Full Transcript of Williams Companies’ 3Q05 Conference Call - Prepared Remarks (WMB)

Nov. 7.05 | About: Williams Companies (WMB)

Here’s the entire text of the prepared remarks from Williams Companies’ (ticker: WMB) Q3 2005 conference call. The Q&A is here. We recognize that this transcript may contain inaccuracies - if you find any, please post a comment below and we’ll incorporate your corrections.


Travis Campbell
The Williams Companies - IR Director

Steve Malcolm
The Williams Companies - President, CEO

Don Chappel
The Williams Companies - CFO

Ralph Hill
The Williams Companies - SVP Exploration & Production

Alan Armstrong
The Williams Companies - SVP Midstream Gathering & Processing

Phil Wright
The Williams Companies - SVP Gas Pipeline

Bill Hobbs
The Williams Companies - SVP Power

Andrew Sunderman
The Williams Companies - VP Finance & Accounting, Power


Nicholas O'Grady
Sandell Asset Management - Analyst

Faisal Kahn
Smith Barney Citigroup - Analyst

Scott Soler
Morgan Stanley Dean Witter - Analyst

Anatol Feygin
Banc of America Securities - Analyst

Matthew Jones Catalyst
Fund Management & Research - Analyst

Shinur Gershuni
UBS Securities - Analyst



Good day, everyone, and welcome to the Williams Companies' third-quarter 2005 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.

Travis Campbell - The Williams Companies - IR Director

Thank you very much and good morning, everybody. Welcome to the Williams third-quarter earnings call this morning. Thank you for your interest in our company.

Today, you will hear from Steve Malcolm, our CEO, Don Chappel, our CFO, and the heads to each of our business units -- Ralph Hill from Exploration and Production; Alan Armstrong from our Midstream business; Phil Wright from the Gas Pipeline; and Bill Hobbs from our Power business.

But before I turn it over to Steve Malcolm, please note that all of the slides that we will be talking from today are available on our Web site, www.Williams.com, in a PDF format.

Slide number 2 titled "forward-looking statements" details various risk factors related to future outcomes. Please read that slide.

Slide number 3, entitled "oil and gas reserves" -- the disclaimer is important and we urge you to read that slide as well.

Also included in the presentation today are various non-GAAP numbers that have been reconciled back to GAAP, Generally Accepted Accounting Principles. Those schedules follow our presentation. We urge you to look at those slides as they are integral to this presentation.

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

Steve Malcolm - The Williams Companies - President, CEO

Thanks, Travis, and welcome. As always, thank you for your interest in our company. Our story continues to revolve around the fact that we are opportunity-rich in terms of investment options around our world-class natural gas assets. We are delivering on our growth strategy with solid investments, as you will hear more about this morning, in E&P, Midstream and gas pipes that are earning well above cost of capital returns.

Looking first at some of the major takeaways from the third quarter -- and I'm on Slide 5 -- recurring earnings after mark-to-market adjustments increased nearly 150% over year-ago levels. That's $357 million for the first nine months of 2005, versus $139 million for the same period in 2004. We continue to believe that this is the key financial metric to focus on as you follow Williams.

Yes, third-quarter results did take a significant non-cash hit from a mark-to-market change, but this is the first significant negative mark-to-market change following six consecutive quarters of positive and at times fairly significant mark-to-market movements.

Exploration and Production growth continues on all fronts. Nine-month recurring segment profit has more than doubled. Nine-month production volumes are up 19%.

Continued strength in liquids margins have driven Midstream profits higher -- (technical difficulty) -- on a recurring basis, a $39 million improvement in segment profit for the first nine months. The gas pipeline continues its steady performance, and mild weather in California, high gas prices and the hurricanes combined to depress power margins.

Turning to some of the developments that will impact our future growth, Slide 6, E&P will be ramping up its activities with the arrival of new H&P rigs in the Piceance Basin. Expect to see 25 rigs running in the Piceance by the end of 2006.

Midstream captured a significant deepwater production commitment from Chevron and Kerr-McGee in support of infrastructure development in the blind-faith field in the deepwater of Gulf of Mexico and is preparing to expand our processing capacity in the West with the TXP5 expansion at Opal.

As Phil Wright will describe, we have a number of open seasons that have been successfully completed, or are in progress, which have the potential to significantly increase capacity on Transco -- in fact, five expansions on Transco within service dates ranging from this month to November of 2008. As well, the Northwest pipeline capacity replacement project is scheduled to be in-service in late 2006 and we have an open season covering an expansion of capacity out of the Piceance Basin.

As Bill Hobbs will describe, one of the several deals completed by Power was the resale of 1500 megawatts of tolling rights through 2010. We are proceeding with our first drop-down transaction with WPZ and are planning to sell at least a 25% interest in gathering and processing assets in the Four Corners area. Of course, the terms of this proposed transaction, including the price, will be subject to approval of both the Williams Board of Directors and the Board of Directors of Williams partners -- general partner. Assuming such approvals are obtained, we would expect that sale would be completed in the second quarter of '06.

Finally, as Don Chappel and the business unit leaders will describe in more detail, we are raising capital expenditure and profit guidance in 2005, 6, and 7.

Slide 7 -- the effect of hurricanes Katrina and Rita. We've been pretty proactive about issuing press releases, so I'm not going to talk about this in much detail. Overall, the impact on Williams is expected to be minimal. Generally, with the exception of the Cameron Meadows processing plant, which did sustain significant damage, our operations were relatively unscathed by the hurricanes.

I would want to point out the last bullet on this slide. The original delivery schedule of the H&P flex rigs has been impacted by approximately one month due to disruptions caused by Hurricane Rita at a fabrication facility.

So with that, I will turn it over to Don Chappel.

Don Chappel - The Williams Companies - CFO

Thank you, Steve. Good morning to all of the on the call.

I will quickly run through a summary of our second-quarter financial results and then turn it over to our business unit leaders for a deeper dive on each of their businesses. I will come back later in the call to review our consolidated guidance and other matters.

Now, let's take a look at Slide number 9, our financial results summary. Income from continuing operations of $5 million was obviously relatively small and it was impacted by mark-to-market effects. I will dive into that more so as we move forward. On a year-to-date basis, that 249 million also impacted by mark-to-market, so it's difficult to see with clarity the real results on the reported earnings level.

I'm going to move right to the bottom line here and you can see recurring income from continuing operations after mark-to-market adjustments. Here we strip out the cumulative effects of mark-to-market accounting, and that's our most clear and important measure of our earnings progress. As you can see there, on that adjusted basis, we are reporting $0.22 as compared to $0.09 a year ago -- on a year-to-date basis, $0.60 as compared to $0.27 a year ago.

I'd like to say I am pleased with our results, which are well above our own plan and our forecast for the year is also above our plan and prior guidance. Even more importantly, the outlook for 2006 through 2008 is continuing to solidify and improve as we continue to seize growth opportunities that will create value and do so with a great deal of discipline.

Next slide, please, number 10. I will walk through a calculation of the nonrecurring items. First, impairments and write-offs total 5 million for the quarters -- excuse me, $61 million year-to-date. Expenses related to prior periods, nothing in the quarter; $28 million on a year-to-date basis. Gain on sale of assets totaled $22 million for the quarter, $38 million year-to-date. Then finally, just other $18 million on a year-to-date basis. That totals up to a $17 million deduction in the current quarter and adding back $13 million on a year-to-date basis.

Moving to the next slide, number 11, please, I will walk through a calculation of recurring income from continuing operations after mark-to-market adjustments. Again, these mark-to-market adjustments eliminate the cumulative effects of mark-to-market accounting, which distorts our reported earnings. Earnings after mark-to-market adjustments will correlate much more closely with cash flows from operations.

Beginning with the recurring income and loss that we looked at on the prior slide, we will move into the mark-to-market adjustments for the power business. The first adjustment is to reverse the forward unrealized mark-to-market gains and losses in the current quarter. We had a $153 million loss as a result of gas price increases on the net short gas contracts that do not qualify for hedge accounting. Again, I would just reinforce that we maintain a balanced book of derivatives. However, some of those derivatives do not qualify for hedge accounting and as such, they were mark-to-market, and we had very large changes in gas prices during the quarter.

The comparable period of the prior year, you can see we had $187 million gain that we are reversing out. The change of those two is quite significant. On a year-to-date basis, we would be reversing $90 million of forward unrealized mark-to-market gains, as compared to $280 million in the prior year. The next line is adding realized gains from mark-to-market previously recognized, and that captures the cumulative effects of prior mark-to-market accounting. In the current period, we would be adding back $60 million to accommodate that, as compared to $250 million on a year-to-date basis.

The total mark-to-market adjustments in the third quarter totaled $213 million -- additional income, or to reverse the mark-to-market expense, as compared to 142 million going the opposite way in the prior year, or a $355 million change. That change, on a year-to-date basis, is 247 million. Tax affecting that -- we get to the after-tax mark-to-market effects of $130 million in the quarter and $98 million year-to-date. Thus, the calculation of the recurring income from operations after mark-to-market adjustments of 125 million in the current quarter as compared to the 49 a year ago and 358 million on a year-to-date basis, as compared to 141 million a year ago and then the per-share amounts that I mentioned earlier. Again, this is our most important and clear measure of our earnings power.

The next slide, number 12, let's review a summary income statement. Again, segment profit is distorted as a result of nonrecurring items and particularly mark-to-market adjustments. I won't spend a lot of time talking about that but you can see the large variation.

Net interest expense is down as a result of the significant debt reduction that we undertook over the last couple of years and then early debt retirement expense is nonexistent in 2005. We have reduced some debt, but it has all been (indiscernible) maturity dates. Then other income and expense has increased in terms of the net expense, and that is principally as a result of nonrecurring items included in the current quarter.

Next slide, please, number 13 -- let's review third-quarter segment profit by business unit and consolidate it, focusing really on the recurring column before and after the mark-to-market adjustments. Again, each of our business unit leaders will drill into these but you can see a sharp improvement in E&P; Midstream and gas pipelines relatively steady; and power reported -- excuse me, recurring basis but including mark-to-market is down sharply, moving from a profit to a loss. If we total it up, you can see the mark-to-market adjustment there for Power that we spoke to earlier. The segment profit after the mark-to-market adjustments total 382 million for the quarter as compared to 317 million a year ago. It's up 65 million or about 20%. We note power, on an after mark-to-market basis, reported $13 million loss as compared to a $33 million loss a year ago. Again, each our business unit leaders will speak in some detail on the results.

The next slide, number 14 -- review the same format of data on a year-to-date basis to get E&P on a recurring basis up sharply. Midstream up nicely as well -- excuse me, this would be the next slide, please, number 14. Okay. Midstream is up as well on the strength of strong liquids margins. Gas pipeline is relatively steady and then again Power's earnings distorted by mark-to-market.

Moving to the bottom of the page, after mark-to-market adjustments, Power is just below breakeven. This compared to a $34 million profit a year ago. However, the profit a year ago was largely as a result of liquidating certain positions within the Power portfolio. Again, on a segment profit after mark-to-market comparative basis, we have 1.130 billion in consolidated results as compared to 965, up 165 million or about 17% year-over-year.

Next slide, please, number 15 -- let's review a summary of major changes in quarter recurring segment profit after mark-to-market, again starting with the third quarter '04 -- 317 million; moving to the third quarter '05, 382 million, a $65 million increase. That's largely attributable to E&P's higher volumes and higher net realized prices. Again, the business unit leaders will go into some detail.

The next slide please, number 16 -- I will walk you through key cash flow items, beginning with unrestricted cash at the beginning of the quarter of about 1.3 billion; cash flow from operations for the quarter was 289 million, nearly 1.1 billion on a year-to-date basis. We had proceeds from the sale of LP units -- Williams Partners, $111 million. We had debt retirements during the quarter of 23 million or 244 million on a year-to-date basis; capital spending of 369 million or 886 million on a year-to-date basis. "other" is principally related asset sales in the third quarter -- yielded an improvement in cash of 64 million, an unrestricted cash balance of 1.361 billion plus our unused credit facilities gives us about $2 billion of liquidity, which is certainly a very large amount. However, I would say we have some pretty substantial needs at this point in time.

First, I would footnote too on that schedule, it includes international cash totaling about 200 million and cash that's earmarked to settle some legacy matters, including an IRS settlement that's approximately 200 million and a number of other contingencies.

As well, we also have margin volatility and potential margining requirements. We currently have margin posted -- adequate assurances margins and prepays totaling 1.785 billion -- and that's on Slide 92, I believe -- up from the end of the second quarter, where it was 1.108 billion, an increase of about $650 million between June 30 and 9-30. At the same time, we can see the potential volatility of another $900 million or so as a result of hedge positions and commodity positions we have with the extraordinary volatility we see in energy prices. So again, we need very substantial liquidity to manage our commodity positions, as well as to provide for other working capital needs.

The next slide, please, number 17 -- debt balance. Debt balance at 9-30 is 7.721 billion and I mentioned down 241 million for the year and 23 million in the quarter. In terms of variable-rate debt, again I would note that the variable-rate debt is limited to $648 million.

With that, I will turn it over to Ralph.

Thank you, Don.

I'm pleased again to report another very strong quarter for Exploration and Production. Our volumes continue to rapidly increase; our profit more than doubled again; and we are also again increasing our guidance.

Turning to Slide 20, our third quarter 2004 to third quarter 2005 financial highlights include that the volumes have increased 17% quarter-over-quarter. Our net realized price is up 44%. We did have a hedge ineffectiveness expense of 15.8 million in the third quarter of 2005. Recurring profits increased 96%, or if you exclude this hedge ineffectiveness, it's up 119%.

You will note that we did have this hedge ineffectiveness during the quarter. This is based on the NYMEX collars that we have. Please recall that we did the NYMEX collars to retain the price upside versus fixed-price hedges, and we did obtain that upset, though, with NYMEX collars, you have a risk of some ineffectiveness, particularly if you are a Rockies producer, which we primarily are. Also, going forward, these NYMEX collars do continue through 2006 and then drop-off, which is a little bit in 2007. Please also recall the most recent collars we did we put on during the second quarter are Rockies-basin-specific and they should avoid this ineffectiveness.

Looking at the base business sequential quarter, it also improved, increased our recurring segment profit by 16%. Including the hedge ineffectiveness, it was up by 30%. Our volumes are up 5% sequentially in the quarter. Overall, we've had a $186 million negative hedge impact for 2005.

Turning to Slide 21, this is the continuation of the slide I've shown you this year through the last two calls. It's updated through September. As you can see, our domestic volumes continue their impressive growth and are up 16.4% since January of '05. If you look at just third-quarter '05 volumes, versus the entire year of 2004, our volumes are up 21%, so again, continue to have a substantial increase in our volumes.

Looking at Slide 22, accomplishments -- the volume growth is impressive. Full year --we've gone over one year with no loss time accidents for E&P and with the amount of activity we've ramped up, it's something I'm very proud of our team for. Not only are they increasing the results very impressively but they are doing it very safely, and we are actually at 390-some days of no lost-time accidents.

Big George gross production is up to 135 million at day. I have some -- a slide on that in just a minute. Looking at the Piceance, we have 12 rigs operating in the Piceance Valley, 3 in the Highlands area, which I'll talk about again. As Steve mentioned, the first H&P rig will be delivered in November. It was scheduled to be delivered in late October; it will now be delivered in late November, and we will be spudding in early December.

Our Highlands production, which I will talk about, which is the new projects, which we call Highlands, are now reaching production of 13 million a day on a gross basis. We've attained another Piceance/Highland opportunity I will talk about. The Fort Worth acquisition is progressing. We've drilled five wells; we have two more drilling. We have two rigs operating, and we have a total of about seven rigs -- pardon me, seven wells waiting on pipeline. So we are progressing in Fort Worth.

San Juan continues to be stable, which I think is a compliment to that team. They are stable at really record volumes. It is a very mature basin, but our team continues to find a way to keep our production stable.

International volumes are up 10%, so we are also doing very well in the international side.

Turning to Slide 23, the Powder team is the leader in the Powder River Basin. I firmly believe this. Our production in the Big George is up 67 million a day or 98% over a year ago. We are now at 135 million at day. Sequential with quarters, we have 25 million a day and again, the Big George production is offsetting the Wyodak decline, basically keeping it flat in the entire basin, but volumes continue to increase. Our production is about 49% of the industry's Big George production, so we are a leader in this area.

On the permitting side for 2006, we have about 65% of our permits already in hand and the rest we expect to receive in plenty of time to achieve what will be a record drilling program in the Powder River next year.

Slide 24 is a continuation of the Piceance volume growth I've showed the last few times. The Piceance team continues to do a great job. We are about 84 million or 34% in volumes over a year ago and we again grew 6% sequentially from quarter to quarter.

Slide 25 is a review from the last call. Our 3P reserves remain at the 8.5 trillion cubic feet, which as you will recall are up 21% from what we had at year-end, 2004. I put this in as a refresher and to stress to you that the next several slides -- when I talk about the Piceance/Highlands, those reserves are not include in this 8.5 Tcf that we have 3P reserves. So when I talk about Trail Ridge, Ryan Gulch, Red Point and Alain (ph) Point at the next few slide, those reserves and potential reserves are not included in these numbers.

If you move to Slide 26, we included a map of the Piceance/Highlands and the operations update. If you look at it, this depicts the entire Piceance Basin and if you look to the south part of it, it includes our traditional operating areas of Grand Valley, Parachute (ph) and (indiscernible) which are along the Colorado River. North of these are all of our new projects.

Looking first, the northernmost, Ryan Gulch -- that's a farmout we've been paying for a major (ph) during 2004. We drilled three wells there in 2004 and we planned eight wells in 2005. It's due west of Exxon's Love Ranch and Piceance Creek field, and our drilling to date has established a presence at the same hydrocarbon system that it's found in those field.

Trail Ridge is just south of that and just to the north of the Grand Valley field. It is continuing to be developed this year. We drilled 3 wells last year and an additional 12 this year. Geologically, we believe this area has proven to be similar to the Grand Valley area, which is just to the southeast, which is one of our core areas.

The Red Point is just due north of Grand Valley. Numerous industry wells have been drilled in this area, and we plan to drill two wells ourselves this year. These industry wells and their results have established that this area is very productive and similar to our Grand Valley area.

The final area I will discuss is the Alain Point area. It's a new area that was again obtained from a major and one where we've started drilling this year. Our initial results there showed it to be an extension of the adjacent Parachute field you'll see just to the south of that, which again is one of our core fields.

Looking at Slide 27 on the Piceance/Highlands project summary, I won't go through all these numbers but this table does provide details for each of the areas. Two key points to make -- again, these figures are not included in the previous 3P reserve figures, actually three -- that's one. The second one is we've applied for a ten-acre application at Trail Ridge, and we are on the December docket for that, which is in front of the COGCC for December 5.

Finally, if you used a ten-acre density in all of these areas, which we are not saying they will go there -- you'll notice Trail Ridge, Ryan Gulch, and Alain Point are currently listed on this slide as 40-acre density -- but if each of these areas would go to ten-acre spacing, and we are currently in the process of moving to ten-acre spacing on Trail Ridge, assuming approval, then we have additional potential reserves of approximately 5.5 trillion cubic feet, which would go on top of the 8.5 trillion cubic feet of 3P reserves that we have. So that number again totals up to be 5.5 Tcf.

Slide 28 gives our year-to-date results of the Piceance/Highlands. Our current rate from all Highlands wells is 13 million a day. We are very proud of that. Let's go area by area. First, at Trail Ridge, it has been our most active area this year; we've drilled 12 wells and we have 9 completed. All of these wells have been successful. They are averaging about 1.1 million cubic feet a day over the first 30 days of production. This leads us to believe that the reserves will be in the range of 1.2 to 1.4 Bcf per well.

We've also modified our completion practice in this area in the 2005 program from the 2004 program to shorten the intervals we treat and to begin flow-back operations sooner. We done that most in our traditional manner, and it's also -- early in this program, we have employed Halliburton's Cobra Max (ph) completion technique in several wells and will continue to evaluate that technique. What this process does, it's intended to further shorten the completion intervals by precision perforating, and it also stimulates the individual sands and hopefully provides immediate flow-back and does provide immediate flow-back.

There are other completion methods in these areas and also in the Piceance Valley in technology we will be utilizing this year and next year. These changes have been successful at increasing both the rates and the EURs for Trail Ridge from last year's programs, so 2005's program has improved substantially on 2004, which typically happens in these types of resource plays. The current producing rate from Trail Ridge is 10 million a day on a gross basis.

Moving to Ryan Gulch, it's an area where we will drill eight wells this year. Today, we've drilled two and completed one of these. We have one rig operating in this area and we have a second rig we will be adding this month. It's not an H&P rig; it's a neighbor's rig. That will bring us to 16 before the H&P rigs begin running in the Valley. So we will have 16 -- not in the Valley, 16 total in the Piceance.

Our wells and offset wells suggest initial rates of about 1.4 million cubic feet a day of production, and EURs ranging from 1.2 to 2.0 Bcf per well. It's still early in the Ryan Gulch program but we're pleased with it and we believe we can move those reserves up to the upper end of that range.

Red Point drilling is scheduled to begin again this month. We will drill two wells this year in Red Point. Looking at all of the other operators there in the Grand Valley -- or nearby Grand Valley field makes us confident we will see very similar results to what the other operators have and what we have in Grand Valley. This area is already ten-acre spaced.

The newest project that we have is Alain Point. We drilled four of six wells there this year. We've completed one. We have two rigs operating in Alain Point and expect to be complete by the end of the month -- these two wells. The one well we have on production is averaging 1.1 million cubic feet a day, and we expect ultimate recoveries of reserves to be in 1.2 to 1.4 Bcf, based on all of the data we have in the very nearby Parachute field where we've drilled literally hundreds of wells and also the wells we're drilling so far. The Parachute area is already spaced on ten-acre spacing, and we expect that Alain Point ultimately can be developed on this density also.

So in summary, we are very excited about all of our Piceance/Highlands areas. We are now producing 13 million a day gross, about 10 a day net to us. We expect these areas to provide material proved reserves to us in the future and also we believe, this year, we will be adding on the order of about 100 Bcf, 100 Bcf of reserves to our year-end report based on drilling we have so far. We expect substantial reserve additions in the future.

Turning to Slide 29, with industry costs going up and also prices going up, I thought it's important to refresh the three-year average cash margin analysis I showed in March. As you can see, our realized gas price assumption is up from the previous. It was 5.52; previously it was 4.56. What we are using is, for our unhedged volumes, we are using a NYMEX average, if you will, of $8.07, which is several dollars, probably $2 below market, so we're still somewhat being conservative if prices stay high. We are using the $5.52 net realized price and to get to that, we take the approximately 8.07 and we're taking out fuel and shrink, basis, hedge loss to get to the 5.52. So the 8.07 goes down to 5.52.

Then looking at cash margin, we deduct for the cash costs -- to get to cash margin, the cash costs, we did a lease operating expense of $0.47, gathering at $0.48, operating taxes at $0.53, and SG&A of approximately $0.33. That equals our cash costs of $1.81. They are up from the March costs, obviously, as many costs are up in this industry, but again, not up as much as our revenue side on our conservative outlook here. If we used market prices, they would be up substantially more, the market prices would. All in all, this equals a cash margin of $3.71, a very profitable business.

The F&D costs on this slide remain at $0.78. Remember, that is an '02-through-'04 average. We will be updating that when we are done with our drilling program this year, but I do not expect that $0.78 to vary much at all. It will be right in that range.

The cash margins remain very strong, based on what could be a conservative price deck. If you look at our operating profit margin, if you take approximate $1.20 or so DD&A rate from that cash margin, you will see that our operating profit margin is very strong also in the 2.50 range. If you take that number times the midpoint of our volume range, you'll see that it's very close to the midpoint of our operating profit range. So again, a very strong business on both cash and operating profit margin, and it does have upside based on what current prices are versus what we are actually showing on this slide.

Slide 30, we have increased our guidance substantially in all areas. You will note that the segment profit is up. I won't walk you through all of these numbers. Our guidance for profit is up, on a midpoint-to-midpoint basis, at a higher rate than our CapEx guidance. We are also increasing our capital spending. I have a slide -- the next slide will reconcile this. But as you can see, we are up in profit, Cap spending and production in all areas that we have. We also have, on the bottom of the slide, the hedge volumes, which have not changed from the last call. So our guidance is up substantially from last time.

I would point out that 2006 is using an unhedged NYMEX price assumption of 8.50, which is below market, and also that 2007 is using an unhedged price assumption of $7 at NYMEX. If 2007 numbers would stay flat in the 8.50 NYMEX range, then that segment profit range in the very top of the 2007 column of 775 million to 900 million would go up by 200 to $250 million on both ends of that. So, you would add 200 to 250 to the 775 and also to the 900, if we stay in the 8.50 range instead of dropping to the $7 range that is in this assumption on this slide.

Slide 31, guidance reconciliation -- very simple. On the CapEx side of the world, industry costs are up although much less than the market prices are up, and we also have significant new projects, particularly in the Piceance/Highlands, which are beginning to contribute to us, as I mentioned. We had 13 million a day of production in the Piceance/Highlands. As you can see, on our CapEx side, we are up $190 million for 2006. A number of that is for facilities that we're building both in the Valley, the Piceance Valley and also for the Highlands, also for additional drilling in the Piceance/Highlands and in the Fort Worth area. Then industry costs overall are up on the $100 million range. You can see, in 2007, again CapEx is up, both in the industry cost and on the new project side.

The segment profit side -- both segment profit on both Lyons (ph) (indiscernible) price and production are up on our existing assets and also for our new projects. Again, I've talked about that our unhedged price that we're using for these numbers is significantly below market prices.

Finally, on Slide 32, our strategy does remain rapid development of this premier drilling inventory. You can see that we have meaningful volume growth quarter after quarter; this is all through the drill bit. Our history of high drilling success and low finding costs continues -- again, short time cycle investments. We are in the top quartile in all majors we look at, in both G&A, drilling costs, efficiencies, LOE; we remain in the top quartile and typically in the top three or four. This inventory is expanding, as you've seen, in the 8.5 Tcf and you see as we start to move into the Piceance/Highlands -- these new opportunities that we have a significant opportunity to expand our 3P side of the world.

This workforce I can't complement enough. They are very experienced; they're very talented; they are working very hard. In doing that, they are also at 380 to 390 days of no loss-time accidents, so I also complement them for being incredibly safe as they grow our volumes.

With that, I will turn it over to Alan Armstrong. Thank you.

Alan Armstrong - The Williams Companies - SVP Midstream Gathering & Processing

Thanks, Ralph.

I will make three main points this morning in the Midstream presentation here. First, we do have another guidance increase we're pleased to report on. I'm going to give you an update on the impacts from the hurricane, both in the third quarter and what we think that looks like residually in the fourth quarter, and then finally, going to talk about the additional growth opportunities that keep coming at us and that are right in and around our core business, including two recently awarded contracts that are going to anchor nearly $250 million in expansion.

With that, we will move onto Slide 34, please. I am going to start here with comparison to last year's third-quarter performance and the year-to-date comparison. Good news on 2 fronts here -- first, this is the best performance through three quarters that Midstream has ever had. We are leading last year's numbers by about $39 million. Secondly, despite a $12 million impact from the three hurricanes during this quarter, we've still posted a strong third-quarter performance.

The key drivers for the quarter were overall higher fee-based revenue, driven by higher gathering and processing fees in our Western region. This was partially offset by the lower deepwater fees that were due to the hurricane outage. Overall, fee-based revenue is up $22 million for the year and again, this is even in the face of hurricane outages, where our deepwater fee-based business robbed us of about $7 million in fee-based revenues. Also our olefins business quarter-to-quarter and year-to-year increased modestly and helped us out during the quarter.

The geographic diversity of our business did help us out in the third quarter, as we saw margins increase out West as a result of the NGL production losses from several damaged plants in the Gulf Coast. But overall, our NGL production was down sharply due to Mobile Bay, Cameron Meadows and Marcum (ph) all being without production for an average of nearly 20 days during the third quarter. Our largest plant, the Mobile Bay plant, was out of production for about 32 days for the quarter. So you will note a strong decrease in our production, but we did enjoy the margins out West.

Moving on to Slide 35, we did manage to respond very quickly to get service returned to our customers in the Gulf of Mexico. In fact, our discovery partnership at Lerose is providing backup service to several damaged plants in the New Orleans area. So not only did we quickly repair and restore service, we were able to weave our way through the FERC to provide alternate flow paths to approximately 500 million cubic feet a day that would otherwise be shut in. We expect -- some of that has already started flowing and we expect that to ramp up throughout the month of November. So, kudos to our discovery team in helping get production back up in the Gulf, and we will actually see our volumes on our discovery system more than double as a result of the efforts there. We do not know how long that will last. It's obviously dependent on when the infrastructure that is supplementing gets repaired.

So, we fared pretty well on Katrina, but our Cameron Meadows plant took a near-direct hit from Rita. We're hoping to have this back up in partial service by the end of the year and probably back returning to full-service sometime in the second quarter of next year. We do expect our business interruption insurance to kick in this month, and the property damage deductible was reserved in the third quarter, so fourth-quarter impact should be less than $2 million at our Cameron Meadows facility.

Also some good news coming out of our Canadian olefins business, as our Fort McMurray extraction plant is now running at design capacity. This is following the return to service by the SunCor upgrader there that was fire-damaged at the first part of '05. So, back up to higher volumes than we've ever seen there, and we are hitting that at a pretty nice margin environment.

We also signed up two very large contracts, as forecasted in our last call. That has allowed us to move ahead with the expansion of our fifth train at Opal and also an expansion for Devils Tower facility out to Chevron, Texaco and Kerr-McGee's Blind Faith prospect.

I previously advised on the continued increase in our fee revenues out West. Here's the last note -- that continues to increase, in terms of the rates that we have out there, as demand and drilling remain very robust in the area. So we expect continued, steady increase in that and I think that's a very healthy signal for our business going forward out there.

Moving on to Slide 36, there's going to be three main points to make with this slide. First, we're raising guidance again for our '05 segment profit. This time last year, we were at 300 to 400 -- sorry, 310 to 410 this time last year. This increase has been driven largely by our NGL and olefins margins, and this has driven us to this new range of 440 to 480. This remaining range has driven the 40 million of remaining range we have (indiscernible) 440 and 480 is driven by what -- we are seeing some very volatile NGL margins right now, as gas prices are swinging wildly, so we're seeing our margins move up one day and down the next.

If we saw October-like margins again in November and December, this would certainly drive us to the upper end of this range. Also, our olefins business -- we've seen very strong margin increase, as there's a lot of ethylene capacity out in the fourth quarter. But we're seeing reduced volumes at our facility because we're not able to get our hands on enough ethane there to produce the ethylene. So the story there on the olefins is higher margins but lower volumes.

The second point -- with the announcement of our Opal's fifth train and the expansion of Devils Tower infrastructure to Chevron's Blind Faith project, we're raising capital in '06 and '07 with a slight increase in our '07 operating profit due to a partial year-over-year contribution from the fifth train at Opal. So you can see we're raising that from what was 400 to 520 up to 410 to 530. Obviously, the punch from those investments shows up in '08.

Finally, an update on what we showed you'd last time as three categories of potential expansion opportunities. First, we had the nearly done package of about 250 million in the last call. We now move that into the category of contracted and committed. We're moving ahead. That is the Opal plant and the Blind Faith prospect.

Secondly, we announced a category we called high probability of success. That was in the 200 to $300 million range. Our probability of success on several of these projects has enhanced significantly since the last call, and we hope to be announcing these at our next call, as we announce fourth-quarter earnings.

Then finally, we have several large projects that continue to develop nicely and that were earlier quoted as being in the proposal stage. These projects -- I suspect several of those will be moving into the highly profitable category at our next call as well. So this last category, most of that investment is largely '07 and '08, but a point to be made here is we do have a robust group of opportunities moving forward through our pipeline right now, and we expect to continue to seek to bring those to fruition. I would comment that these are not acquisition kind of prospects for the most part; this is all just organic growth in and around our existing business.

Moving on to Slide 37, this just kind of gives you a graphic, again, of what's going on as we further invest in this business. There's really three points to make on this slide. First, our base business is neutralized to our current forecasted margin, and our base business, even with that, is continuing to grow. You can see that with the dark blue bars there and the dip in our range for '06 you can see there is really driven by just a forecasted lower NGL and olefins margin. So, the base business is again this solid dark blue, and then the diagonally hatched bars represent the margins in '04 and '05 that came in above what we are forecasting the margin to be in '06 and '07. So it shows a very healthy base business that continues to grow even without the capital investment, which is shown on top there in green.

Finally, or sorry, the second point to make here is the running-in-place capital as we call it. It is still continuing to be about 50 million. That's about half maintenance and half well connects. This is shown there in the grey and yellow bars, so we continue to be able to hold that line. This is allowing our base business to remain healthy and spinoff significant free cash flow from our core business.

The light-blue expansion bar there are delivering returns in the later years, as you can see, and that shows up in the green with about 14 million of cash flow coming in '06 from about $70 million of investment in '05. Of course, not all of this capital is put in service during 2006, and this is especially true for the Blind Faith capital, which is occurring in '05, '06 and '07 but doesn't really contribute until 2008.

So hopefully, that gives you a picture of what's going on with our base business and where we expect that expansion to take us. Hopefully, when we show 2008 in the not-too-distant future, we will be able to show you how that's really going to turn us up.

Moving on to Slide 38, we are excited to be expanding our strong relationship with Chevron-Texaco and Kerr-McGee once again out in the deep water with this Blind Faith prospect. This just shows you a little bit of detail about what's going on there. First of all, this contract comes with a large area of dedication, and we have reason to expect reserves and production to flow through this infrastructure for years to come, based on our analysis of the area. The producers plan to invest approximately $900 million just to develop this first prospect. As I said, there's several other prospects in the area that we are very excited about that will feed into this infrastructure.

Just a few more details on it -- we will have the line ready for service in third quarter of '07. Our investment plan doesn't have production starting on the first part of '08, but we will be ready for service in the third quarter of '07. The producers expect a November start-up and we are just adding some conservatism into our investment strategy there. It's about $177 million; it feeds both our existing Devils Tower infrastructure; it feeds our Mobile Bay gas plant; and it provides nice supply base through the Transco and Gulfstream infrastructure as well. So, we're very excited about this and this is right on strategy for us and particularly excited about continuing to expand our relationship with Chevron-Texaco and Kerr-McGee.

Moving on to the short explanation here on 39 of the Opal TXT5 (ph) plants, we received a very large volume dedication from Ulter (ph) petroleum, from their Pinedale anticline field, and the volume dedication that we have from them more than anchors this expansion. In fact probably our biggest question on this one is whether or not we are expanding this large enough, given the remarkable performance from the Pinedale anticline field. So we're very excited about this. We are able to -- our reliability increases as a result of this, making us very difficult to compete with out here, as does our unit cost continues to get lower and lower as we expand this important facility for us.

Moving on to slide 40 here, just to wrap up, first, our geographic diversity yielded Midstream strong earnings despite the impact of three hurricanes, and we expect minimal residual impact from the hurricane aftermath in the fourth quarter. We were very excited about how our strategy of complementing the Midstream business plan with WPZ is coming together. Specifically, we are pursuing several opportunities to expand our footprints and throughput in our core basins that are leveraged off of WPZ investments that we feed into our existing assets, so everything is right on track there and we couldn't be more excited about that.

Then finally, our pipeline of opportunities is moving ahead as predicted, and we look forward to describing this and more details of our business at the Midstream tutorial, which is scheduled for November 30 in New York City.

With that, I will turn it over to Phil Wright from our Pipeline Group.

Phil Wright - The Williams Companies - SVP Gas Pipeline

Thanks, Alan. Consistent with Steve's message that the story from gas pipes is continued steady performance, operational and project execution performance is excellent. We continue to see robust growth opportunities in markets served by our pipelines.

Turning to Slide 42, please, considering the absence of expansion projects contributing to this year's earnings, I'm very pleased with both the financial and operating performance of our gas pipes during the third quarter. Recurring earnings for this quarter and for the year 2005 continue to be in line with prior-year results. We had unfavorable impact on recurring earnings from revenue improvements on Gulfstream attributable to new contracts signed during the year. Those were partially offset by the loss of revenues from the termination and prepayment of the Gray's Harbor lateral transportation agreement.

At $161 million, reported results for the quarter are ahead of prior year due to the effect of a FERC ruling issued during the quarter, which resolves a very old issue related to a full tracker which was filed in 1999. Based on the order, we were able to reverse a $14 million reserve we had on our books.

Slide 43, please - in September, we received final FERC approval to construct and operate our 26-inch capacity replacement project on Northwest pipeline. As I've noted in prior calls, the project is expected to cost 333 million and we project a November, 2006 in-service date. These costs will be fully recoverable starting with our January, 2007 rate case.

While the twin hurricanes did cause supply disruptions on Transco, we are gradually resuming flow of previously shut-in production. Much but not all of the disruptions were the result of liquids extraction and transportation infrastructure being down. By mid-November, we should be pretty close to pre-Katrina and Rita gas supply levels. Overall, as Steve said, we fared well through two of the worst back-to-back hurricanes to hit the Gulf of Mexico. Repair work on our pipelines due to storm damage is estimated to be just over $20 million and will, for the most part, be covered by insurance. The impact to revenues has been minimal.

I should note, at this point, the dedication of our people who have made it possible to recover quickly from these storms. Working long and hard hours, these people have returned to show up for work on time, even though they didn't have a home to return home to, and we are grateful for their fine effort.

In October, Gulfstream Pipeline in which we are a 50% owner with Duke was successful in placing an $850 million nonrecourse financing, which, after retiring an existing loan, produced about a $310 million cash distribution back to Williams.

I'm very excited about the growth activity that we're seeing across all of our pipelines. In August, Gulfstream began providing transportation service to Tampa Electric under a new, long-term firm contract to provide 48,000 dekatherms a day of capacity. With addition of this contract, Gulfstream's capacity is now more than 70% subscribed under long-term firm contracts. I'm pleased to say that, on November 1, we placed our $16 million central New Jersey expansion on the Transco system in service. This project will provide 105,000 dekatherms a day of firm transportation to South Jersey gas. Because this project is classified as incremental, we will commence earning on our investment concurrent with the in-service date. We expect this project to add just over $2 million of segment profit to our 2006 results.

In July and August, Transco conducted what turned out to be a very successful open season for additional firm transportation from receipt points in North Carolina to delivery points in the greater Washington, D.C. metropolitan area under our proposed Potomac expansion project. The expansion has been designed to create 165,000 dekatherms a day of firm transportation capacity and has been fully subscribed under long-term contracts. The estimated capital cost of the project will range to upwards of $65 million. We plan to file an application for FERC approval of the project during the third quarter of 2006 and target having it in-service November 1 of 2007. As well, over the last several days, we've announced open seasons at Northwest pipeline and Transco on the Parachute lateral and the Centennial expansions, respectively. While we will need to await the results of the open seasons to determine the final size and cost of these projects, it again points to the excellent growth opportunities in the markets served by our pipelines.

Slide 44, please. Our guidance includes updates to both segment profit and to capital, starting with 2005. We've narrowed the segment profit guidance range by increasing our full-year forecast by $40 million on the low end and $30 million on the high end of the range to reflect the $14 million of nonrecurring earnings we booked in the third quarter, as well as favorable adjustments to our operating expenses. We've also narrowed the range of our 2005 capital forecast. As you may note, we've increased the lower end of the range by $20 million to reflect slightly stronger than expected third-quarter expenditures and higher expenditures in the fourth quarter. We still expect to close the year within this capital guidance range.

Our guidance for 2006 segment profit reflects elimination of about $63 million of favorable but nonrecurring items in 2005. As I mentioned in our second-quarter call, the FERC General Accountant's office changed the way we have to account for Pipeline, Safety and Integrity Act compliance expenditures. This change will require us to expense certain costs, mostly related to internal inspections, which FERC previously had as capitalized. So we estimate that we will have to expense $31 million in '06 that we previously had in capital. The result of our Gulfstream financing will be incurring $20 million in interest expense. But again, that financing provided $310 million of cash to Williams.

As well and as I noted in prior calls, we're not bringing any major expansions into service, nor do we have any rate cases coming into effect in 2006. Yet, we have normal inflationary and other pressures on our operating expenses. Boiling that down, we are adjusting the lower end of our segment profit guidance range down by $15 million. Please note, the cash effect of the FERC order to accounting change is something moving dollars from the capital side to the expense side. As such, we've accordingly lowered the top end of our capital forecast by $30 million and have left the bottom end the same, narrowing the range.

In 2007, as you are aware, we are planning rate cases at both Northwest pipeline and Transco to be effective first quarter of 2007. As a result of these rate cases, we anticipate being able to recover, through our new rates, the previously discussed internal inspections costs and so do not believe that our 2007 earnings will be impacted by that change. Our 2007 capital expenditure forecast has been increased due to the recently announced Potomac expansion.

Slide 45, please. I've already discussed the major changes in our capital forecast, but to recap, we are anticipating moving $30 million of integrity costs from capital to expense in 2006. Also, we've added the costs of the Potomac expansion projects -project. The projects for which we recently announced open seasons at Parachute lateral and Centennial are not included in this forecast.

Next slide -- number 46. Summing up, our strong performance -- (technical difficulty) -- operationally and financially. Gas pipes continues to be a strong cash flow provider. We're having continued progress and excellent execution on our compliance and reliability projects and our expansions. The preparation for our rate cases are on track to be in effect in 2007.

With that, I will turn it over to Bill Hobbs.

Bill Hobbs - The Williams Companies - SVP Power

Thanks, Phil. Good morning. We are now on Slide 48. As Steve indicated, the third-quarter results were adversely impacted by high natural gas prices, extremely mild weather in the West, and plant outages at Ironwood and our California plants. During and subsequent to the quarter, we were successful in contracting for five power sales contracts, including the CLICO contract that reduce these risks in the future and create cash flow certainty.

Segment profit loss of 227 million for the quarter was primarily driven by the mark-to-market losses, as Don discussed earlier. These mark-to-market losses are non-cash and do not reflect real economic value. After adjusting for the non-cash, mark-to-market impact and the buyout of a gas supply contract, we realized recurring segment profit loss after mark-to-market of 13 million, versus a loss of 33 million for the same quarter last year.

Slide 49 -- looking at year-to-date cash flows for the Power business, segment cash flow from operations is 44 million positive, and Power standalone cash flow from operations is 5 million positive, year-to-date. Please see the footnote reflecting that these numbers include 36 million of losses on nonrecurring items.

Slide 50 reflects the items that are impacting our third-quarter performance. As I indicated in the second-quarter call, we anticipated normal temperatures in the West. Instead, we saw extremely mild weather in the western U.S. with cooling-degree days being 43% lower than last year in Los Angeles.

The high natural gas price environment was a benefit overall for Williams but was a detriment to gas-fired merchant fleet. The hurricanes also resulted in stranded firm transportation on Transco's Mobile Bay lateral, resulting in nonrecovery of demand costs. Also during the quarter, we bought out (indiscernible) uneconomic gas supply contract under unfavorable terms -- under favorable terms.

Slide 51 reflects cash flow for the quarter and year-to-date segregated into the various categories you have seen in the past. Expected merchant cash flows did not materialized during the quarter for the reasons I highlighted earlier. Segment cash flow and Power standalone cash flow remained positive for the year.

Slide 52 -- as a result of our third-quarter performance, we are lowering 2005 guidance for reported segment profit after mark-to-market and recurring segment profit after mark-to-market. We are also lowering 2005 cash flow from operations guidance to a positive 25 million to 75 million. We are lowering the upper end of our 2006 reported segment profit after mark-to-market guidance by 50 million as a result of the Power contracts we've recently closed and that these contracts protect our downside but limit our upside.

Slide 53 -- I will now discuss the new contracts to the extent we are allowed under the confidentiality provisions of the agreement. Since deciding to stay in the business a year ago, we have had great success in reentering the market and closing risk-reducing transactions. We've been successful with all targeted customer types, and we've been successful in replacing over-the-counter hedges with more effective hedges that reduce our margin requirements.

On slide 54, there is a list of deals we've closed this year. The key deals are the 1500 MW sale in the West, which is listed here twice by mistake, and the 500 MW sale to CLICO of that is awaiting Louisiana Public Utility Commission approval, which we expect by year-end.

Slide 55 takes us from our revised 2005 guidance and walks us through our revised 2006 guidance. Although we expect the high natural gas price environment to continue, these new sales reduce that risk in addition to weather uncertainty. These additional hedges create more cash flow certainty and limit our downside.

On slide 56 and in summary, our third-quarter results were adversely impacted by weather, a volatile gas market, and unplanned unit outages. But despite the unfavorable environment for gas-fired generation, we expect to remain cash flow positive for the year and we continue to close new contracts that create cash flow certainty, mitigate risk, and reflect our ability to continue to hedge into the future We look forward to providing a more detailed update in our tutorial on November 30.

I will turn it back to Don.

Don Chappel - The Williams Companies - CFO

Thanks, Bill. Next slide, please, number 58 -- let's review updated 2005 guidance. The prior guidance is noted on the right column.

Segment profit is relatively steady on a reported basis, but this includes the mark-to-market effects that we talked about earlier. As a result, I will drive right to the bottom line here. The last line in the schedule, diluted EPS recurring after mark-to-market adjustments, you can see is at $0.84 to $0.94, up from a previous guidance of $0.70 to $0.90 and reflects strong prices both for natural gas and liquids margins.

The next slide, please, number 59 -- this slide summarizes the business unit and consolidated guidance. Again, segment profit is up in each period, primarily as a result of higher natural gas prices. Note that E&P increases in 2007. Despite the assumption of a declining price, we really move from an assumed NYMEX price in 2006 of $8.50 to a $7 price in 2007. Yet, the assumed segment profit increase is despite that as a result of strong increases in volume.

The next slide, please, number 60, summarizes business unit and consolidated guidance for capital spending. Again, we peak in 2006 as a result of the Northwest pipeline replacement project, but as each of our business leaders have indicated, we continued to seize value-adding growth opportunities on a very disciplined basis.

The next slide, please, number 61 -- a summary of key financial measures. We've previously discussed the segment profit guidance. I will move to cash flow from operations. Cash flow from operations is increasing in each of the periods from our prior guidance and increasing year-over-year quite strongly.

Capital spending also increasing as a result of higher industry costs in E&P and accelerated drilling program, as well as new projects in both Midstream and gas pipelines.

Then finally, operating free cash flow is up a bit in '05 and then down somewhat in '06 and '07, as we seize these additional opportunities and we remain opportunity-rich for value-creation projects. I would also note that this schedule does not include any MLP acquisitions or Williams asset sales that may occur and in fact, as you know, we announced, this week, the first of such Williams asset sales to WPZ.

The next slide, number 62, please -- as we've previously indicated, we are opportunity-rich and we continue to seize opportunities to create EVA and value for shareholders by further accelerating our E&P development, capturing value-adding Midstream projects in the West and the Deepwater Gulf, and expanding our interstate pipeline system to meet customer requirements. As such, capital spending has increased and we have continued to increase EVA and returns. At the same time, we've been focused on improving our credit metrics and you can see, from this chart, we are focused on continuous improvement in credit.

The next slide, please, number 63 -- this graph represents segment profit after mark-to-market adjustment. As you can see, 2006 over 2007 is relatively flat and then moves up quite sharply in 2007. For the first time, we are providing some guidance on 2008 and again will be up sharply in 2008. I would just note that 2008 improvement is driven largely by, again, continued strong E&P production increases and that $7 price deck, which is steady with 2007. At the same time, a number of Midstream projects start to kick in as well as interstate gas pipeline projects, as well as that 2007 rate case that Phil had mentioned earlier. Again, as a result, we think that this path will create substantial value for shareholders.

The next slide, please, number 64 -- highlight again a few key points. Again, we are focused on driving and enabling sustainable growth in EVA and value for shareholders. We will maintain an adequate cash and liquidity cushion of at least $1 billion and in light of the high natural gas prices and high volatility, that's somewhat higher in today's markets than that $1 billion level. We'll continue to focus on improving our credit ratios and ratings, ultimately achieving investment-grade ratios. We will continue to reduce risk in our Power segment, and Bill focused on a number of multiyear deals that do just that while creating some value certainty. We remain opportunity-rich and we will continue to seize EVA-creating opportunities on a very disciplined basis.

With that, I will turn it to Steve.

Steve Malcolm - The Williams Companies - President, CEO

Thank you, Don.

Turning to the final slide, Slide 66, a couple summary points -- obviously, we're delighted with the growth generated in 2005. Again, recurring earnings up 150% over year-ago levels but it's not just about 2005 growth; you've heard clear evidence of our opportunity-rich environment that we enjoy. In the Piceance Basin, the fact that we will have 25 rigs working by year-end in the Deepwater Gulf of Mexico and the new projects that we've already captured -- the expansion in the West. Then, as Phil described, many of the expansions that we are focusing on to meet gas pipeline market demand. So, a very bright near-term future.

As well, we announced the first planned sale to Williams Partner. That will deliver growth capital while retaining asset control. I think as well, it's a longer-term focus -- the scope and scale of our growth opportunities continues to expand. Ralph talked about the Highlands opportunity and the Piceance. The Powder River continues to develop quite nicely. Alan mentioned the (indiscernible) list of growth opportunities in the Midstream area. Then finally, we are raising our earnings and cash guidance and expect the upward trend to make a sharper incline in 2008. With that, we will be happy to take your questions.