Williams Q4 and Full Year 2005 Earnings Conference Call Transcript (NYSE:WMB)
February 28, 2006
Steven J. Malcolm, Chairman, President and CEO
Alan Armstrong, SVP, Midstream Gathering and Processing
Ralph A. Hill, SVP Exploration and Production
Bill Hobbs, SVP Power
Phillip D. Wright, SVP Gas Pipeline
Don R. Chappel, SVP, CFO
Rick Gross, Lehman Brothers
Scott Soler, Morgan Stanley
Craig Shere, Calyon Securities
Faisel Khan, Citigroup
Maureen Howe, RBC Capital Markets
Carl Kirst, Credit Suisse
Sam Brothwell, Wachovia
Schnere Gershuni, UB Securities
Nick O’Grady, Sandel Asset Management
Wade Suki, Bank of America Securities
Jeff Burr, Matador Capital
Travis Campbell, Head of Investor Relations.
Thank you and good morning everybody and welcome to our Q4 earnings call today, thank you for your interest in the company. As always, today we’ll hear from Steve Malcolm, our Chairman, Don Chappel the CFO and the heads of our various business units Ralph Hill, Alan Armstrong, Phil Wright and Bill Hobbs. But before I turn it over to Steve, please note that all the slides that we’ll be talking from today are available on our website, Williams.com in a pdf format. Also, on slide number 2, forward looking statements details risk factors related to future outcomes, please review that slide and slide number 3 talks about oil and gas reserves disclaimer. It’s important 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 generally accepted accounting principles. Those schedules follow our presentation and we urge you to look at those slides. With that I’ll turn it over to Steve.
Steve Malcolm, Chairman, President and CEO.
Thanks Travis and welcome to our Q4 conference call. And as always thank you for your interest in our company. Looking at our first slide, that will be slide 5, at some of the major headlines for the year, first in 2005 we more than doubled our performance on the key financial measure, that being recurring income from continuing operations after marked market adjustments. That metric increased from about $190 million in 2004 to $513 million in 2005.
We also generated $1.45 billion of net cash from operations. Natural gas production was up significantly. In fact, domestic production was up 18%. We’ve taken steps to accelerate reserves development as evidenced by the fact that we’ve contracted for 10 rigs from over a 3 year term in the PMs basin. We had a successful launch of our MLP and as you know we previously announced that we have proposed to sell an approximate 25% interest on our 4 corners business to Williams partners LP. The purpose of this proposed transaction including price will be subject to the approval of the conflicts committee of the board of directors of the general partner of Williams partners LP. This proposal is still being considered and this is the only information regarding this proposed transaction that we will provide today.
Finally, we made significant progress in resolving some of the legacy issues with the settlements on gas information reporting, and ARISA.
Looking at slide 6, some of the details on the business unit results, E&P is growing, production reserves and profits, recurring results are up 122% from $251 million to $558 million US. Production up 18%, mostly through the drill bit. We recorded 277% reserves replacement with a 99% success rate. Total crude reserves at 3.6 trillion cubic feet. And as Ralph Hill will describe the continues to show great promise.
Midstream generated strong earnings despite the impact of two major hurricanes. Pullies performed admirably during these hurricanes.
We’re bringing new deep water volumes on line. We’re committing to expand our capacity in the rockeis as evidenced by our acquisition of TXP4 and the fact that we’re commenced construction of TXP5.
Gas pipeline customer demand continues to support significant growth. Some of the major projects that we have announced, parachute, Lidey, Potomac, Sentinel, Greasewood, Phil will talk about those in a few minutes. We set another delivery record on Transco with a 8.73 decatherm peak day on January 7th, 2005. And our rate case preparation has begun on Northwest Pipe and Transco. We would expect to file on Northwest Pipe on July 1st and on Transco on September 1st.
Finally, power is continued to reduce risk, had great success in executing additional mid-term deals and generated positive cash flow for the year.
Turning to slide 7, in terms of our guidance, through 2008, as we run through our presentation this morning you will hear that we will be growing recurring segment profit after mark-to-market adjustments from about $1.6 billion in 2005 to $2.3 billion in 2008. that number representing the midpoint of our range. And we are truly opportunity rich within all four of our business units. That we will be investing $5 billion in capital expenditures over the next 3 years so with the majority of that going to grow our E&P production. And we expect to increase segment profit nearly 50% by 2008 and will see continued improvement in our debt to cap ratio. With that, let me now turn the call over to Don Chappel.
Thanks Steve and good morning. I’ll quickly run through a summary of our Q4 and 2005 results and then turn it over to the business unit leaders for a deeper diver. I’ll come back later in the call to review our consolidated guidance and other matters.
Let’s take a look at slide 9, our financial results summary. And I’d note that income from continuing operations and net income; both include non-recurring items as well as mark-to-market effects. So I’ll focus my comment on the last line which is recurring income from continuing operations after mark-to-market adjustments. You can see for the fourth quarter we posted a result of $.26 per share as compared to $.09 in the prior year and for the full year $.86 as compared to $.35. I’m pleased with our Q4 and 2005 results, which are sharply improved from 2004, as well as in line with our previous guidance.
Recurring segment profit after mark to market adjustments for the quarter are 448 million, vs. 300 million in the prior year or up 50%. And that’s detailed on slide 77 in the appendix. And for the full year, segment profit after mark to market adjustment is at 1.578 billion, vs. 1.263 billion, or up 25% and that’s detailed on slide 78 in the appendix also.
Additionally we’re well positioned to seize the many extraordinary value creating opportunities that lie ahead. And we’re even more confident in our ability to achieve the goals that we have set forth and will set forth during this call today. I’d also note that our 2008 segment profit guidance after mark to market adjustment is up nearly 50% from 2005 levels.
Slide number 10 – I’ll now walk you through a calculation of recurring income from continuing operations just highlighting a few of the non-recurring items in the quarter. We have an accrual for regulatory and litigation contingencies, totally $78 million in the quarter or $96 million year to date. That affected principally the power segment. Impairments, losses and write offs related principally to two non-core investments and those were principally Longhorn and Oxsable. We had expense related to prior periods. During the fourth quarter, Transco recorded an expense related to prior periods an adjustment associated with the accounting and valuation corrections of certain inventory accounts. On a year to date basis this adjustment was offset by other items previously discussed.
And then finally, a gain on sale of assets relatively small for the quarter, somewhat larger on a year to date basis and we’ve detailed that on prior calls.
Total non-recurring items for the quarter totaled $167 million before taxes; the tax effect and an adjustment to our tax accounts reduced the adjustment by $20 million and the total of that is $168 million or $.28 a share. And again on a full year basis, $428 million or $.72 a share. Again, this includes the mark to market effects.
Number 11 – I’ll walk through the calculation of recurring income from continuing ops, after mark to market adjustments, really focusing on these mark to market adjustments which we think are important to better understanding our real earnings power.
Again, starting with the recurring income that we just calculated on the prior slide, we make some mark to market adjustments on our power segment, reversing forward unrealized mark to market gains totaling $70 million in the quarter, $172 million year to date and adding back realized gains for mark to market that was previously recorded, totaling $48 million for the quarter and $310 million on a full year basis. The net of that is a reduction in reported segment profit of $22 million after tax, $14 million effect on income as compared to an $85 million effect on a full year basis. Also, looking at the full year you can see that $85 million positive adjustment as compared to a $72 million negative adjustment in the prior year or a change after tax of $157 million. So again, I think it’s really necessary to look at our earnings power after these mark to market adjustments, given the very large swings.
Slide 12, focusing on Williams’ liquidity at year end 2005 and I’d like just to talk through this slide. Again at the end of the year we had cash and cash equivalents about $1.6 billion dollars. Other cash securities just over $100 million and then we had some special items and I’d like to note we had subsidiary and international cash, totaling $$240 million and customer margin deposits of $321 million, m uch as we deposit margin with other counter parties, other counter parties deposit margin with us and we could be require dto return that if prices were to change or if those customers would replace that cash with Letter of Credit; so it’s really not viewed as being available to us. So backing out that $561 million that is earmarked for customers or for subsidiaries, we have cash balance of $1.159 billion at the end of the year and available revolver capacity of $961 million or about $2.1 billion of liquidity.
With that, I’ll turn it over to Ralph.
Go to slide 14. I’m very pleased again to report a strong quarter for E&P. Our volumes continued to rapidly increase and our segment profit more than doubled. I want to thank particularly our very talented and dedicated workforce and employees for their relentless pursuit of increasing our production in a very safe and efficient manner while also continuing to add new opportunities for Williams and our shareholders. I hope when I have finished today and have shared results with you, you will agree that we continue to be one of the leaders in the E&P industry in production growth, cost efficiencies, reserve replacement and new opportunities.
Slide 15 – segment profit is up as we mentioned. Q4/Q4 175%, volumes increased 14%, net realized price increased 79% so a very strong quarter for us. Keep in mind we do have significant number of hedges that were out of the money that did impact Q4 earnings, but still have very strong earnings growth for the quarter.
Slide 16 – looking directly at the strong production growth of 18%, our domestic volumes continued to grow, 18% this year; our Q4 ’05 volumes averages 25% greater than the 2004 yearly average. So we continue to grow our volumes and as you know we predict our volumes continue to grow 15-20% growth this year and through our guidance period.
Slide 17 – Accomplishments and a current update. I’ll talk about each of these a little bit more. But just for headlines, domestic volume growth is up 18%; total volume 17%; reserve replacement – I have two slides on reserves, 277%; we added 34% new staff successfully to our E&P group so we’re able to go out and recruit new talent and also retain the talent we have to operate these assets. Our production continues to climb. We now have 2 rigs operating in the Barnett Shale and in the San Juan basin, which is a very mature basin; we’re still able to increase production by 4%. Our international group kicked in with 8% volume increase and also had record operating profit from the volume increase and the increased oil price. We now have 19 rigs operating in the Peonce, which includes a second H&P rig which is onsite and should spread this week and our Peonce island production reached 18 million a day. I’ll have some more information on each of these in a minute.
Slide 18 – Looking at Powder River, the Big George continues to drive this. It was up 74 million a day or 101% over a year ago. On a sequential basis volumes were up 9% or 11 million a day. The Big George growth in the fourth quarter vs. Q3 was up approximately 50 million a day. The wyedack was down about 11 million a day, so you can see the Big George was actually more than offset in the Wyedack decline. Williams and its partner represent about 43% of the Big George volumes in the Powder River. We expect to be able to continue to have this kind of growth. We are very encouraged in the growth in the Big George production; generally the coals are thicker, have higher gas content as we thought they were and they’re living up to their potential and are drilling this year like last year and for the foreseeable future is to target the Big George prolific area. Looking at ’06, 100% of our permits are in hand from the BOM or submitted; basically we have all our permits in hand for the majority of the year with a few permits needed from the BOM towards the end of the year, but we expect those will be given to us at any time. And our water management plans; water management’s part of the application to the BOM. We have those in place and we have 67% already approved and we expect to see the rest of those as the next few months move, as we move through the next few months.
Slide 19 – turning to Peonce production growth is up 88 million or 34% in the year; on a sequential basis up 5% or 17 million. Our volumes were down a little bit in the Q4 from what we thought they would be. We had some compressor maintenance issues, some interruptions on pipelines; a brief period of severe weather in early December. Those things all effected production slightly but still squeezed out 17 million a day growth and we expect those kinds of growth numbers to continue in the Peonce.
And as of march 1 we have 19 rigs operating in the Peonce. Those are divided into 4 gray wolf rigs, three cyclones, 9 neighbors, 1 that we are borrowing from an industry partner and 2 H&P rigs. We will add 8 more H&P rigs during this year that will take that number up to 27, but the loaner rig will go away at the end of March. So we’ll be in the 26 rig range by the end of the year; which essentially our target is 25-26 rigs. So we’ll be on target for our rigs. Even with the delay in delivery of the H&P rigs that experienced.
Slide 20 – looking at cost performance. Our LOE is $.36 per MCS. 3 year S&D costs is $.92 and our G&A is $.34 per MCS. We believe we had industry leading performance in these areas. Not enough industry data is out yet for me to give direct comparisons, but I do believe when the 2005 data shakes out and I review us vs. the industry comparisons with you, you’ll see it’s very favorable. For example, our 3 year S&D costs of $.92; that is below what the industry had on average and in our more direct competitive areas, using numbers from 2002 through 2004. So adding in 2005 costs which were higher, I expect that the industry’s S&D costs will go up significantly and ours is at the $.92 range. So I do believe we’ll compare very favorable in all these areas.
Slide 21 – On reserves. I’m very pleased to announce that reserves are up to 3.6 trillion cubic feet. Our domestic reserves are up 13.3% to 3.4 trillion cubic feet. Last 2 years we’ve grown 10.5%, this year we’re able to grow 13.3%, even from a larger base we’re starting from. Domestic reserve replacement was 277%; that’s one of the top numbers I’ve seen reported in the industry. Success rate: we drilled 1,629 wells, we had 1,617 successful wells. Again, for the 3rd or 4th year in a row, a 99% success rate. And we moved 603 BCF probable reserves to proved reserves and as you can see at the bottom of this slide, we continue to be able to move our probables to proved reserves the last 3 year we moved almost 1.5 trillion cubic feet of probable reserves to proved reserves. So as we talk about our probably reserves, we feel very strongly that those are the type of reserves you want to have and the type that can move into the proved category. In addition to moving this 1.5 TCF of probables to proveds the last 3 years, our proved developed producing percentage of our total proved reserves has increased from 43% to 49%. So we are not only moving probable to proved, we are also adding…we are not just adding we are moving more into the PDP side and have more revenue generating reserves as we move through each year of drilling program.
Slide 22 – is a reconciliation of getting to our 3.4 TCF of domestic pre-reserves. Just looking briefly from ’04 through ’05, we sold 11 BCF. We acquired a very modest range of 28 BCF. We produced 224 BCR. in addition and revision, total additions were actually 615 BCF and we had 12, a very minor level, 12 BCF of revisions. So the net number is 603 BCF. Total 3.4 TCF to the year end reserves. Also looking at sensitivities in our reserves, we believe the year end hub price used, as per the guidelines, was in the $10.80 range. If that price was cut in half our reserves would only decline by about 1.9% or about 60B, so, our reserves are not really that price sensitive. They are based on high return, long lived reserves, as you know. We are very proud of our reserve replacement ratio and just to stress approximately 99% of our reserves are audited by either for and the reserves underlying the Williams royalty trust is handled by Miller and Land so approximately 99% plus of our reserves are audited by outside firms.
Turning to the highlands project summary, I won’t go through the numbers on this table, but you do see that trail ridge is now been approved for 10 acre density. Redpoint already was 10 acre density. The point to make of this slide, these figures previously have not been included in our 3P reserves that we’ve talked about were 8.5Ts. we have now booked of the Highlands, 140 BCF of pre-reserves from the Highlands asset teams. So we have actually moved some of these reserves from this category, which really wasn’t even in our 3P reserves into a proved reserve category based on our drilling from 2004-5; primarily 2005. We expect to apply to 10-acre in the Island point at the appropriate time. Using 10 acre density for all of these projects would add substantially more reserves to our portfolio, but as we mentioned before we have not added that in there and just to stress, the vast majority of these potential reserves are not include in our 8.5TCF of 3P reserves.
Looking specifically at some of the wells drilled to date on slide 24, we have drilled as you can see 15 well in Ridge, 8 in Ryan Gulch, 6 in Alan Point and 2 in Red Point. We’re excited about what we’ve been able to accomplish. Our current production from this area is 18 million a day. We expect we have enough data now to know that there is a hydrocarbon system present. And we’re well along in our understanding of what can happen here and you’ll see some of these ranges, particularly in Ryan Gulch narrow as we continue to have experience.
For 2006 we’ll significantly ramp up our drilling program with 20 wells in ridge, 15 in Ryan Gulch and 9 at Alan Point for a total of 44 wells. Also in this area you must just for outside knowledge, you probably have seen a very amount of transaction which was in the Peonce basin area, which had a tremendous market value, we think, on that. So I think if you look at those kind of numbers that Petroleum was able to purchase, what they purchased and add that to some of our projects here, you can see that there’s a tremendous amount of value here for Williams here as we proceed through.
Slide 25 – We have other opportunities. I believe that a well established core capability of any organization in the ENP industry is also to be able to identify grass roots opportunities. Some of these opportunities are now at the stage where we’re positioned to just begin preliminary discussions of them with you. Looking at this slide, the purses in the peonce basin is a shell ridge prospect; it’s below the Williams fork. We’ve leased about 14,000 gross acres, have 100% working interest, 87.5% net, 10 year leasing term. We have another project pending in the Peonce basin on the Williams work project similar to what we do right now in all of our drilling in both the valley and the highlands. We are looking to finalize this hopefully in the near future, it will be 11,000 net acres and in 2006 we have a drill commitment. In the basin we have been able to lease about almost 40,000 continues gross and net acres; this again would be a mesa verd type gas sands clay. 100% working interest, 10 year lease, 87.5% net. And in the Paradox Basin which is a resource play more, the Ismay Group, Shell and Tye Gas Sandstones, we have 37,000 gross net acres leased, again 5 and 10 year terms on the leases, 100% working interest. All of these are in the infancy stage but I think it’s important to show you that we have been out doing other things and continue to add to our portfolio. As we get more information we’ll give you more when it’s appropriate. We do believe that they have material potential and they capitalize our strengths in non-conventional plays and they give more growth visibility to our current rich inventory of opportunities.
Slide 26 – we do believe we are a leader and I think these facts are proven out by this chart on US gas production growth, particularly through the drill bit. The left side of this slide you can see just ranked by total production, we were 16th in 2005, ranked by top 20 gas producers. If you look at production growth, we were 4th. But also I would mention that most of the people on this list of the top 20 US gas producers on the right side; did significant acquisitions in either late 2004 or throughout 2005. So on organic drill bit growth we are probably the industry leader. I think it’s just a testament to our portfolio we have that we can grow this kind and expect to continue this kind of growth for the guidance period that we’ve talked about.
Slide 27- Cash margin analysis. Similar to what I’ve shown before, representative of our 3 year POV and recall that our point of view at the top of this slide and now is there is a expense of $8.50 for ’06 and $7.00 for ’07 and ’08. still use that number minus fuel and shrink of about $.65 which includes transportation and fuel, minus a basis of about $.75 and the hedge loss which is again about $.75, you equate to this $5.75 realized margin. The current 3 year nymex as of February 24 was more in the $8.81 range. As of yesterday I think it dropped to the $8.59 range. So still, those prices are above the calculated strip that we were using which was $7.50. Even though there’s been some weakness in ’06 prices, ’07 and ’08 is actually staying above our forecast.
To reach the cash margin we deduct LOE, which is $.45 and of $.51 operating taxes $.51 and our G&A of about $.30 and we get cash margin of $3.98. so it is obviously a very profitable margin on a cash basis. The other way to look at it, you look at our 3 year S&D cost of $.92, we paid $.92 and we’re making $3.06 margin when you take the $3.98 minus $.92. So we’re making a tremendous margin on what we paid for. On our operating profit basis, you basically take the $3.98, subtract about $1.20-$1.30 DD&A and times our production and you see how we get into our operating profit guidance range. So again a very strong cash margin business and operating profit margin business, even with the recent decline in ’06 gas prices, we still have a very profitable business going forward.
Slide 28 – Our guidance. 2006 and 2007 did not change. We’ve added 2008. We still plan a very robust drilling program in 2008 that’s been added of about 1700 to 1800 wells similar to 2006 and 2007. The midpoint of our 2008 production is greater than 1 BCF a day so it’s a significant production growth during this period. Our comp at average growth rate over this three year period falls in the range of what I mentioned annual; our annual range is 15-20% and our compound average growth rage is in approximately the 16% range for this period. So we look to have a very strong production growth and operating profit growth during this period. Capital spending stays approximately the same in 2008 as in 2007, up slightly for potential new projects which won’t really add too much to production but we did up it some for that. As for an unhedged price assumption, you can see those at the bottom and I think it’s very key to look at our average San Juan Rockies price at the bottom. 2006 is currently above what the market is actually giving, due to the recent decline. 2007 and 2008 are below in the sense that the market is higher in 07 and 08 than what we have on this page as 609 and 610. on the 2006 basis, 732 is actually above what the market would currently give if it was priced out today.
Slide 29 – Key points, hopefully you will see that we are an industry leader in production growth, cost efficiency and eserve replacement. Our production increased 18%; we predict our production to be able to grow 15-20% through our guidance period. Our cost period to be beat some of the industry’s lowest and we will provide on our next call much more direct comparisons of our performance versus the industry. Our reserves did increase 13% and the reserve replacement rate was 277%. So our strategy remains to be on top and rapidly develop our premier inventory, stay on top of industry costs. We have not seen significant cost incease over the projections we’ve put in to our plan for 2006. there is cost pressure, however, so what we’re looking at is we believe we put the right numbers in there, we believe the numbers will be able to withstand the cost pressures, but as we move through the next three months we’ll have to understand if our costs will have to go up at all. Drilling rates are up slightly, while our completion costs are basically locked in so we don’t see completion costs as a major part of our portfolio, so we don’t see a tremendous pressure on our completion side. Drilling rates are probably up about 2-5%. Overall we don’t believe at this point that we need to do anything to our ranges for increase cost, but we’ll keep you posted. We’re doing everything we can to diligently manage our costs and we think we’ve done a great job. If you look at our record on how we’re doing that.
We’re also looking for new opportunities to start contributing and that’s mostly in highlands. As you know, we have about 140 BCF of reserves booked in the highlands now. We look for more of that to happen as we continue our drilling program this year. And we described 4 new opportunities that we will start to develop late this year and in 2007 and we hope to be able to talk more about those to you as we develop them.
And finally I would once again thank our work force for a tremendous amount of work, a great effort during the year and looking forward to their outstanding achievements for 2006.
I’ll now turn it over to Alan.
Thanks Ralph and good morning. Let’s go ahead and turn to slide 31 here.
We’re very happy with our 2005 recurring performance within midstream, especially when y9ou consider the 40% decline in Montbellevue , 3 major hurricanes and asset sales that were in excess of our expansion capital placed in service during the period. The $471 million was nearly $80 million above the midpoint of the range we provided at this time last year and near the top of the range we provided in November. So, needless to say we’re very pleased to repeat a record year with continued steady returns and strong cash flows from this business.
The year to year story even though it looks pretty simple here, $471 vs. $471, actually consisted of about $20 million lower NGL profits that were offset by higher fee based revenues. Compare that 40% decline in Montbellevue that I mentioned earlier, you have to realize the benefit that we enjoyed by having the geographic diversity of our western production offsetting what would represent the Montbellevue which is typically just a Gulf Cost but is the industry norm. so we’re pretty excited to have been able to overcome that.
Also during the period that $20 million lower was offset by higher fee based revenues as we’ve indicated to you in the past we were headed toward. So strategy continuing to deliver.
In the fourth quarter of ’05 we deliver $112 million. This was another good quarter, but was $39 million lower than the year ago blowout of $151 million and to really speak to this you have to realize our NGL profits were reduced by about $51 million quarter to quarter and we were able to offset this with lower O&M and some higher fee based revenues. So, all in all, very pleased with the year and very pleased with the way we performed in the fourth quarter to overcome what was some pretty good pressure on
Moving on to slide 33, Q4 and 2005 highlights.
A few points to make on this slide. First you can see that we had much less volatility in recurring profitability from quarter to quarter in ’05 there in the gold than we had in ’04 and in fact Q4 was just under the average for the last 2 years. So some very repeatable performance. Particularly when you consider the amount of external issues we had like the 3 major hurricanes that we took on.
Also we made great strides in positioning midstream for growth in the coming years as we established WPZ which currently enjoys the lowest yield in acceptor. We embarked on the construction of several significant expansions in our core growth basins and those are listed here; particular around Opal and in the deep water. And we embarked on the construction of several significant expansions in our core growth basins. An din the fourth quarter we were able to negotiate for the acquisition of the o-pal TXB4 trains at our o-pal complex and we enjoyed strong free cash flows from Triton, Goldfinger, which came on out of Devils Tower and just in the month of December, that was just starting up, we saw $2.5 million in incremental cash flow just for the month of December. So, some strong profitability.
Moving on to slide – on guidance here. This is a pretty simple story here of continued growth. This is
Moving on to slide here on the prospects that we’ve been showing. We continue to make great progress here on various growth projects that we’re pursuing. I don’t have enough time today to go into a detailed update of these prospects, but really the short version is that we moved several projects from the development and proposal stage that was on the left into the under negotiations basket and those of you that were able to attend the midstream tutorial back at the end of November, would remember this slide. You can see that we’re progressing some of these projects from the proposal stage into the negotiation stage. Also, a slight increase in the contracted and approved bucket here, again just reflecting the added o-pal TXP4 acquisition in there. So we continue to be very pleased with the amount of opportunity we’re seeing in the sector and we would expect to see that development and proposal stage continue to be filled in as new prospects come forward in all the areas that we’re operating.
Just a highlight moving on to the next slide here. This is the overland pass pipeline proposal and this is just a highlight. One of the prospects that we’re pursuing. We first publicly announced this project back on November 30 at our midstream tutorial. We continue to be excited about this project and are excited to tell you that this project continues to move forward and is really starting to take some shape. Surveying, engineering and ride away on this proposed 750 mile pipeline are all progressing and we continue to work toward an in-service date at the end of ’07 or early ’08.
As I stated back at our midstream tutorial, this project still represents the lowest cost alternative to flow the liquids from Wyoming into Conway, Kansas. And there will be relatively little horsepower required to move the product from the Wyoming area into Conway, so obviously that gives us a very low variable expense there. This low cost of transportation will result in a very strong reduction in the tariffs that we are currently paying to the Mapple system to clear our NGL’s into the market. And of course that lower tariff will flow right back to the profitability of the o-pal and echo springs facilities. So continue to be excited about this and a lot of great attributes for this project.
Moving on to the next slide, this summarizes here on the key points. We just slightly edged out last year in terms of record recurring annual profitability. You have to look pretty close to determine that but we certainly are pleased with the year we produced. Segment profit plus depreciation was $662 million, the MLP proceeds exceed4ed $78 million after the funding of Tahiti and various IPO fees. And we brought in $68 million in before tax assets. And we only spent about $115 million in capital during 2005. so midstream continues to produce tremendous free cash flows and we’re excited to be able to contribute in that way.
The spread between gas prices and MontBellevue liquids declined 40% from ’04 to ’05, yet our NGL margins only declined about 10%. And again, that really was attributed to the geographic diversity of our assets and so we’re very pleased with our ability to weather some of the volatility in those markets. And then finally we are forecasting very strong growth in several sectors of midstream and look forward to continuing to update you on the growth of those prospects.
And with that, I will turn it over to Phil Wright.
Thank you Alan. Slide 38 please. The gas pipeline segment again turned in solid profit and cash flow performance with recurring segment profits of $574 million. Q4 reported results include the impact of 2 non-recurring, non-cash adjustments, totaling $37 million, associated with the revalueing of certain natural gas inventory accounts. These Q4 charges partially offset the $49 million of non-recurring gains we reported throughout ’05 and will reduce full year reported earnings from $586 million to a recurring level of $574 million.
Lower year over year recurring results are due primarily to termination fo the Gray’s harbor contract, our northwest pipeline, higher operating expenses, partially offset by higher earnings from Gulf Stream.
Slide 39 – in addition to being another year of strong positive cash flow at gas pipes, our team delivered excellent results operationally and commercially. Operationally, we established a 3 day peak record on Transco and met all of our demand obligations in spite of 3 major hurricanes. On the commercial front it is expected that the central new jersey expansion project commence service on November 1 and we held successful open seasons on Transco to serve the northeast and greater Washington, D.C. areas via the Sentinel and Potomac expansions respectively. Sentinel, which will add firm capacity of about 250,000 decatherms a day is scheduled to be in service November of ’08. The Potomac expansion will add 165,000 decatherms a day of therm capacity and is slated for service in November of ’07. we files a certificate application for the previously announced Long Island expansion and I’m pleased with the progress we continue to make on that project. We owe a successful open season for the parachute lateral, which will connect production from the Peonce basin into a hub at Greasewood Colorado, the origin of another new lateral, connecting northwest customers to new production in the Rockies. Expected in services dates are January of ’07 for parachute and November of ’08 for greasewood.
Turning now to our profit, cash and capital guidance on slide 40. Noted in prior calls, during ’06 we have no major expansions, no rate cases coming into effect. As well, due to a change at and accounting policies, we’ll charge about 25-35 million dollars of pipeline integrity costs to expense that had been capitalized before the change and will have $20 million of higher interest costs on gulf stream, following the $850 million financing completed in ’05. So we expect ’06 segment profit to be lower but to rebound following rate cases on northwest, Transco and pine needle in ’07. We’re lowering our guidance in ’06 by $10 million to account for higher insurance premiums due to last year’s hurricanes and for development costs for the recently announced pacific connector pipeline project at northwest, which will be reserved and charged to income until the project is deemed viable, at which time the costs will be capitalized.
The only other material change on this slide is in our capital guidance for ’06 and ’07, predominantly due to the expansions I noted and which are summarized for you on the following slide, which is number 41.
We’ve increased our maintenance capital range in ’06 by $35 million to account for deferments from ’05 and changes in our hurricane repair assumptions. Last fall, we forecast these repairs to hit in ’05 and be reimbursed in ’06. Owing to contractor availability and weather difficulties, these are now expected to occur in the first half of ’06. We’ve also increased our cost estimate to a range of $65-$75 million, which we anticipate recovering from insurance. We’ve increased our ’07 maintenance capital guidance to advance work needed for pipeline integrity assessments that were slated for ’08. The ranges for expansion related expenditures have been increased now to include the parachute, sentinel and greasewood projects. This level of capital is well within our EBITDA and cash flow from operation projections and allows gas pipes to continue to generate positive free cash flow through the forecast period.
Slide 42 please. This map shows the excellent growth opportunities served by our pipelines. The projects in the shaded boxes have been recently announced but are currently not included in the capital guidance we discussed. Production area, mainline and mobile based sales expansion will enhance our ability to transport domestic production and imported LNG from gulf coast to markets along Transco. Depending on market interest, the mainline expansion could add up to 750,000 decatherms a day of therm transportation. We’re currently holding open seasons for these projects and both are targeted to be in service in ’08. We’re pleased with the improving situation at gulf stream, our joint venture system into Florida. Gulfstream’s conducting an open season to assess interest in a proposed compression based expansion to add about 200,000 decatherms a day of capacity with an inservice date anticipate in January of ’09. We’re very excited about joining with PG&E and Ford Chicago interview partners to pursue the pacific connector, a 250 mile pipeline tying Port Chicago’s proposed Jordan LNG terminal to northwest customers and the pacific gas transmission backbone system into California. Project completion is targeted for 2010. Also, we’ve recently announced an open season for incremental therm storage service from the Jackson prairie storage facility near shahales, Washington, where we’re one third owner. The project included in our guidance will provide capacity to service long term, seasonal and peak-day growth in the pacific northwest by November of ’08.
Slide 43 – Summing up, I’m please to say that by almost any measure, 2005 was another successful year. We continue to be a strong cash flow provider, deliver excellent results operationally and our successes continue in customer service as evidenced by number one rankings in the Masteon company survey in the regions served by northwest and Transco. Going forward our focus is on placing new expansions into service and preparing our rate cases. With that, I’ll turn it over to Bill Hobbs.
Thank you Phil. We’re now on slide 45. slide 45 takes our reported segment profit and then adjusts for non-recurring items such as litigation contingencies, impairments and then further adjust for the impacts of mark to market accounting which bring us to a Q/Q and a Y/Y improvement vs. 2004. Although a break even year for power, it was somewhat below our expectations coming into the year segment profit negative 257 and again we adjust for mark to market accounting, we adjust for working capital changes in UC power segment, standalone, CFFO of $127 million.
On slide 47 we have two changes to guidance, one is to adjust for the impact from mark to market and the other is we are raising our floor in 2007 to $50 million, they’ve given us a range of $50 million to $200 million largely on the strength of the new deals that we’ve done.
Slide 48 shows the success that we did have in ’05 and there’s a couple of key takeaways here. First of all, we were able to contract around each of our positions as well as our customer types, reflect a diverse group of utilities, banks, hedge funds and cooperatives.
Starting in 2006 on slide 49 and this slide does have a formatting error that we didn’t catch and will be fixed on our website, but we have had early success in 2006, primarily in the northeast. We have contracted for 500 megawatts of additional capacity sales for June 2006 through May 2009, with 2 utilities and as well we did our first sale to the retail aggregator in the west position of 175 megawatts that runs through the end of 2006.
Slide 50 shows basically on a bar chart format the success we’ve had in contracting for additional capacity throughout the guidance period. As you can see we still have additional megawatts left to sell, that provide the in the hourly markets but also the opportunity to enter into additional long term sales.
Slide 51 is a key slide, if you will look at 2006 to 2008, the guidance period, you’ll see that the hedge cash flows are extremely significant, especially compared to the merchant expectations that we have. And if you normalize our SG&A for 2006-2008 to reduce it for the non-recurring affect of 2005, you can see that we predict a very strong cash flow forecast even if you would back out the merchant revenues. However, we do see the market improving and we do believe that merchant revenues are very achievable.
Slide 52 walks us from 2005 recurring segment loss after mark to market and adjusts for the impacts of the new contracts that we have executed. Again, in 2005, high natural gas prices, mild weather, hurricanes and plant outages had a significant negative impact on our earnings. Although we do not forecast that for 2006, the new contracts have greatly mitigated that risk which gets us to our guidance range of $50-$150 million.
On slide 53 and in summary, again we did contribute a positive cash flow to the corporation on a standalone basis in 2005 despite very difficult conditions in 2005 we basically produced a breakeven year and significant improvement over 2004 levels. We do believe in 2006 the market is improving. We are executing contracts. It’s showing a lot of interest from our customers and increasing liquidity in the marketplace so we’re very optimistic that we’ll continue to have success in further contracts into the future and certainly we are looking at some deals that extend beyond 2010 although at this point it’s too early to indicate the possibility of success. We remain very focused on creating additional cash flow certainty and generating EBA and reducing the risk which is evident to the long term deals that we’re contracting for and as I’m indicated we are excited about our future in that we’re going to continue to be able to offer risk management services to our customers for years to come. With that I’ll turn it back to Don.
Thanks Bill. Let’s turn next to slide number 55. it summarizes our 2006 forecast guidance. Again segment profit before mark to market adjustment is largely unchanged from what we had provided last quarter and I would note that it includes $280 million of cost related to mark to market effects. We do adjust that out by the bottom of the slide and lastly and most importantly, diluted EPS on a recurring basis after mark to market we’re estimating in the range of $.78 to $1.03, up somewhat from 2006 levels and I think very importantly it positions us for 2007 a breakout year.
The next slide, number 56, this summarizes the business unit and consolidates segment profit guidance after mark to market adjustment. The guidance is largely unchanged from our 11/4 call and again I would not that 2008 that approximately $2.3 billion is up $700 million or above 45% from 2005.
Number 57, this slide summarizes business unit and consolidated Capex guidance. I’d note Alan and Phil previously described changes from prior guidance related principally to some timing rollover from 2005 to 2006 as well as new projects and certainly in the case of gas pipelines we would expect that those 2006 costs to the extent that they were maintenance related would be recoverable and our rate cases it would be filed in late ’06 and it would take effect in early ’07. and to the extent that they’re related to growth projects in either midstream or pipelines, those earnings would take hold as those projects go into service.
Number 58, we previously touched on segment profit. I’ll focus my comments on cash flow from operations. Again, 2006 cash flow from ops, at approximately $1.8 billion, up from $1.4 in 2005 and again by 2008 or forecast is more in the $2.4 billion range, an increase of $600 milion over ’06 or 33%. Finally, operating free cash flow is a negative number for ’06 as a result of very significant growth projects as well as the northwest pipeline replacement project. As you can see by 2007 that diminishes somewhat as that northwest pipeline replacement project and some other maintenance projects are completed. But still very substantial and driving substantial growth. Operating free cash flow is positive in ’07 and very positive in ’08 and I think we’re well positioned to continue to seize opportunities in our core businesses to create additional value.
Number 59, graphically depicts what we just talked about. As you can see cash flows are strong and growing quite rapidly and capex is expected to decline somewhat following 2006.
Number 60, this slide graphs our segment profit growth again with about $700 million of expected growth over 2005 by 2008, or just under 50%.
And then finally on slide number 61, just to hit a few key points, again we’ll continue to focus on driving sustainable growth in EBA and shareholder value. We’ll maintain adequate cash and liquidity of at least $1 billion to handle margin volatility as well as our capital needs. We’ll continuously strive to improve our credit ratios and ratings. Ultimately achieving investment grade ratios, even if that’s out ahead of us a few years. We’ll continue to reduce risk in the power segment and we’ll seize many of the terrific opportunities that we have ahead of us. With that I’ll turn it back to Steve.
Thank you Don. Briefly, I believe our story continues to revolve around four key points. We own and manage world class natural gas related businesses, we are opportunity rich in terms of our investment options, we are investing in a disciplined manner by virtue of the fact that we’ve embraced the EDA methodology and we believe that we are in the midst of an attractive commodity outlook for our businesses. We can certainly prosper in a $6-$8 gas price environment. With that, we will be happy to take your questions.
We’ll go first to Craig Shere with Calyon Securities.
Hi. A couple of questions. First Don or maybe the segment heads, can y’all provide what you see as maintenance capex numbers for each of your divisions and then a couple of quick follow ups after that.
Craig we’ll ask each of our segment heads to perhaps make a comment on that. Phil Wright’s prepared to kick that off.
Yes, if you would turn to slide number 41, at the top line there we have our normal maintenance and compliance capital investment detailed there. And I think as well we have in the appendix more information on capital. If you need a more detailed breakout of that, we’re prepared to do it but it gets kind of lengthy in slicing it up. As you can see the big ticket item there is the 2nd line, northwest pipeline 26” capacity replacement, which we’ve spoken about throughout the year in 2005 at $276 million in ’06 and a couple of million of cleanup in ’07.
And also if you will look in the appendix under what’s title dstrong free cash flow, I’m not sure what the slide number is there, but it is in the appendix…87, you can see there both historically and in our forecast what the maintenance capex looks like for midstream. It also has the well connex and to a certain degree our well connex are running in place capital. About 25-30 of that is what we think is necessary to keep production volumes level. So, but just the cliff notes on that, it runs about $30 million a year of maintenance capex and about $25-$30 of that Well Connex, with that Well Connex capital increasing a little bit the last ocuple of years, but we are getting increasing volumes from that.
I failed to reinforce a point that Don Chappel made earlier and that is with these projects in ’06 and ’07 for maintenance we do expect to be able to recover on those following our rate cases at northwest and Transco.
We generally define ours as capital required to keep our production flat. Our production’s gone up significantly. We expect to continue, but to keep our production flat at the levels we’re at now, we would estimate about $250-$300 million, probably closer to the higher end of that level to keep the volumes flat.
Great, thank you. And Ralph, what are prospects for new technology deployment or obtaining reasonably priced rigs to meaningfully accelerate the drilling schedule?
Well, we have accelerated quite a bit and we look for other opportunities, there are other companies we are talking to in addition to H&P about new technologies. Neighbors has a similar type of flex rig if you will, it’s not called flex rig, that we’re contracted actually for a couple of those rigs to come to use in early 2007. so we are doing things like that. And that’s the kind of new technology that we’re seeing right now. The top driven rigs, the closed mud-pits, the closed loop system on muds are much more efficient type rigs, so we are actively out seeking not only new arrangements with our existing drilling contractors, but possibly others. There are prospects there, at this point we’re at the range of the 25-26 by the end of this year, but we’re already in the process of looking to incerese that number for 2007 and beyond as we speak.
And last question, Bill what are prospects for hedging past 2010? And any comments on the capacity markets?
I think in general that still the utility markets are dealing in the 3-5 year range, but there are things that are occurring in the market for instance the Neptune line that’s being built in the northeast to take PG&M power to Long Island. There’s interest around that project because people will be signing up for 10 year capacity so I think they’re starting to look for supply arrangement in that kind of timeframe. We’re certainly talking to all of our utility customers, even the ones we have existing relationship with to kind of blend and extend the contracts that we have to … the rules are changing very quickly and you mentioned capacity markets but they are changing and so we’re always working with our customers to try to make sure the contractual items fit their needs and ours. Our view of capacity markets is you’re probably going to see PG&M and ISO occur in 2007 and in California is schedule to be 2007 but could slip into 2008. I will say this though, the contracts that we’re currently entering into, these deal I’m referring to, do have a capacity feature to them. So even though there’s not a defined market in all regions, customers are recognizing the need to contract for capacity.
We’ll go next to Schnere Gershuni with UBS Securities.
Good morning guys. I just have 3 quick questions here. The first question is, when do you expect to update the 2P and 3P portion of your reserves?
As we move through this process we’re thinking the next call we should be able to do that, which his in May. It may be more like mid year but we’re in the process of doing that now. The push was to finish our proved rserves and get through that process, which we’ve now done and we’ll start to turn our attention to updating the 3P by mid year.
Okay. One other quick question just about reserves and this relates to the Peonce on slide 24 you have the expected estimated ultimate recovery ranges for the wells, I don’t have your previous numbers, but did you increase the range for both Ridge and Alan point?
I thought we tightened the range, I don’t recall us increasing the range but what we’re trying to do as we drill more in each of those areas we are tightening the range. I think that should be fairly close to what we had previously but I’ll find the old slide and look at that for you.
And just switch me over to power for one second. I realize you’re just talking now about some of the opportunities that you had in 2010 in the PGM market, but if we can switch to the western site, specifically California, has anything changed on the macro front that would change your outlook for I guess the confidence that you have for extending contracts beyond 2010?
Not really. There’s talks of a new power facility being built, but California basically needs about 2,000 megawatts a year just to keep pace with the economic growth that its seeing. So I think we’ll certainly reach a point, I have said before and I think it’s probably more in 2007 and 2008, when utilities will looking at contracts as far as 2015. But, there’s nothing fundamentally that’s changed in any way to change our bullish view of that market longer term.
Thank you very much.
We’ll go next to Nick O’Grady with Sandel Asset Management.
Hi guys, can you hear me? Okay, question is on as you may know, one of your peers western gas resources has talked about planning different ways to maximize value. I’m curious if you guys are looking at the same types of tings, specifically midstream, E&P, other ways to find value?
Nick, I’m not aware of anything new that’s come out of Western on that. We’ll take a look at that if you’d like to call IR.
We’ll go next to Carl Kirst with Credit Suisse.
Good morning everybody. A couple of quick questions on the E&P side, Ralph is it fair to say with the new H&P rigs that are going to be coming down that you guys are still very focused on bringing in new and possibles to the proved category in ’06? Meaning that should we still be looking for a double digit growth in reserves in 2006, I guess partially it looked like F&D this year, ’05, was about 25. Is that roughly the range you’re looking for for 2006 as well?
Well, I don’t think I can predict that at this time. But we are all about trying to move our probables over to proved in addition to increasing our production. Costs are up slightly this year; we will have to weight that vs. the amount of reserves that we add. We are also going into some new areas that don’t initially add a lot of reserves. We are also adding a significant amount of facilities this year, meaning 2006, that we started in 2005 to allow us to move all this gas for the period late ’06 and beyond. So in general, our goal is to move as much over as possible each year and to continue our path of increasing our reserves while also increasing production but, I don’t think we’ve ever predicted nor will I predict this time what we think, but we have a great track record and we look to continue our track record.
Fair enough. One follow up just looking at the highlands, trying to get a sense of timing for when you might be looking at 10 acre spacing on Ryan Gulch as well. Could you at least even bucket it into an ’06 or ’07 timeframe?
Not yet. And Ryan Gulch, we’ve drilled the least amount of wells and as you can see the range on EURs is the widest range and there’s still a question will that even go to 10-acre spacing or stay at 40 or stay at 20? We just don’t know enough yet, but we are planning to drill 15 wells there this year and we’ll have a much better idea by the end of this year on what we think that can be ultimately. Ryan gulch is just too early to tell if it stays at 40s, goes to 20s or could ultimately be at 10s. just we need to do much more drilling, much more experience with that area first.
Great, that’s helpful and just lastly, Don, can you give us if there was ever a timeframe ever established for the four corners deal, was there any timing ever talked about?
Carl, as Steve mentioned earlier in the call we are unable to discuss that transaction, so I’ll respectfully refuse to answer. So you’ll just have to stay tuned.
Fair enough, thank a lot guys.
We’ll go next to Faisel Khan, with Citigroup.
Good morning. If I could just walk through your guidance for ’06 that roughly $1.86 billion in operating income, the high end for ’06. I look at your ’05 recurring number after mark to market adjustment, it’s roughly $1.58 billion. If I look at the high end of your EPS guidance of a $1.03 compared to $.86, can you just walk me through what’s going on below the operating income line to net income that’s been causing a slower net income growth over ’05 to ’06 vs. your operating income growth?
Faisel, I don’t know what I have to add other than what is on the slide that was provided earlier. I can certainly walk you through that but I think we’ve pretty well laid out what the components are.
What about this: in the four the quarter of ’05 your interest expense goes up by about $10 million. Can you talk about what’s causing that? Is it short term rates and then your investing income line also goes the other way by about, is a loss of about $21 million.
I think during 2005 we did expand our credit facilities and certainly they were in place in the fourth quarter but we expanded our credit facilities to have more capacity to support our hedging program as well as provide additional liquidity for general corporate purposes. We’re also anticipating a couple of financings related to our gas pipeline business to get the capital structure at the optimal level as we approach a rate case. so perhaps those factors are a couple of components of that.
Okay, fair enough.
Faisel, I might point you to slide 82 that does detail some of the components of interest expense.
There’s amortization and of another debt expense numbers…do you have those types of expenses in 2005?
We had some similar expense in 2005 but I also think we detailed that in our prior call, the 11/4 call, so there should be a schedule that’s similar to the one that you’re looking at.
Okay, fair enough. On the proved reserves side, you talked about the domestic reserves moved to roughly 3.4Ts but there’s an incremental 200Ds that came the international segment. Can you talk about what’s going on over there?
Similar to last year we had slightly over 200 BCF and we’ve had that for quite a while and that’s through our ownership in AVCO Argentina and some other related properties, down primarily in Argentina. Last year as we mentioned our domestic reserves were 3 TCFs, meaning year end 2004, and that number has moved to 3.4 TCF, year end 2005. Reserves did go up international, but not a significant amount, so adding that slightly over 200 BCF to the reserves ’04 and ’05 get us to the 3.6Ts. so it’s our ownership primarily in our Argentina properties.
And you said your reserves aren’t that price sensitive, meaning the higher commodity prices at year end didn’t really affect any positive revisions or moving any more reserves. Some reserves did become more economic as a result of the higher prices, is that true?
Yes, that is true. We cut the price in half just to do some sensitives. And less than 2% of our reserves would actually go away.
And sort of put the pipeline company…the rate cases that you’re going to have ongoing over the next 1-2 years, are you attributing any success of those rate cases in your guidance?
I’m sorry are we what?
Attributing any success in those rate cases in your guidance? Are you assuming that your rates go up on your pipeline system?
By the full amount or…?
That has been our guidance for 2007. There’s an assumption that we file these rate cases late ’06 and they go into effect during the first quarter of 2007 and that is included in the guidance for gas pipelines.
Okay thank you very much.
unidentified speaker from Williams
If I could respond to an earlier question. We did raise the region Alan point. Previously the reserves were 1.4BCF and we raised that to 1.6. So to the other caller, that is correct, we did raise the upper end of that range, kept lowering the and raised the upper end.
We’ll go next to Scott Soler with Morgan Stanley.
Hi, good morning. I have 2 kind of questions. One is just in terms of earnings guidance in ’06 again following up on Faisel’s question, I wanted to ask two specific points aside from interest expenses that, Don on the tax rate the same on the effective tax rate? I think most people tend to model 36-37%. Is that higher now? And then also, on the hedges on slide 84, the hedges are at a lower price than what was previously mentioned on the same production for ’06 and ’07 and I was curious why did that change? Then I’ve got one question on E&P.
The hedges, what we did is the NYMEX price is the same but we tried to note here, please note that it’s base locations not Nymex. What we’re trying to give you now and we thin k it’s a better model is actually a fixed price at the basin. So what I’m giving you is the actual basin price…
I’m sorry Ralph, I see that now.
We did footnote that but they didn’t change in the sense of…it’s easier if you do the basin price vs. the Nymex price.
Scott on your tax rate question we have a slide in the appendix that details that, slide number 83. We’re using a 39% effective tax rate and a cash tax of 5-10% for the guidance period.
Okay. And I guess on E&P I want to ask an update question from when we chatted a month ago. I guess that just the general comment and I don’t know what you can answer, on slide 26 it shows and our numbers too when we look at all the E&P companies in north America, Williams is probably the most successful E&P company, excluding acquisitions in growing reserves in production due to drill bit. Yet if I put on that slide my net asset value and backed into the value of the E&P business, we think the market’s better than the reserves as we roll four reserves at $1.25. which would put you at the lower range of valuation with the best E&P business in the industry. I guess what I’m trying to understand is how generally are you guys discussing potentially closing the gap? And would it come through acceleration of drilling vs. share buy back or third other options that you might have. Is there any updated thinking on that from when we met a little over a month ago?
Scott, this is Don I’ll just make a comment and if perhaps Steve wants to follow it. I think our strategy is to sharply accelerate our production. I think Ralph and his team have a plan to do that really moving from 15 or so rigs in the peonce at the end of 2005 to somewhere in the 26-27 range by the end of 2006 and kind of going into 2007 with that 26-27 and perhaps more. And I think as we’re able to get our E&P production up to a level that’s optimal, certainly our earnings will come up sharply. And we would expect to receive a more full valuation. And with that I don’t know if Steve has any…
I would just add to that, I think as Ralph Hill has described, we intend to accelerate our drilling in the peonce and probably most of the, the new information will be around the peonce highlands area and just how attractive that oportunity’s going to be. So I think proving up and validating just how good the highlands are and how strong those step outs are to the extent that we can capture additional step outs would certainly I think further drive value in the E&P sector. We clearly understand that some investors believe it’s possible to create some short term burst of value through modifications of our company structure and to your point, where I think you were going Scott, we have analyzed along with many other options whether we could create long term shareholder value through an initial public offering or partial or complete spinoff of our E&P business. As I’ve said in the past, our current assessment is that that value creation, if any, from such actions would only be short term in nature and wouldn’t be in the best interests of our shareholders. Having said that I think we’ve demonstrated a willingness to make structural changes when we believe that they support sustainable value creation over the long term and then I think the evidence of that is the fact that we did go forward and create the MLP. So we will continue to manage our company to create sustainable long term value for our shareholders to the extent that that objective would lead us to evaluate our structure, we will consider all of the various options. But, we believe, based on our assessment thus far that we can create the greatest long term value from our E&P business and for our shareholders by maintaining the integrated natural gas strategy.
Okay. Thanks for addressing it Steve.
We’ll go next to Maureen Howe with RBC.
Thanks very much. A couple of my questions have been answered but, I just wanted to return to the expansions of the pipelines and so I was just wondering when you hold an open season and then proceed onto a regulatory filing, what term are you looking for in terms of contractual arrangements from the shippers?
Let me speak to recent experience as an example. We’re striving to maintain this level in our future expansions as well but if you look at the long island expansion we had 20 year contracts behind that.
So is that sort of an average that you would look at or is that what you would expect to get.
That is what we expect to get and what we have gotten in the past although I’ll be quick to say that there’s a lot of pressure on that level of term in the marketplace. Competitors have been offering lower terms and we continue to deal with that. It’s a situation by situation negotiation.
And before you proceed to regulatory filing, what is it that you lok for in terms of percentage of contractual arrangements? Is there a threshold in terms of covering fixed costs or is there a percentage in terms of available throughput on the line?
Each discrete expansion project is designed after the open season. We understand clearly what the market wants in the way of firm capacity. We design the facilities tailored to fit that. And, present those costs to the customer and that is in fact the rate that will be negotiated into the precedent agreement, signed with the customer. And so when we go to certification we have essentially these projects fully put to bed.
When you say that, when you go to certification, you have the project signed up to provide what you’re looking for in terms of a threshold return on equity?
And then I was just wondering Don, in terms of the investment grade credit rating, I guess you get asked this almost every conference call but, is…what’s your current thinking and outlook in terms of – in your mind – realizing that who knows where the credit rating agencies are…but in Williams’ mind, how long to do you think it will be before you reach the target ratios that will give you an investment grade credit rating?
Maureen I think that’s a great question and it’s one that I probably can’t answer. But, we are and have been reinvesting in the business for a couple of reasons. We think that drives more value to shareholders than paying down debt. Then also I think investment grade rating will be more a function of our coverage of fixed charges then debt to Cap ratio type metric. As well, I think the ratings agencies still are on kind of a wait and see basis on power. I think their view has improved quite a lot over the last couple of years but I think they’ll be looking forward to our beginning to hedge beyond 2010. So having said all that, I think it’s just really indeterminable but it’s certainly out there a couple of years or more.
You seem to be signing contractual arrangements on the power side and with pipeline shippers, so what would you characterize as the biggest issues and problems faced by Williams, due to a lack of an investment grade credit rating? Is it just the cost of debt or is it reducing your flexibility?
I think we’re operating quite nicely with the credit rating that we currently have. Surely the market is giving us much more credit than the ratings agencies. So we look at really where our bonds trade and how the banks deal with us much more so than our credit ratings. So given that, we have a great deal of flexibility. We have great access to capital and reasonable costs. I think what the investment grade will give us in an incrementally better cost, more flexibility and ability to maintain lower cash balances as well as in terms of post less margin and less liquidity requirements on hedges and even on some new long term contracts, particularly in the power sector. So I think overall it’ll be a great help to us, but one that is not top of the list at this point.
Okay that’s great. And just one final question. It’s sort of just a small question for Bill. It has to do with…we’ve normally seen in the past anyways, a graph that’s put into the presentation that shows the $400 million and totaling fixed charges and then your contractual commitments that goes out a number of years and I guess shows the crossover point. I don’t see that in this presentation and I don’t see it in the appendix. Is this something that might be posted on the website? Are you familiar with the graph I’m…?
The appendix we are now just reporting through the guidance period so I guess that’s the change you’re referring to. It is basically the same schedules we showed before, it’s now just for the guidance period.
Okay, that’s great. Thank you very much.
The next question comes from Sam Brothwell with Wachovia.
Hi. I know we’re getting close to the curtain here but I was just going to ask if maybe you could elaborate a little bit more. You touched on the interest expense question. Is it fair to say that you’re probably going to see the maximum amount of pressure on that line item this year, given that the capex is so high? I guess the other thing is, thinking about collateral posting requirements as gas prices move around, can you comment on that at all, this year relative to last year?
Sure, Sam. Yes I would expect that 2006 would likely be some more pressured in light of both the hedges we have in place and our need to have substantial liquidity to support those hedges as well as the fact that we do have capital spending in front of us that’s in excess of our operating cash flow so we do have a need to fund some of that capital spending. So we’re maintaining perhaps more cash than we would otherwise as well as a credit facility that’s a big bigger than we would, absent both the hedges and the high level of spending that’s in front of us.
Okay, thanks a lot.
We’ll go next to Wade Suki with Bank of America Securities.
Good morning everyone. Just a couple of quick questions for you. I might have missed it, but did you mention what the domestic percentage was a year end?
Yes, I did. The domestic PUD percentage is now 41% and the PDP is…I’m sorry, the domestic PUD percentage is 51% and the PDP is 49%.
Was it 55% last year or something like that?
Last year the PUD wqs 55%, correct and the year before that was 57%.
Fantastic. And again, I think you mentioned it Ralph, 12Bs and net positive revisions domestically?
They were actually net negative, slight negative. So the…on slide 22 where you see the 603BCF of plus 603, add/revision, there was 615 of adds and 12 of revisions, just slight negative revisions. And there were very miscellaneous.
And then costs incurred, could you walk through that reconciliation with the exploration development acquisition that kind of thing?
On which one now? I’m sorry?
Just your costs incurred on the E&P business, broken out exploration, development on acquisition. Do you have that available?
I’m not…say it one more time?
Capital expenditures, costs incurred?
What we spent last year, you mean?
Yea, if you had it broken out between development, acquisitions, unproved leaseholds, all that good stuff that you usually disclose in the K.
I do have that. I don’t have it in front of me. Primarily the vast majority was for development drilling with approximately 30-35 million for facilities and the small acquisition in the Barnett which is about I think also about 40 million. We’ll break that out in the K, but the vast majority was for drilling last year.
That’s what I figured. Perfect. Thank you so much.
Next to Jeff Burr at Matador Capital.
Good morning. Just to follow up on the discussion about the shareholder value and E&P. you know, first of all you guys have done a phenomenal job in the peonce and E&P and yet there’s still this very significant valuation gap. So, kind of a several part question. You guys have done a great job, what will going from 15 rigs to 26- or 27…which will be a great accomplishment, but how will that change the valuation gap that exists now and if that valuation gap does in fact persist and its something you feel is best not addressed with and IPO or partial spinout of the E&P business, why is there not perhaps a stronger consideration of a share buyback where you can, you know, buy your own reserves at a huge discount to similarly valued assets?
Jeff, I think the point about what might drive value I think is around quantifying in more certain terms what the peonce highlands opportunity might be and I think that’s why we think it’s premature to take steps on doing anything with the E&P business, that’s one reason. As well, Jeff, I really don’t think I have anything more to offer on the issue of structural changes that we might take. I think I’ve been very clear that we have evaluated those options with our board, with investment bankers, and again, all things considered, don’t believe that it makes sense today. But I’m not suggesting that that’s the final answer. We will continue to be open minded about that topic. We’ll continue to evaluate it often and that represents our current thinking. In terms of the share buyback, we’ve talked about the fact that as we look at how we want to make the best use of the capital and cash we have available we think that most of the…the best way to grow shareholder value today is by investing in these extraordinary E&P projects. We will continue to evaluate all of the options both from a structural standpoint and how we best use our cash.
And Don I don’t know if you’d want to add anything?
Steve, I’ll just add and Jeff, I kind of look ahead about 18 months or so. Again by mid 2007 we’re drilling with 27 or more rigs in the peonce as well as drilling in all of our other areas. We’ll have increased visibility around the Highlands, perhaps opportunities to accelerate drilling there. There are 2 pipelines we will have had rate cases, we’ll have new projects both in midstream and gas pipelines go into service. We’ll have more time for the MLP to provide us with some benefits and the whole picture, if you fast forward about 18 months in terms of earnings, cash flows and prospects is a pretty bright picture. And I think we see a lot of value creation, much of . To get something like that we would have a pretty severe setback on credit and the markets would be closed to us.
Just as a little bit of a follow up and I’m not trying to be argumentative here. We’re ecstatic about the job you guys are doing, excited about the next couple of years. I guess Steve, what would be helpful, or Don, as you’ve looked at the option of a partial spinoff or an IPO of E&P. I mean, that does not seem like it would prevent you guys on an operational basis from being able to essentially operate in the same manner you have been. You know, the integrated way that you’ve been talking about. It just simply would create a vehicle for those who want to invest in a pure play to do so. So what am I missing there in terms of why an IPO or partial spinoff of E&P would prevent you guys on a day to day operational basis…how would that prevent you from continuing to operate the way you are now?
I’ll just mention a couple of considerations, one is credit. We have a substantial amount of debt. If we were to hive off some of those cash flows from the E&P business we would have to load that E&P business with a substantial amount of debt, which would put it in a fairly weak position for an E&P company. So we really look at both the parent company as well as this E&P company that we just described as being weaker than the combined company would be. And I think that would cause some considerable valuation and opportunity issues as well as the costs of governance and the way the governance issues, as well as the opportunities that Steve described here that we think are just now emerging. We think that’ll be much more valuable in the future than they are today. So, I think that, along with the fact that we’re not currently drilling up the reserves at a pace that is optimal. I think we’re moving as fast as can be expected moving from 1 rig in 2003 in the peonce to 10 in 2004 and 15 in 2005 to 27 by late 2006. I think we’ll substantially close the gap along with the other steps that we’re taking. So I’d encourage a little bit of patience there.
Well, we love what you’re doing. We’re excited about the future, we probably just respectfully just disagree a little bit on the cap structure side, but that’s what makes a market. Thanks for the answers guys.
We’ll go next to Rick Gross with Lehman Brothers.
Good morning. I’d like to ask a little bit about the Peonce and the infrastructure spending that you’re going to possibly do on expanding the gathering and processing facilities. We’ve seen in the local news out there in Colorado that you’re filed to increase the plant capacity from 3 to maybe 6 up to 800 million a day. I’m just curious as to if that plan is recognized in your current capex, either in E&P or if it’s over in the midstream business. And what type of rig count you’d need? By my own calculation you’d need well over 35 rigs to build your own equity production, which historically has been the feed into those plants, to 800 million a day. Can you flesh around what’s imbedded in the outlook as far as increasing the plant size and the infrastructure our there in the Peonce. I guess the current production’s over the plant capacity of roughly 300 right now.
Rick, the capital is included in our guidance for the facilities we need. Essentially what we see is basically we’ll be getting to those kinds of levels, at least our guidance levels, with the 25 rig program, once that’s up by the end of this year and cranking through. We can reconcile the difference between 25 and 35 later, but basically our 25 rig program and running it full speed, getting some efficiencies on both our days’ drilling, our completion, lack of rig moves, because we can stay on the same pad longer and those kind of things. So, essentially, yes, the capital’s included in our guidance for plan expansions and it is based on primarily 25 rig program.
From a standpoint of firming up the plant size and the fact that you’re going to feed it with principally equity gas, is the full 800 in by the end of the forecast period, ’08, end of ’08?
Rick I think it is. I don’t recall directly so I’ll say yes I think and we can get back to you on that. And there is some third party gas that we’ll be feeding into the plant.
Is it very substantial?
Well, I don’t know what substantial definition is. But it’s…it’s a good level, but not near what we will be putting into it obviously. So it’s hard to say. We’re also negotiating for some of the third parties still to come in. so I’ll just kind of leave it at that.
Okay, thank you.
We’ll take our final question of the day from Dave Foley with Crowe Creek Asset Management.
Good morning. Just one quick question for you. You guys have, or its my understanding, that APCO Argentina just had a pretty significant find down in Southern Argentina and I was wondering if you could comment on that.
Not yet. APCO will have its 10K filed I believe within 2 weeks. I know that one of our partners in the field has sent some information out on that. I think they filed earlier. But they have had some good successes down in the southern part of Argentina.
Okay. Thank you very much.
We are standing by with no further questions at this time. I would like to turn the conference back for any closing or additional comments.
Thanks for your patience. I appreciate your support and look forward to speaking with you next time. Thank you.
This does conclude today’s conference. We do thank you very much for your participation. You may disconnect at this time.
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