it was in our drilling program, it basically counted as a proved undeveloped, and we were able to count that. Now if it is in the drilling program but it might be a probable location because we haven't taken advantage yet of the Highlands and the one-off rule, we were only able to book the PUD side of that world. Some most of that was in the Highlands.

And the interesting thing about the Highlands is we increased our drilling program, which we are in the process of doing. We went from one rig last year. We're going to be at four in August, and, as Steve mentioned, we may pull the trigger and do some more. As we prove up more of that field and actually what we call triangulate some of these areas, the one-off rule could be a very big thing for us in the Highlands since we have over 5 Tcf of probables and possibles in that area. So we look for that one-off rule to be a tremendous advantage for us and this five-year limit to be a one-time disadvantage, and we look forward to the opportunity to continue to drill, delineate the rest of that field, triangulate around that area, so we can call more than one offset and really take advantage of over 5 Tcf of probables and possibles.

I got you. That was very helpful. Thank you.

And in terms of the second part of your question, what kind of price points we are looking for, I mean there continues to be a great deal of uncertainty with respect to where prices are headed. We have been delighted by the winter. We have been delighted by the fact that storage inventories have been pulled down. But there remains uncertainty. I think people are trying to figure out the EIA supply data, trying to understand to what extent we have seen deliverability reductions. But I think the short answer would be, if we get through the heating season and futures prices continue to be strong, particularly strong to the point where we are still able to capture the kinds of well economics that are shown for a typical Piceance Valley well, I think that under those circumstances we would want to accelerate our drilling activities in the Piceance.

But your guidance for 2011 I think assumes 650 still or somewhere around maybe a 612 strip right now. If you're given the profitability in the Piceance, if you're still north of $6 after the withdrawal season here, would you still feel like at $6 plus, there is no reason to hold back?

Yes. I think the short answer is yes. If we're still looking at futures prices north of $6 given the kinds of returns that we are seeing in the Valley, I think that we would want to accelerate our activities.

Faisel Khan, Citigroup.

If I could ask a couple of questions first on the Midstream segment. I noticed that the volumes, the NGL volumes, sales volumes, were down sequentially fourth quarter -- third quarter to fourth quarter, and it looks like a lot of those volumes were in the Gulf of Mexico and the Gulf Coast region. Could you guys talk about what was going on over there?

Sure. You're looking at just the fourth quarter to the fourth quarter?

Fourth quarter -- from third-quarter '09 to fourth-quarter '09.

Okay. We had a couple of issues. One, we have a contract in the Mobile Bay area there with Exxon and Shell. Shell had quite a bit of work that went on on one of their plants, and Exxon had the rights to -- they have a monthly right once a year to be able to elect out their liquids and take their liquids. And so that is one of the primary drivers on that drop there in the fourth quarter.

Okay. So we should see those volumes bounce back in the first quarter? Is that fair?

That is correct.

And I just on your data book that you guys put out, looks like you have GP distribution of WPZ to the seed corporation of about $140 million. Is that a change from what you guys have put out in your January 19 restructuring presentation?

This is Don. No, that is not. That is consistent with that, and that is the cash portion from a net income standpoint. We earned somewhat more, but with the coverage ratios and all, those numbers on the slides there are cash numbers. But that is consistent with what we put out before.

Okay. Great. And then on the E&P side, the higher DD&A expense in the fourth quarter versus the third quarter looks like it is ticking up. Is there something going on over there, or should we continue to see DD&A go up through the year?

It just really is a function -- if you are talking about the rate -- it's just a function of the capital investment over the last couple of years. So it is going up slightly as we continue on.

Okay. Great. And I just wanted to make sure I understood the last answer to the last question on the revisions related to the five-year limit. So 80% of that was in the Highlands area, and that was because of lower drilling activity last year in the Highlands? Is that fair?

Well, that is one way to look at it.

Well, that is one way to look at it. Because of lower drilling activity, we were not able to continue to -- we were not able to really take advantage of of what we did in the Valley and the one-off rule. So essentially when you look at it, under the new rules it is your historical conversion rate. I could go on and on, but yes, I would say when we get back in the field, which we are and start drilling more, and as prices have improved, which they have, I expect to see very positive results, assuming prices stay where they are and assuming also that we get back in the field, which we are already in the process of doing.

And the CapEx guidance for 2011 for E&P is pretty wide, $1.3 billion to $2.1 billion. I guess what does that large bandwidth sort of contemplate?

You're talking 2011?

Yes, sir.

It is just really potentially the opportunities that Steve talked about. We already are moving from about 12 rigs in the entire Piceance complex area in 2010. The plan in 2011 is to go to 22, and we have the opportunity do more. So that is why the range is so wide. Plus, some of the other new things we are looking at could possibly play into that, so we're just giving a wider range of what we hope we have to succeed during this year.

I might just add something to that. Again, we have a fairly wide range on commodity price. I think the market is fairly close to our midpoint. So that is I think the best way to think about it. But if prices were very low, we would restrain our drilling activity. If prices were exceptionally high, we might put more capital, even more capital to work, in the E&P, then we would at something close to current market prices.

Mark Caruso, Millennium Partners.

Just a few follow-up questions or a clarification actually. The first question was, did you give a capacity on the new Marcellus pipes? I know you're saying mid-2011, but I did not hear a capacity on how large that pipe could be.

That will be a little over 350 million a day of capacity.

350 million a day, and is that 100% contracted with Cabot, or is there still opportunity for either equity volumes or more third-party volumes?

There is some additional space. We've got the ability to expand that pipeline beyond the Cabot piece there initially.

Okay. And then on the guidance side, it looks like if I do the math right, midstream fracs on a gallon basis are higher than guidance, but you guys did not increase guidance for 2010. I did not know if you could give a little more color around that. Ordinarily the range for 2010, I guess, on midstream.

On midstream, sorry. Well, certainly if you look at the current markets, the current markets are certainly exceeding those guidance numbers that we got in there as we head into the first part of the year. However, if you look into any of the forward market, that certainly is not supported above that. And so we are wanting to see what happens when we get through the first quarter here.

I will see say that the fundamentals, as Steve mentioned, the fundamentals are probably better right now than they have been in a long time and giving us some optimism just looking at storage volumes and the way we are continuing to chew through some of the light end production and storage right now. So we're hopeful that we will be able to do that, but a little early to call at this point.

Okay and just one last question. I'm looking at the 2011 numbers. It looks like E&P went up, but overall did not change. Is that just a matter of when I was looking at the slides, getting lost in the consolidation, given the fact that you now own 80% and how it consolidates up?

Yes, I think that was just a bit of refinement in our guidance. We did not think the changes were sufficient to warrant any overall change.

Jessica Chipman, Tudor Pickering Holt.

I have a question related to Marcellus. I know that you guys are in the beginning stages there. My question is whether or not you can give us a little more color going into 2010. I think as of last update you had one rig running per your Rex JV in the Marcellus. And since then you have also added about 6000 net acres outside of that JV if I understand that correctly.

My question is, if you would not mind giving us a little color on where that acreage was added? Is it around your current footprint, or are you looking at areas outside of those counties? And also how you plan on allocating capital in the Marcellus. Do you plan on drilling on that acreage outside of the JV, or will you stick first to the Rex JV?

Well, the acreage we acquired, some of this is around the Rex deal, and other acreage is up primarily in the Northeast area, some of the more active counties that you have seen, the Susquehanna side of the world and surrounding counties. We actually have a large buy area that we have starting from the northeast side going down to the southwest side. So we're actively prospecting in really the entire play.

We currently have, as we have just now taken over operations, just the one rig that we will be operating and I believe Rex will be operating on another part, a rig or two that I think they give their update in a couple of days. So our plans going forward allocating capital would be we will continue in the Rex area, and we also would like to at some point add another rig into our new acreage, and also we would hope that we have some other successful deals concluded in other parts of the play.

Okay. And if you -- do you add a rig outside of that acreage in your JV, will you press release the results, or will you wait and update quarterly for the Marcellus?

We have not really thought about that. We will probably -- we're not one to ever beat the drum on an initial production that comes out of a well, but we will probably after we feel the well is in good shape that we will probably give updates as needed at least quarterly, but we may do it more often.

Yves Siegel, Credit Suisse.

A couple of questions. One, Alan, as it relates to processing margins being so good right now, how does that figure in your decision to perhaps hedge or not hedge?

Well, we certainly feel like the forward market right now on NGLs, if you went out and tried to hedge right now, we think is really oversaturated with sellers, largely I suspect driven by MLPs that do not have enough fee-based business to reduce their volatility in a situation where they are having to go in and re-up those hedges. And so there's just tremendous pressure on the sell side in that forward market. Really the only buyers that appear to be in that market appear to be the banks.

And so we just -- if you just look at the value, the spread between gas to crude going forward versus the gas to NGLs, it is a dramatic decline. In fact, the forward market on crude to NGLs is declining about 15% even with crude in contango. So we really feel like there's not much value right now in that forward-looking hedge. We are certainly continuing to look for opportunities there, but, as it appears right now, it's more of a buyer's market than a seller's in that forward market.

Philosophically have you laid out any new guidelines in terms of how you want to approach hedging?

No, we really have not. We continue to look at that on an opportunistic basis, and if we think the market is a fair reflection of the forward value and we need to reduce volatility, then we will certainly act whenever we see those opportunities. But we have not really laid out any new philosophy on that.

Okay. And then I --

This is Don. I would just add that again we have a very strong balance sheet at WPZ. We have a strong coverage ratio, and we think we have the strength to weather that volatility despite the fact we would love to hedge more. But nonetheless, I think as Alan points out, we are unwilling to give up a great deal of value because we don't need to. So we will be more opportunistic in terms of taking risk off the table.

Okay. And if we could just turn back to the Marcellus, number one, can you disclose how much the pipeline will cost? And then number two, could you also talk about how you see gas flows going forward? I'm talking about the dry gas that gets into Transco. Is that going to be staying up in the East, or do you think you might see it backhaul?

And then thirdly, have you given thought perhaps to the liquids in the Marcellus in terms of perhaps coming up with a solution either going up to Canada or going down to Mont Belvieu?

Don't get me started on that third one. That third one has a lot of opportunity around it, and it is certainly an issue in need of a solution right now that we are working hard.

On the first matter, no use for competitive reasons. We are not releasing that capital investment just for transparency's sake on that. And secondly, on the question of volumes, backhauling, certainly let Phil speak to his perspective on Transco on that. I can tell you from our vantage point that it is pretty early. There is not near as much production as there is talk of production just yet. And so I certainly think it has the potential, but we are a ways from that, and I will let Phil speak to what he has seen.

This is Phil. I agree totally with Alan. I would say that the opportunities to do backhauls are clearly there, and we have customers interested in backhauls. And we have been doing them for a long time on Transco. For instance, customers in the Southeast region have benefited from taking gas from [Cold Point] by the [Lide] hub into the Transco system and down for a long, long time. And so to the extent that volumes in the Marcellus ramp up and we have customers throughout the Transco system that through displacement want to do backhauls and the like, we can accommodate that very nicely.

Carl Kirst, BMO Capital Markets.

Most of my questions have been hit here, but maybe if I could just do a follow-up on the Marcellus. Ralph, you were mentioning that we are hopeful we are going to see some things shake loose here. I was wondering if you could comment on we just had Anadarko look like it had a pretty good price for some of its acreage. Are you seeing the land values continuing to heat up to the point where beyond what you guys might be working on today, there will be further opportunities from an acquisition side, or are we kind of shifting back to more a slower bootstrapping approach again like we saw in this last quarter where we will just see the earnings release and every quarter we might be adding 5000 acres a quarter, so to speak?

Well, I would say obviously, as Steve mentioned, we are going to be very disciplined in what we do, but we're looking at it really from the grassroots leasing side, the joint venture side. And obviously, again in a very disciplined manner, there are number of big players, small players, medium-size players out there. So we're also looking at it from the A&D side.

So I think from an E&P perspective we're going to continue to look at it from all three of those angles, and hopefully through a disciplined manner, we will see some good growth there.

I do think we do bring to the table, as Steve mentioned, a very strong Williams story to the Marcellus. If you think about it, obviously the E&P expertise that we have, our midstream expertise and the need -- desperate need for some midstream solutions out there -- Transco runs right through the heart of the play. And then our gas marketing people have been very successful in helping out in some of those interests we have going and actually taking the producers gas and marketing it for them.

So we are looking at it from E&P from a three-pronged approach, but really Williams is looking at it from a four-pronged approach. So we think we have a great Marcellus story, and we're getting a lot of good feedback on it. A lot of good meetings held. So hopefully we will continue -- we will see some success with those conversations we are having.

Okay. Fair enough. Could you give us an update -- I apologize if you had mentioned this earlier as I was taking notes -- but where are we on the latest with respect to the Paradox?

On the Paradox we continue to be encouraged. I know Baird has their conference call in a couple of days, but we are encouraged with the 13H well, as we call it, that we have been monitoring for quite a while. We look -- I think Joe actually is going to give some decline curves and some type curves around that. What we are really looking forward to is the ability to repeat that in that area and also in the aerial extent of repeating that.

So, as we continue to work with them, we hope to -- if we remain encouraged, which we are, probably drill at least a couple of more wells, continuing to delineate and see if there is an opportunity to find that aerial extent of the play, and see if it works like it is in that [Coskey] area. So we are cautiously optimistic and looking forward to hopefully drilling a couple of more wells and getting some more tests and some more areas defined out there.

Andrew Gundlach, ASB.

Most of my questions have also been answered. I have a question on the Piceance Highlands and Valley on the economics that you put in the data book. I don't know if this is for Ralph or for Steve, but I understand the difference and the drill and complete. What I do not fully understand and which leads to a lower but not insignificant IRR is the location difference and differential and transport differences between the two areas and also the working interest. Could you just put a little light on that?

Yes, on the working interest, what we have done is we have blended the various areas out there. For example, we own -- on the Trail Ridge area, we basically own all of that. In the Ryan Gulch area, we own 51% and Exxon owns 49%. So that blends the working interest. This year we are drilling about two-thirds Ryan Gulch and one-third Trail Ridge there.

On the differential side, the location and differentials, it is all in the liquids value. Basically it is included between the two. And the amount of reserves differential is essentially the Highlands area has a little deeper formation that we are also tapping into, a little thicker column. So a little bit more reserves in the Highlands area.

I see. And what explains geologically or reservoir-wise the much higher IP rates in the Highlands?

In the Highlands, again, it is that thicker column. It is the ability to tap into a little deeper formation also than just the Mesa Verde.

Jonathan Lefebvre, Wells Fargo.

Most of my questions have been answered.

Sir, did you have any other questions?

I do not. Thanks.

Holly Stewart, Howard Weil.

Two questions, one for Alan. Following up on Mark's question on the new Marcellus gathering line, is that 350, is that all for Cabot, or do you guys have some volumes on that as well?

No, it is not all for Cabot. We do have some remaining space on that.

Can you break that out for us?

No, we are not disclosing that detail.

Okay. And then I guess a follow-up for Ralph. 4Q volumes were a lot better than our expectations considering the pullback in capital during the year. It looked like you got a bump in the Powder River and the San Juan. Can you provide a little color there for the Q and then thoughts moving into 2010?

Well, for the quarter basically the powder is just always a function of the de-watering side of the world, and we had some benefit from that. San Juan is just we actually did some additional drilling there that we have not done before and earned a farm-out. So just some good surprises -- not surprises but just good timing of those things coming on.

For 2010 essentially we are -- the plan and the guidance you have seen so far just basically shows like flat production for 2010 and then growing to about 11% or 12% in 2011. And that goes into what Steve talks about. To the extent that we get back in the field earlier, we obviously plan to have -- grow from the 12 to 22 rigs, for example, in the Piceance from 2010 to 2011. You can see that kind of growth. As we come out with good strong prices, one of the goals would be to get into the fields quicker than we are right now and start adding rigs earlier than what the current plan has. So, if we do that, we can have stronger production growth.

Okay. Do you have an exit rate for the year you can share?

I don't have that in front of me. I think we can share that. I will just need to get that to you, and if we can get with Travis, we will send that to you.

Todd Godfrey, UBS.

Could you just give us a pro forma corporate debt and corporate cash position post the transaction last night?

Pro forma corporate debt, $2.3 billion. Cash position was about $1.2 billion before closing the transaction. That will draw cash down a little bit on a pretax basis, and then we will take a tax deduction throughout the year, which would get the pretax cash back by the end of the year. So does that help?

Yes, thank you.

And with no questions remaining, I would like to turn the call back over to your speakers for any additional or closing remarks.

Yes, this is Steve. I would just say that the transformational transaction that we completed yesterday really puts us in good shape to capture all of the growth opportunities that we have spoken about today. We also believe that the Marcellus represents a wonderful opportunity for us, and the integrated model is really working well for us there. And then the Piceance is a world-class asset, and it is every bit as good as any of the shale plays out there.

So with that, I look forward to talking to you next time. Bye.

Once again, that does conclude today's conference call, and we thank you for your participation.