威廉斯 (WMB) 2008 Q4 法說會逐字稿

Good day, everyone, and welcome to the Williams Companies' fourth-quarter 2008 earnings conference call. Today's call is being recorded. At this time, for opening remarks and introductions, I would like to turn the call over to Mr. Travis Campbell, head of Investor Relations. Please go ahead, sir.

Thank you and good morning, everybody. Welcome to the Williams fourth-quarter earnings conference call. As always, thanks for your interest in the Company. After my remarks, we'll turn it over to Steve Malcolm, our CEO, who will go through some thoughts; and then to our CFO, Don Chappel, who will talk about the fourth quarter results. Then Ralph Hill, Alan Armstrong and Phil Wright will speak to the E&P Midstream and Gas Pipeline businesses. After Phil's remarks, Don Chappel will review the consolidated guidelines and Steve will make a few brief remarks before we turn over and take your questions.

Please note that on the website, Williams.com, you can find the slides that we'll talk from this morning. Also the fourth quarter press release and all accompanying schedules are also on the website as well as our press release regarding our proved reserves at year end.

Slide number two, entitled forward-looking statement, discloses various risk factors and uncertainties related to future operations and expectations. Actual results, of course, vary from our current expectations due to factors disclosed. Please review that information.

Slide four, oil and gas reserve disclaimers, is very important. So please 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 this presentation. So with that, I'll turn it over to Steve Malcolm.

Thank you, Travis, welcome to our fourth quarter and full-year 2008 earnings call. As always, we always appreciate your participation in the call and interest in our Company.

Turning to slide five, please, Williams delivered very strong financial performance in 2008, largely on the strength of the first three quarters. Our full-year performance drove a 24% increase in adjusted earnings per share.

Other key and impressive operating highlights are shown on the slide. Our development activities in the Piceance, Powder and Fort Worth basins drove domestic production up 20% year over year. We grew reserves to 4.5 Tcf. We continue to be an industry leader in terms of F&D costs. We continue to proactively manage our Rockies position. And by that, I'm referring to the fact that 81% of E&P's production captured higher than Rockies prices by using the pipeline capacity that we have contracted for to move the gas to higher price points. And, our Midstream business took advantage of the basis anomaly in terms of capturing higher margins.

Clearly, however, fourth-quarter financial results suffered from the effect of the global economic conditions as the rapid decline in commodity prices certainly had a significant effect on results. But, but, we did benefit from the cash-generating Gas Pipe fee-based Midstream businesses that are insulated from commodity prices.

Next slide, slide six, please -- the business landscape has changed significantly since our third-quarter conference call on November 6. In particular, we have seen much lower commodity prices. We have seen crude oil prices drop 50%, speaking now about spot prices, 50% from early November's $70 to a current price of around $35. Forward strip has fallen as well. In early November, it was around $75 for '09. It has dropped 43% to $43.

As well, natural gas spot prices dropped 36% from early November's $6.79 to, currently, about $4.34, and we have seen the forward strip all as well. And, certainly, credit markets remain very difficult and unreliable.

And so, turning to the slide seven, what does this challenging business environment mean for Williams? We're taking appropriate steps to reduce our capital spending and are limiting expenditures to $1.3 billion below our '08 level, which is about 36% below '08 levels. The good news is the current cash and credit facilities are adequate to fund planned '09 CapEx. And by 2010 we expect to fund CapEx from cash from operations. Obviously, we are recalibrating expectations for earnings. We're expecting the weak commodity prices to push '09 sharply lower, and you have seen that in our new guidance. We do, however, expect things to improve somewhat as we see forward strip prices indicating some improvement in 2010.

I guess the third key point is that we are maintaining our current structure. We believe that it is best -- is the best structure to manage the risk and create value long-term. And a value creating structural change is not actionable in this economy. And here, I'm referring to the effect of the very low commodity prices, the more severe recession that we are seeing, the fact that credit markets present extreme challenges. And so, bottom line, the extraordinary costs, risks and lost synergies outweigh the potential rewards.

We do expect our mix of businesses, our investment-grade credit rating and our strong liquidity serve us well in this challenging environment and very weak commodity price environment.

Turning to slide eight, and so we're positioning Williams to prosper when the economy recovers. Again, I think the business mix, investment-grade credit rating, the strong liquidity, positions us favorably. I would characterize our capital spending as somewhat of a maintenance plus level of spending. We're bringing ongoing infrastructure projects into service, but by dialing down drilling activity while deferring other investments until the economy recovers and returns improve.

Meanwhile, we are retaining our workforce skills and capabilities. We're focusing on costs and not losing sight of the fact that our track record, and I point you back to our '08 results, our track record demonstrates a very strong value foundation.

Finally, on slide nine, we expect '09 to be a very challenging year in the industry, but WMB's liquidity is very strong. We have no significant debt payments until 2011. We're making significant reductions in our capital spending. And all of these steps are designed to best position Williams to prosper as the economy recovers.

Our growth engine that has created significant shareholder value over the last four years is still in place. And I think you are well aware that that growth engine is driven by the attractive organic investment opportunities that we have, and we believe that will still be in place when commodity prices recover.

So we believe that we are well-positioned when the economy recovers. And with that, I'll turn it over to Don.

Thank you, Steve, and good morning. I'm going to walk through a couple of slides here and discuss the results very briefly. They are well described in our press release package, and our business unit leaders will each spend a few minutes on their results.

So turning to slide number 11, financial results, just focusing on the bottom line, for the quarter recurring income adjusted for mark to market effects of $0.33, down 44% from the prior year as well as down from prior quarters in 2008. So starting to feel the effects of sharply declining commodity prices in the fourth quarter. For the full year, very strong results at $2.15. I think, again, that demonstrates the earning power of the Company in the strong economy, and we are eager to get back to that environment.

Just turning the page, slide number 12, fourth-quarter segment profit -- again, the business unit leaders will talk about their results. I'll just touch on the bottom line. Segment profit after mark to market adjustment, our important measure here, $402 million on a recurring basis for fourth-quarter '08 versus $718 million in 2007. So again, you can see the sharp decline in the fourth quarter. You can also see, as commodity prices rolled back, the contributions from each of our primary businesses start to even out after a very, very strong performance by E&P and Midstream in prior periods.

Just turning the page to year-to-date results, slide number 13, please, again, focusing on the bottom line, recurring segment profit after mark to market adjustments at $2.819 billion, up 16% from 2007 -- again, very strong year despite the weaker fourth quarter.

At this, I'll turn it over to Ralph.

Thank you, Don. Today I'd like to cover our 2008 financial results, our production highlights, a reserve update, counsel and guidance. First, I want to thank all our E&P employees and support staff for a superb job in 2008. It was a record year for production, profit and reserves. I also want to thank them for their ability to shift gears in a significant manner and respond to this current recessionary environment while preserving our long-term value. And I'd also like to thank our service providers and vendors.

Let's turn to slide 15. Fourth quarter '08 to fourth quarter '07 financial highlights, we had an 18% volume growth overall, total Company. We did have a 30% recline in recurring segment profit, which I will discuss in just a minute the reasons why, and we had a net domestic average price realized of 12% lower.

In the fourth quarter you'll see two things there. First is the negative impact of our results in nonrecurring items. First, legal contingencies -- that relates to the unfavorable opinion we received from the Wyoming Supreme Court on our appeal of a state regulatory decision on the allowance of certain tax deductions. The court ruling was for the period 2000 through 2002, and the accrual was made for that period plus remaining periods through 2008, and that was $34 million.

The second thing is a property impairment, and this is in the Arkoma Basin, which is one of our non-core producing assets in southeastern Oklahoma. The fourth-quarter impairment of $129 million resulted primarily from lower year-end reserves. The decline in reserves primarily resulted from using lower year-end prices as required by SEC guidelines. This caused the reserves to become economical and caused the non-cash write-down of $129 million -- or impairment.

And then on the year-to-date for the total year, you do see that we have a 19% volume growth overall, 71% recurring segment profit growth, which shows the true earnings power of this unit in a normal commodity environment, and the net realized domestic average price did increase 28%.

Let's turn to slide 16. Accomplishments -- 71% recurring segment profit, as I mentioned. On the domestic side our production growth was up 20%, and I have a slide and we'll go into that in just a few minutes. Domestic reserve replacement of 176%, our three-year F&D of $2.32, if you exclude the 2008 acquisitions. And keep in mind, our acquisitions, which were about $570 million last year -- our strategy is weighted very heavily towards unproved properties. We think on a 3P basis we bought all these acquisitions at about a $0.16 per MCF basis, on a 3P basis. We very rarely buy proved reserves, hence the $2.32, excluding 2008 acquisition.

And our team continues to be good citizens in the various areas we operate. First, we were named the business of the year in Grand Junction, Colorado; that's where our Piceance operates. And, we were also named Business of the Year in Denton County, Texas for our Barnett operations, and in the San Juan Basin we won the BLM Good Steward award.

Slide 17 -- this portfolio, which increased profitability in 2008 by 71%, also increased our production by 20%. It's set up for a very strong future. Our growth won't be as much this year, obviously, with our capital budget. But you can see Piceance Valley was up 14%. The Highlands were up 24%. The Powder River was up 34%. Fort Worth was up 66%, and San Juan Basin, our most mature asset, continued to grind up at 3%.

Slide 18 -- looking at our reserves, we believe we had a strong reserve performance in 2008. Total reserves were about 4.5 trillion cubic feet. On the domestic side, we were up 5%, 148% domestic reserve replacement for the 602 Bcf net additions, greater than 99% drilling success rate. And we added 714 Bcf to proved before the price-related revisions. The price-related revision was 112 Bcf.

Essentially, 2008's year-end prices compared to 2007's were down in our various basins between $1.19 to $1.55, or 20% to 25%, which impacted our reserves by this 112 Bcf. That's only about 2% of our total proved reserve portfolio. In prior years we have been asked, what if prices would decline, what would happen to our portfolio? And we said, really very little would happen. As you can see, with only 112 Bcf written down with the much lower prices, our portfolio is not really impacted, which shows the strength of our reserves.

Finally, in addition to this all, we moved about 1.9 Tcf of probables to proved, again, over the last three years. And our PDP, proved developed producing percentage, is now up to 57%, up from 53% just a couple of years ago. I think that shows that we continue to increase our productive capacity while also increasing our proved reserve base.

Slide 19 is a reconciliation of reserves. Basically, you can see where we started two years ago at 3.7 T's, and we are now up to 4.3 T's on a domestic basis. Our reserve additions came in on a total basis at 791 Bcf, which is just a little less than 2007's additions.

Revisions are downward over 220 Bcf, which makes that net 571 Bcf that you see on the graph here. Of that, 51%, or 112 Bcf, is due to the low-end price, which I just previously discussed. The other 49%, or about 100 Bcf, is due to reservoir performance-related issues. Really, all that is is a slight tweaking of the models, and primarily, most of that was in the Piceance. What we do is, as we look at it every year, we had a slight adjustment to the tail end of our reserves, primarily. When you look at that and you multiply that slight adjustment times 3100 wells, it turned out to be 100 Bcf. But really, a very slide adjustment in our reserves.

We deduct our production of 406 Bcf, which was up 21%, as I mentioned, from last year, or 20%, and we end up with our year-end reserves of 4.3 Tcf on a domestic basis.

Slide 20, just to show what we have done in the last several years and the strength that we believe we have in our portfolio, panel one just shows the increasing deliverability over the last four years. We are up a compound average growth rate of 21% in production. We think that growth rate is truly remarkable, given that, one, it's really organic; it's not done through acquisitions; and also, given the additional high decline rate of most of our wells where we operate in, in tight sands, coalbed methane and shale. So -- and also, just basically through the organic growth rate.

Panel two shows our growth in proved reserves, a compound average growth rate of over 9%. It also shows a relative ratio of proved reserves between the PD's and the PUD's and the proved developed and the PUD's. And that proportion continues to increase, and again, as our reserve basis increases and our productive capacity increases.

And the last line shows our reserve replacement ratio over the last four years, and this year without the price adjustment, that 148% would have been 176%.

Turning now to slide 21, our strategy continues to be aggressively in moving our gas away from the Rockies. In the fourth quarter we had about 19% priced at the Rockies and 81% not priced at the Rockies. So let's break that down a little bit. Our fourth quarter production is 1.156 Bcf a day. 37% of that is at Rockies prices before hedging, and 63% of that is taken away. So we have about 425 million a day at Rockies prices.

Then we take away the 200 million a day that we're hedged, and we have only about 19% that's priced in the Rockies. Then, Midstream consumed about 174 million cubic feet a day as fuel and shrink, and that further reduces our Rockies exposure to only about 51 million a day, or only about 4% of our entire portfolio.

In 2009 Rockies exposure is expected to be less than that at about 12% on an E&P-only basis, and obviously Midstream continues to consume fuel and shrink, so our exposure will be very minimal in 2009.

Looking at capital budget on slide 22, please recall last time I walked you through a decrease in our expected budget from $2.3 billion to $1.7 billion. That was a cut of about $600 million-some, and we have now cut another $700 million by dropping 13 more rigs. Essentially, 10 rigs are being dropped in the Piceance, three in the Fort Worth Basin. We are doing quite a few fewer wells in the Powder River. Associated facilities, primarily the Piceance, are down by $65 million, and our cost savings in land we've cut by $95 million.

In the last call I mentioned another $75 million of cost savings that we had, so we had significant cost savings, and that brings us into our current guide point, middle of $1 billion. We are seeing declines in all of our costs across the board. Our tubulars are down 10% to 21%. Directional service is down 12%. Bits are down 35%. Frac service is down 30%. Workover rigs down 25%, and many other things are down. And we think we'll continue to see additional cost savings.

Our growth is predicted at 2% to 4% growth in volumes now. Most of that growth is in the first quarter, as you would expect.

So if you summarize all this, our drilling economics still remain very favorable at forward prices, but our capital program has been cut back significantly due to this global economic crisis. We are still opportunity rich for the future. If you look at our expected rig count, Piceance we expect it will be at 9 to 10, down from about 28 rigs; and Fort Worth will be about two, down from about seven rigs.

Slide 23 is our guidance. You can see we continue to ratchet down our capital, as you can see on this slide, and also our price deck that you've seen in the appendix basically turns our recurrent segment profit for this year, estimated to be between $325 million and $575 million, depending on the price that you apply to that.

Finally, slide 24 -- I want to say a couple of things here. First of all, I can't lose sight of our team's efforts for 2008, a record year for reserves production and segment profit. In a normal economic climate, that would continue for many, many years.

Second, our premier drilling inventory, as we have always said, provides flexibility. We can ratchet it up or ratchet it down. We have now ratcheted it down. Almost all this portfolio is held by production. We can decrease activity, and we have done that. And we are preserving the long-term value for the future growth.

And the last bullet on this slide there's no time to talk about it today, but we believe our new opportunities are very promising in other areas. Thank you; I'll turn it over to Alan now.

I'm going to start here on slide 26. I am pleased to report that Midstream had another successful year, earning $926 million of segment profit on a recurring basis. Our well-positioned assets and our very dedicated teams, once again, allow us to take full advantage of a robust Midstream environment for most of 2008.

Of course, in fourth quarter results were certainly affected by the dramatic downward movement in NGL prices, which impacted not only our domestic natural gas processing margins, but also hurt our olefins and Canadian margins and imposed lower valuations of our inventories in many areas. While falling commodity prices negatively impacted some of our business, our fee-based revenues increased to over $215 million for the quarter, reflecting the addition of Bass Lite volumes to our Devils Tower infrastructure. This fee-based number represented a 15% increase over the same period last year.

The tempered momentum in the fourth quarter provided us a recurring segment profit for the fourth quarter '08, which was $250 million lower than our fourth quarter of '07. The domestic NGL margins from our fully-owned plants were $125 million lower, but we also incurred a $78 million marketing loss in the fourth quarter compared to a $6 million gain in that same area in the same quarter of '07. This $84 million variance is driven by dropping prices on product in transit, and I'll show a little more detail on this later in the presentation.

Also, our olefins business was hit hard by lowering commodity prices and took some significant lower cost-to-market adjustments on inventory valuations.

Moving on to slide 27, just real quickly here, you can see that our margins there on the green line shows that we actually saw $0.59 of margin in the fourth quarter. That's probably higher than a lot of people are expecting and still well above the $0.37 for our domestic plants. So I will explain on the next slide -- on 28, I'll show the drivers that show that NGL margin being higher.

On 28 here, here, as we did in the third quarter, we show the impact of ethane rejection, inventory shifts and collars on our fourth-quarter NGL margin and our equity sales gallons. If you refer to this illustration, starting on the left side we depict our estimated equity NGL gallons that we normally would have sold during the quarter. Then, next, we subtract the estimated volumes that were lost due to ethane rejection. This adjustment is followed by adding the equity gallons from the prior to 9/30, so prior to the beginning of our fourth-quarter inventory that we sold, actually, in the fourth quarter. So the result is our reported equity NGL sales volumes of 285 million gallons.

On the right side of the graph here we talk about price, and we depict the estimated normalized margin per gallon for the fourth quarter, which is significantly lower than our reported margin. The normalized margin would have fallen below our five-year average margin of $0.37, as seen in the previous slide. There were three main drivers benefiting the per-unit margin that we actually reported.

First, in the blue-striped segment, we add the margin impact from the heavier product mix this quarter; that increased our per-unit margin. Because of the ethane rejection that we experienced, the NGL product mix that we sold was approximately 46% ethane and 54% propane. Our reported margin reflects the heavier mix of NGL sold and would have been reduced, had we sold the usual 50-50 ethane-propane mix. So basically this richer mix with higher-priced products in it drove the price up.

In the next bar we add the impact on NGL margins from the collars that were put on in the beginning of 2008. And you can see we got a nice lift there from our collars, about $0.16 across all of our barrels. Then we add the margins recognized in the fourth quarter on the 9/30 inventory. So these are products that we sold out of inventory that had been produced in the third quarter. And we end up with our reported NGL margin of $0.59 per gallon. The difference between the normalized and reported equity volumes and reported margin are much smaller for the entire year, as you can see on the total-year slide that we've put into the appendix for you.

Moving on to slide 29, I spoke earlier, the $78 million marketing loss in the fourth quarter, and this was driven by price movements during the quarter and inventory levels. You can see on this graph here in the line above is the pricing levels, and in the dark blue bar on the top graph there is the level of inventory, and you can see how that inventory rose dramatically. And then on the bottom you can see how the marketing margin that we've reported since first quarter of '06, and you can see it has been fairly limited, up until this quarter.

Our NGL Marketing group buys products from the plants at OPIS prices and then wears the risk of value of that product in transit. Our normal transit times are three weeks, but of course this is continuous over the whole quarterly period. The inventory that NGL Marketing holds built throughout the year, for several reasons. First of all, during most of 2007 we sold almost all of our NGL's in the Wyoming plants to a third party. This arrangement expired in February of 2008, and therefore we had to build line pack inventory for our own account on the Mid-America pipeline system.

Secondly, we got product held up by behind the enterprise fractionator in Mont Belvieu, due to their frac being out of service due to the hurricanes late in the third quarter. Then finally, we had to build line pack inventory on the Overland Pass Pipeline to begin shipping on this pipeline as we filled that previously unfilled pipe.

So about the same time our inventories were at their peak, our NGL prices tumbled rapidly throughout the quarter. And you can see from our graphic that normally this impact is very small, and in fact it was positive to the tune of $17 million in 2007. So it provided a $95 million variance from year to year.

Moving onto slide 30, our fourth quarter benefited from an increase in our fee-based business compared to our 2007 as we have seen consistently in 2008. Our fee-based revenues were up same quarter, year over year and in each quarter of 2008. For the year, our fee-based revenues increased 10% or $75 million over our 2007 fee base.

Our return on average assets for the year was 21.4%. We calculated that return by using our segment profit less general corporate expenses and other income expenses below the line, and then we take that over our net assets, which is net PP&E our long-term investments and our working capital.

As we touched on the third quarter, we will continue to benefit from the startup of Overland Pass. Although the startup was painful due to the delays we incurred, our Wyoming and eventually Piceance plants will be in a unique position of being able to pick the better of either Conway or Mont Belvieu NGL prices. And we also enjoy dramatically reduced transportation and fractionation expenses, and we have significantly improved our take away reliability.

So far during the first quarter, we believe we have improved our propane net back prices by almost $0.15 per gallon due to Overland Pass from our Wyoming plants.

We also made significant accomplishments in the fourth quarter on major projects. Bass Lite began flowing at full volumes in the fourth quarter and contributed about $19.7 million of operating profit in 2008, when coupled with some of the earlier production from there.

We also helped Bill Barrett Corporation deliver their first Paradox Basin production into Northwest pipeline in December, and as a result we received a significant acreage dedication in the heart of this basin that looks to be very prolific. And we continue to solidify our position in this new shale play.

Our E&P group helped us gain this first mover advantage through their knowledge and ownership interest in the Basin, and our Willow Creek plant construction in the Piceance is progressing in line with its schedule, and we continue to project substantial completion during the third quarter of 2009. Our large deepwater projects, Perdido Norte, is expected to start up in the fourth quarter. And the final connection for the Tahiti Lateral is expected to be completed in March, and Chevron is still showing that as a third-quarter startup.

Moving on the guidance very quickly here, with reduction in our commodity price outlook, 2009's segment profit guidance has been lowered to a range of $400 million to $700 million. While we are expecting lower earnings in 2009, due to the pricing environment, new expansion projects are expected to contribute approximately $50 million of incremental profit compared to 2008. In looking at 2009 capital spending, you also note that we have a $50 million reduction in our capital spending, and that actually is $100 million lower spending because we actually transferred out $50 million of spending that didn't get completed in '08. So our '08 spending was actually lower, and so our net is actually $100 million.

Moving on to our key points here on slide 32, as we touched on briefly in the accomplishments slide, 2008 continues to show a high return on average assets at 21.4%. In fact, this measure has averaged 22% over the last three years. We believe that we remain at the top of our sector of the industry on this important measure, due to our capital discipline, and our very focused and effective group of employees that remain very committed to driving both our strategy and our return for our shareholders.

We haven't grown the most, but we have grown in a very profitable manner and in a way that should benefit both our near-term and long-term shareholders. Our fee-based revenues grew $75 million from 2007 to 2008 and we anticipate our fee-based revenues will grow in 2009 as the new major projects that I listed begin to contribute and certainly grow into 2010 as Perdido Norte starts up at the end of this year.

One key growth are in our entry is the Paradox Basin, and we continue looking into similar large-scale basins for other opportunities.

And with that, I will turn it over to Phil Wright.

We're very pleased to report another strong year in 2008 from our Gas Pipeline segment. Could I have slide 34, please? In spite of a $24 million headwind, pun not intended, from reduced IT feeder revenue on Transco due to Hurricane Ike, our revenues were up $50 million from 2007 on the strength of a full year of our new rate structure on Transco versus only three quarters in 2007; incremental contributions from our major expansion projects, including our Leidy to Long Island, Potomac and Gulfstream projects and higher short term firm sales on Northwest Pipeline.

Slide 35, please. In addition to solid financial performance, 2008 was also a year of significant operating accomplishments. Among some of the highlights, we placed phase one of our Sentinel expansion in service on December 22. We expect to have phase two in service in November of this year. And when complete, this project will add 142,000 dekatherms a day of capacity on Transco to the Northeast.

It's noteworthy, I believe, that this project, our Leidy to Long Island expansion, and our Potomac project, all demonstrate that our team has the skill sets, the footprint and the resources to grow and protect the coveted Transco franchise.

In another market-driven expansion, our Jackson Prairie deliverability enhancement at Northwest Pipeline was brought online in November. As well, and in another indication of the value of Northwest, as the backbone of the gas delivery infrastructure of the Pacific Northwest, we set a new record for peak day deliveries and annual throughput.

I'd also note that we were successful in extending contract terms for capacity on Northwest, totaling approximately 360,000 dekatherms a day during 2008 for an average extension of 13 years. Since 2006 we have worked with our customers on Northwest to extend 1.5 billion a day, 1.5 billion cubic feet a day, of firm transportation capacity and over 800,000 dekatherms a day of storage and peeking services.

Lastly, our Gulfstream phase four expansion began flowing in November to serve the strong and growing power generation markets in Florida.

Slide 36 -- turning now to our guidance, we're slightly lowering our segment profit range, due largely to higher property insurance and pension expenses. We have some nonrecurring maintenance expenditures we have to do, including repairs to damage caused by Hurricane Ike, for which we don't expect to get some of the recoveries until 2010, and major replacements at two compressor stations. On our expansions we have provided detailed descriptions in the appendix, so I won't cover them here. But I would observe that the expansions included are high-quality, market-driven projects with high credit quality customers. They aren't exposed to the years six and 11 turnback risk producer-driven projects have to contend with.

So, summing up on slide 37, Gas Pipes once again delivered solid, predictable cash flow to our portfolio in 2008, greater than $1 billion in segment profit plus DD&A. We have affirmed or Gas Pipeline team's ability to execute quality expansion projects in the highest-growth regions in the country, all underpinned with long-term, market-driven contracts with high credit quality customers. And we have more on the way with $470 million to $575 million in expansions in our guidance for construction during the 2009-2010 timeframe. So the outlook is great for Gas Pipes to continue to generate strong, predictable free cash flow for Williams.

Now I'll turn it back to Don.

Thank you, Phil, let's turn to slide number 39, and we will take a look at some summarized guidance information. This slide walks through the changing commodity price landscape as well as our changing CapEx and earnings guidance. The column on the left was our assumptions as of November 6, and I think most of you agree that the price environment at that time, while down sharply from what we saw earlier in the year, was likely something viewed as fairly normal, a $60 to $90 crude oil range, a $6.00 to $8.00 gas range, something in line with what most consultants and EIA might call a more normal long-term environment.

At that time we had a CapEx budget of around $3 billion and expected to deliver about $1.25 to $2.05 EPS with a midpoint of about $1.65. As we moved forward, as Steve mentioned earlier, prices are down sharply. You can see them there, but oil is down about 43%, gas was down about 40% from the time of our November call until this date. And, as a result, we throttled back our capital spending by about $650 million at the midpoint and also down $1.3 billion from 2008 levels. And that resulted in a range of $0.60 to $1.10, certainly a sharply lower level and one that we don't think is normal but one that we're prepared to endure during 2009.

I think, if you look to the right, our 2008 actual is reflective of our earnings power during a strong economy and a strong price environment. So as we think about the future, I think we can look for much better times ahead and much higher levels of earnings.

I would note in our 2009 price assumptions -- or, excuse me, earnings assumptions today -- while we are seeing many, many costs, it declined pretty sharply. There's a couple I'd just like to note. We're seeing sharp increases in our pension cost as a result of the sharp decline in the value of investments. We're also seeing a sharp increase in insurance costs as a result of the hurricane effects and the large claims in the Gulf Coast area. So just things to think about as you model the future. And those are built into our numbers.

Our 2009 forecast guidance, on slide 40, again just details the components of that guidance level and the comparison to November 6.

Slide 41 again summarizes what you saw from the business units before, but E&P and Midstream down sharply on sharply lower commodity volume and prices, and Gas Pipeline very steady, given its long-term contracts with high-quality credits. Overall, recurring earnings after mark-to-market adjustments again down sharply. Finally, Gas Marketing at the bottom of the page after eliminating mark-to-market effects moving to about an expected breakeven level as the legacy issues diminish.

Turning the page to slide 42, this just graphically depicts our natural gas position. And I'll just walk through how this slide works. The one on the left is our consolidated natural gas position. As you know, E&P produces over a Bcf a day. Netting out fuel and shrink, production taxes, we get down to a number of I believe it's around 940. The green area is hedged principally with collars, and you can see the hedges for 2009 on slide number 62; I think we have about 600 million a day hedged. And then the yellow would be the unhedged E&P volume. Below the line is the Midstream short position to produce NGLs, and the dot, the diamond in the center, would be our net natural gas position.

So, although we produce over a Bcf a day, you can see that net long position is closer to 100 million a day or about 10% of our total production. Again, there is some variability because of the fact that many of the hedges are collars. As we take a look at the Rockies for the same period, again, the lion's share of our E&P production is in the Rockies. Again, we back off the production taxes, fuel and shrink, and the -- kind of the purple burgundy-colored area is the gas that is transported out of the Rockies to other price points. So what remains in the Rockies, sold in the Rockies, would be the green, which is hedged, and the yellow, which is unhedged. Again, the blue represents the Midstream short position, and the diamond would represent our enterprise position, which is short Rockies gas very slightly.

I would just also note that we have about 300 million a day of hedges on in 2010, natural gas hedges. And that is detailed again on slide number 62. In the Midstream area we have no hedges in 2009 or beyond on NGLs.

Just turn the page, please, to capital spending. You can see our capital spending detailed here again, down sharply from 2008 and down sharply from our November 6 guidance, with E&P off about $700 million and the others being some fairly minor adjustments.

Turning the page, think about cash flow and liquidity. I'll just hit a couple of highlights here. Cash flow from operations, at $1.9 million to $2.2 billion, less dividend and minority interest payments to our MLP investors. Other represents cash that would come out of the pocket of the MLP or our international operations to fund some of the items included on this schedule, whether it be CapEx or minority interest payments and the like.

The capital expenditure midpoint, $2.3 billion, leaves us with a change in cash of about, call it $500 million to $700 million negative, beginning unrestricted cash, solely unrestricted, not MLP cash, not international cash, of $800 million less the change from above, plus assume borrowings of about $500 million yields an ending cash balance somewhere in the range of $600 million to $900 million. Capacity, remaining capacity under our credit agreements at the end of 2009, would be $1.350 billion, yields total year-end 2009 ending liquidity estimated at $2 billion to $2.2 billion.

Turning to slide 45, just a few other thoughts. Again, we think a lot about capital allocation in this environment. Capital is scarce and expensive. We'll allocate capital to our highest risk-adjusted returns, but we also think about strategic issues, and those are many, both from a defensive standpoint as well as from an offensive standpoint. We think we have some opportunity to play offense in this environment.

2009, again, our planned CapEx exceeds our cash flow, somewhere in the range of $500 million to $800 million. Again, available cash and credit facilities will fund the excess investment. We have many Midstream and Gas Pipeline projects that both Phil and Alan detailed in their remarks as well as are listed in the appendix to our presentation. We'll finish those projects. E&P is reduced sharply to a $1 billion level, yet expects a slight increase in production during 2009 and we'll continue to preserve the many investment opportunities that we have for periods when prices are higher and capital is more available.

2010, we would expect that CapEx will match assumed cash flows. The bulk of the change there is many of the projects in Midstream and Gas Pipelines will be completed; and, while we will have some new projects, we would expect that overall we would match our CapEx with our expected cash flows and we'll remain flexible so that we can live within our means even with low prices.

The forward strip shows an expectation by the market of somewhat improved prices, oil in the range of about $10 at this moment and gas in the range of about $1.25. So that would certainly be helpful, if that were to come true. And we will, again, retain the flexibility to adjust our spending.

As I mentioned earlier, we would expect to play some strategic offense, and we are very attuned to value-creating opportunities that are created by this economic and financial market crisis as well as low prices. We will be very focused, opportunistic, prudent, aware and disciplined. With that, I will turn it to Steve.

I have no further comments. Why don't we just move right into Q&A.

(OPERATOR INSTRUCTIONS) Faisel Khan, Citigroup.

How extreme were the issues presented in the credit markets that caused you to look at the risk associated with a potential structural change in the Company? Can you give us a little color around that?

Well, probably not as much color as you would like. But there's no question that the changes that we have seen over the last few months certainly had an impact on our decision. Because of the unprecedented financial and commodity market uncertainty -- and we don't know where commodity prices are headed. We are heartened by the fact that strip prices are a little better in 2010, but on the other hand, there are forecasts out there that we are going to see Henry Hub prices at [250]. So unprecedented uncertainty.

And so I think it's fairly clear that the market values more highly companies that are larger, that are more financially diverse, that have stronger balance sheets, that have stronger credit ratings. So those are some of the reasons that we have decided what we have decided.

In listening to your whole presentations today and you're looking at your '09 guidance, I know you guys talked about some of the headwinds from higher costs from pension insurance. Is there any way to cut costs out of the system, too? There has been a fair amount of cost inflation across the board at all three of your segments over the last couple years. Is there any way to reduce the cost structure of the Company, over the next 12 to 18 months?

There's great tension between simply taking austere cost-saving steps versus staying positioned for the future. And we do anticipate that at some point there will be a recovery and there will be stronger commodity prices that will translate into good things for our Company. And we have spent a lot of time building the appropriate organization so that we can best take advantage of those opportunities.

Having said that, we are obviously looking at taking steps to reduce costs. We are -- right now, I would call it more of the low-hanging fruit. We gave up our apartment in New York City, for example -- not that big a deal, but I think an appropriate step. We are cutting back travel where it makes sense for us to do so. We have negotiated hard and we'll continue to negotiate hard with third-party vendors.

So I can assure you that we're looking very closely our cost structure.

I think, Don, in your last comments, you talked about playing offense. Does that mean also looking at opportunities for small acquisitions? Or, is there some other -- or was it just talking about keeping your capital budget a little bit above operating cash flow? And is that considered playing offense?

I think, from a strategic standpoint, we are talking about the fact that -- we view the Paradox Basin, for example, as an offensive opportunity for us, the fact that we have an E&P presence there and a growing Midstream footprint. That's good stuff, and I think will create wonderful opportunities for us in the future.

As well, we'll continue to look at strategic opportunities, but they would have to be compelling in today's market.

Don, did you have any follow-on comments?

I think well stated.

Carl Kirst, BMO Capital.

Steve, perhaps I ask the restructuring questions differently, just to make sure I'm understanding the results of the review. Is this something that is really just reflective of the reality today, the current market? Or, was this more of a longer-term, managing risk in both good cycles and bad cycles? And I guess what we're all trying to come to, is this sort of a review that gets reignited if and when commodity prices get back up to where they were in the third quarter?

An excellent question, Carl, and a fair question, but again I'll probably disappoint here. We're going to continue to assess all of the options to enhance shareholder value. But I'm not going to speculate today on any future actions we might take in that regard. I think I have been pretty clear on the environmental changes, the economic landscape changes, the commodity price changes that impacted our decision and why we think it's very prudent to go forward and to continue with the current mix of businesses.

But, Carl, I'm not going to speculate on, well, what does that mean for the future.

Fair enough, I had to ask. Two other quick questions if I could, Ralph, just on the proved reserves. If -- and this may be a difficult question to answer -- but, if we were undertaking the review again today at current gas prices, I guess, we're trying to figure out where the line all of a sudden stops being linear, do you have a sensitivity or some indication of what perhaps negative price-related revisions would be under the current price deck?

I don't. Again, we are not that sensitive. You look at our cash costs and a number of our basins are below $1. Other basins are well below $2. Then, if you look at the new rules this year, where you're probably going to be allowed to do more with your probables and possibles in areas of tight sands that we have, it's just too early to speculate on that. We probably feel the new rules are going to be very favorable for us, and there could be some areas that have offsets in the prices if prices stay low for the year. But we've actually met with our auditors and talked about that a little bit, but I think it's just way too early to talk about either side, about how much more we will have because of the new rules and then what could happen in a price environment. But I can tell you that we are very competitive in all of our areas and we have very low costs in our areas, and that will help us quite a bit.

Just lastly, Phil, just a clarification. The $24 million of headwinds that you said with respect to Hurricane Ike -- that was a fourth-quarter revenue impact, i.e., excluding Hurricane Ike, EBIT in Pipes would have been essentially $24 million higher?

It was a reduced IT feeder revenues incurred during that period of time. And so we just dropped that out of the revenue line. And so as we go forward, we would expect IT feeder revenue to pick back up.

Sam Brothwell, Wachovia.

A question on the E&P side and in Midstream -- can you just clarify? Did you cut by 10 rigs, or did you cut to 10 rigs in the Piceance, Ralph?

It actually works out both ways. We cut by 10, and that ends up being -- for the average for the year, we should be around between nine and 10. We originally were at 28, 27 or 28, in the fall of last year and we cut down to approximately 20 in the last call, and now we have cut another 10, down to between nine and 10.

Can you give us some sense as the kind of backlog of wells that you have still got awaiting completion up there?

We have not done that yet, but we expect in this budget we have this year we'll have about 75 or so wells that we won't complete, to manage around this budget. So it's not a huge number, but we will have 65 to 75 wells that we are, at this point, would not complete to manage within that budget.

Can you give us some sense of the price you need in the various basins, particularly the Piceance, to earn your cost of capital?

We have never given the cost of capital per se. I can tell you that our cost, and the cost of capital appears, probably, in this market to be a moving target, but we believe that even at the prices you would see today, we would clear our cost of capital in these basins.

And, Alan, just kind of a high-level question. There has clearly been a lot of pressure on the US petrochemical industry demand. Do you see -- looking forward, do you think we'll return to, ever return to normalized conditions? Or, are we really seeing a secular change, particularly with some of the petrochemical capabilities coming on in the Middle East?

Sam, I think that mostly what we have seen to date is driven just by worldwide recession. Actually, I think the US could be pretty well-positioned long-term, particularly with the gas supplies that we have. I think we could wind up being a fairly low-cost supplier again, as we were.

So I'm fairly optimistic about the pet-chem market, just because I think we have proven that we have got ample feedstocks here and I think that will keep people here. I think certainly what we have right now is just recession, and I don't think it's so driven by lack of exports at this point.

(OPERATOR INSTRUCTIONS). Lasan Johong.

Ralph, any chance you can give us exit rates for the first quarter and the fourth quarter of this year?

I don't have the first quarter with me. I think, if you look at it, we expect our exit rate at the end of the year would be down about 4% to 5%, say around 5% from the beginning of the year. So most of our growth is in the first quarter, probably 10% to 12%, maybe slightly more. And then it tapers off during the year.

I can say that every year -- if you look at 2010, and we are not giving out 2010 guidance yet, but if you look at the efficiencies we grind out every year, for example, we have drilled some wells in the Piceance in five days or less. We have taken Ryan Gulch wells, and our average wells in 2008 were better than the best well we drilled in 2007.

If you factor all the efficiencies in, we believe 2010, even with the lower rate of capital that we are using and even assuming we have a flat level of capital in 2010, we would expect that decline would be arrested and we would be flat to what we see in 2009. So it's not an ongoing decline, but there will be a decline this year.

If you stop drilling entirely and just kept your production on line, could we assume a 15%, maybe 20% decline rate overall for your E&P business?

I haven't run that for awhile. For now -- we'll just need to get back to you on that. I do not know that answer. That's probably a decent assumption, but I'd have to look at the numbers.

Steve, considering the potential for the economic crisis to remain sluggish and the forward curve measured against that economic scenario seems to be bullish, any chance you are going to put on a lot more hedges going forward to take advantage of that inclining forward curve?

Yes, we always look at what the market is offering. We have had, as you know, a corporate strategy to have 40% to 60% of our production hedged. That obviously was influenced by the enterprise position, particularly that position in the Rockies. But we look at hedging opportunities, always, weekly. And I can assure you that we will take advantage of opportunities as we see them.

My final question -- do you anticipate big impacts from potential LNG flows into the US?

I still think the answer to that is somewhat uncertain. Certainly, demand in Asia and Europe for LNG is somewhat diminished, it would appear. Whether that finds its way to the US is somewhat questionable. But I guess I don't have a crisp answer for your today.

Joe Allman.

A follow-up on the rig question. So the rig drops that you've planned are already done for this year, or are there some more rigs that are getting dropped?

They're almost all done. There are a few rigs that are finishing up on various pads, and it's more efficient to let them finish those pads. But we have significantly dropped rigs since the beginning of the year. Almost all of them have been dropped.

Another question on the restructuring. In the review process, what were some of the benefits that you saw for separating out the different businesses?

Well, as we described during our last call, it was all driven toward finding a way to enhance shareholder value. That was the pot of gold that we were looking for. So we'll continue to assess -- as I mentioned earlier, we will continue to assess all of the options that are available to enhance shareholder value in the future.

When you look at the value of your different businesses, and I know it's hard to separate it out, but do you that your E&P business is undervalued relative to other, more pure E&P companies?

Yes, that's -- again, it would be dependent on the various assumptions that you might make for how you would value, what multiples to apply in today's very uncertain market. So, again, I don't have a crisp answer for you there. It's something that we continue to evaluate and look at.

For your guidance for NGL margins, $0.22 to $0.35, does that bake in an improvement in the second half of '09 for frac spreads?

There's not much movement during the year from what we are seeing right now, actually, on that. The percent of NGL crude, particularly on the ethane, does improve during the year, but the base commodity prices are held pretty flat. But we do see an improving percent of ethane to crude, for instance.

And then the tax benefit for this quarter? Is that a true-up for yearly taxes, or --

The tax adjustment is just an annual detail review of the effective state tax rates. Our earnings have been growing in areas with either lower or no state income tax. And, as a result, our view of our state tax rates has declined somewhat. So we've reduced that and we made that calculation in the fourth quarter that gets applied to both earnings for the period and deferred tax balances, and that's what you saw roll through the fourth quarter.

Lastly, on pensions, what is the unfunded status, and what will be the additional cash contribution to the pensions?

Ted Timmerman is our Controller, Chief Accounting Officer, he will take that question.

As to the unfunded status, we will be publishing that in the 10-K. As you can imagine, given the returns on plan assets over the course of 2008, you will see some decline. And we'll also be posting what our funding expectations will be for 2009 as well.

So stay tuned.

[Sean Grant], Zimmer Lucas.

Just a quick question on your CapEx. Does the budget assume that you exercise the option on Overland?

No, it does not.

Rebecca Followill, Tudor, Pickering and Holt.

Just to clarify, you had said that 2010 production would be flat. Is that assuming continued $1 billion CapEx?

I was just saying, if we ran about that level, $1 billion, and with the efficiencies we have, we would not expect this decline that we'll see to continue on.

And then, on E&P, at what point -- at what price do you say I'm going to reassess and up my CapEx budget?

Will, I ask for that every day. No, sorry. Well, I think it's really just going to be a function of, as Dan mentioned, to the extent we have additional cash flow and the prices would come up. I think we would be allowed to be the first mover to come in and spend additional dollars. So really, just as our cash flow would come up, I think would be the time you would see us to that.

Don, do you want to talk?

The range of prices we provided, I think we are fairly good within that range. If prices were to decline below the bottom end of the range that we laid out, which was $4.50 Henry Hub, we would certainly take another look at where we are. But we have certainly already looked at the $4.50 to $6.00 range within that spending plan. But clearly, if things moved sharply lower, we would revisit it once again.

But we are hopeful that we won't have to see that. But obviously, none of us know.

Just to, once again, ask a question that has been asked a couple of times, you said on the conference call a couple of times the words strategic offense. It's got people wondering really what that means. Is that, I've got something in mind, I think that prices for assets are going to fall? I don't understand what you mean.

Sorry to not be clear. But I think all we are seen here is that, in the case of the Paradox, for example, we are seeking to expand our footprint both from an E&P and Midstream perspective. So what we were trying to convey is, this isn't only about playing defense. We are able to make investments that expand our footprint, and we'll continue to look at strategic opportunities that make sense.

But don't, in any way, conclude that we have something in mind or we are about ready to announce something.

Well, we have drilled four verticals. One is waiting on completion, and five horizontals and two waiting on completion. We had planned to drill seven horizontals this year, and now it looks like we will drill more like 14. So those are some areas we are playing offense, and there are some other land opportunities that we have out there that we've kept in the budget to continue to expand positions in various areas.

Sunil Jagwani, Catapult.

I'm just trying to reconcile a couple of different statements. I guess firstly, you had talked about being able to make good return even at current prices on the E&P side. The DD&A rate on the E&P income statement that flows through is $1.80 or $1.90, somewhere around there. And then the reported -- at least the way I calculate it, the finding and development costs are over $3.00, given that you spent $2.5 billion in E&P last year. So I'm just trying to reconcile those three statements. If you can help me, that would be great.

First of all, we don't look at our one-year finding costs, ever. But we could; we give that out. And I think the way our portfolio is set up, there are some years where you are going to see us very low and some years a little higher.

In that $3.00 calculation, you have about $528 million that was spent on acquisitions, which were almost -- with the exception of maybe 20 Bcf or maybe 30 Bcf, that was entirely for 3P reserves. So we just look at it on a three-year basis. Our three-year basis is now up to about $2.32. It was about $1.80. Why is it up? Costs were up some, areas we drill this year were up some, those kind of things.

But then, if you look at it, what I think is going to happen this year, I think you'll see that drop significantly because of where we are drilling, how we are drilling and the CapEx that we have and the costs that are coming down.

And then just on the cash side of the world, our cash breakeven is well below $1. And you take that, and you take what is a normal environment, and I believe that was see our returns are all 15%, 16% or higher on our drilling program.

This concludes today's question-and-answer session. At this time I would like to turn the call back over to Mr. Steve Malcolm.

Well, thank you. I would just conclude by saying what I said earlier. We expect our mix of businesses, our investment-grade rating, our strong liquidities to serve us well in this very, very challenging economy and very weak energy market. So thank you very much for tuning in this morning.

This concludes today's Williams Companies conference call. Thank you for joining us and have a wonderful day.