Kinder Morgan, Inc. (KMI) Q3 2008 Earnings Report, Transcript and Summary

Good morning. My name is Ann, and I will be your conference operator today. At this time I would like to welcome everyone to the El Paso Corporation Third Quarter 2008 Earnings Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks there will be a question-and-answer session. [Operator Instructions]. I’d now turn the call over to Mr. Bruce Connery.

Good morning and thank you for joining our call. In just a moment I will turn this call over to Doug Foshee, our President and Chief Executive Officer. Others with us this morning who will be participating in the call are Mark Leland, our CFO; Jim Yardley, President of the Pipeline Group and Brent Smolik, President of El Paso Exploration and Production. Throughout this call we’ll be referring to slides that are available on our website at elpaso.com. This morning we issued a press release and filed with the SEC an 8-K and is also on our website. During the call we’ll include certain forward-looking statements and projections. The Company has made every reasonable effort to ensure that the information and assumptions on which these statements and projections are based are current, reasonable and complete. However, a variety of factors could cause actual results to differ materially from the statements and projections expressed in this call. Those factors are identified under the cautionary statement regarding forward-looking statements section of our earnings press release, as well as in other SEC filings and you should refer to them. The Company assumes no obligation to publicly update or revise any forward-looking statements made during this conference call or any other forward-looking statements made by the Company, whether as a result of new information, future events or otherwise. Please note that during the call we will be using non-GAAP numbers such as EBIT and EBITDA, and we have included a reconciliation of all non-GAAP numbers in appendix of our presentation. Now I will turn the call over to Doug.

Thank you, Bruce and good morning. I would like to frame this morning’s presentation by outlining for you how we view the current environment for businesses and how recent events have changed both our outlook and our plans and the content choices and tradeoffs we have made in order to position El Paso not only to weather the current environment but to do so in a way that still allows us to achieve our longer term objectives to grow our two core businesses. The combination of a precipitous drop in oil and gas prices and the more recent closure for our practical purposes of the public capital market that caused us along with the rest of our industry to rethink prior plans. In our case these events have caused us to accelerate our normal planning process, which would have had us presenting a new long range plan to our Board in December. As is evidenced by our release last night on our capital spending plans for 2009, we have already presented and had approved the capital spending portion of our plan for 2009. As you might imagine this plan is significantly different from our view of 2009 several months ago. As we put this plan together we were guided by a few key objectives. First, ensure our ability to fund our businesses in the worst of economic circumstances. Second, preserve the growth attributable to our backlog of pipeline projects, which we believe is the best in the business. Third, preserve our ability to grow our E&P business longer term by not taking actions that impair the high quality inventory that Brent and his team have built over the last two years. And fourth, preserve the profitability that we worked so hard to create over the last five years by tightening our corporate belt. In crafting our plan that meets these objectives, we believe that we have some real strength to help differentiate us and allow us to move through this current environment and create long term value for our shareholders. A significant amount of our revenue and profits come from a pipeline that has very little exposure to commodity price links and because of the nature and duration of our contract is largely protected from near term changes in throughput. We have a track record in our pipeline business of bringing in capital projects on time and on budget. The volatility in our E&P business is largely mitigated in 2009 by a hedge portfolio that protects around two-thirds of our revenue and prices of at least $9 for GAAP and $110 for oil. In fact, we have a sensitivity for ‘09 of only around $50 million for a dollar change in gas and $20 million for a $10 change in oil. Also we have substantial discretion in the capital spending for E&P business and it can be accomplished in a manner that doesn’t negatively impact our long term growth potential or our substantial inventory of projects. Since most of our E&P properties are El Paso operated and are characterized by very high working interest, we can control our activity levels to respond to changes in the market environment to the greatest possible degree. And finally, for a lack of better description with regard to the current capital markets environment as we say here in Texas, this ain’t our first rodeo. We have experience, engaged and talented professionals that have been through much tougher environments than this one relative to our own company in the past six years. So, we know how to operate our company in an environment where capitals constrain and speed, flexibility and contingency are key. The result of this is that we have plan that preserves, impact all of our pipeline growth pipeline, reduces capital spending in the near in E&P, retains virtually all of our E&P opportunity inventory, holds volumes in E&P basically flat year-over-year, retains the ability to flex our E&P spending still further in conditions worsen. Creates better long term returns in E&P as service and materials cost come down in the future to meet lower commodity. And, we expect that these actions will allow us to meet our debt maturities at mid year 2009 without accessing capital markets should they not reopen even in an environment of lower commodity prices. With that as a preamble let me spend just a few minutes talking about the quarter and then I will turn it over to Mark. In spite of dealing with lots of headwinds in our business, we had a great quarter. Reported earnings of $0.58 were up 190% over last year, more importantly adjusted earnings of $0.35 is a 58% improvement over 2007. EBIT was up 82% over 2007 and in spite of significant capital spending increases, interest expense was down versus 2007. All of this in spite of the effects of hurricanes Gustav and Ike on both business units as well as the corporate office here in Houston. And while we’ll have lingering effect of both storms in our businesses during Q4, we still expect to earn around a $1.25 for the year, our six consecutive years of improvements in earnings. With those brief comments on the quarter I’ll turn it over to Mark and come back at the end to wrap up.

Thank you, Doug and good morning everybody. I’m starting on Slide #8 titled financial results. Once again the company generated very strong earnings in cash flow this quarter. We are reporting adjusted earnings per share of $0.35 compared to $0.22 for the third quarter of last year. I’ll cover the adjustments in a minute. Reported earnings per share is $0.58 with net income of $445 million. Adjusted EBITDA was a $1.248 billion up 50% from the same period last year. Adjusted EBITDA includes over $280 million in mark-to- market gains and other special items and excluding those items adjusted EBITDA was up 18% compared to last year. Growth and earnings this quarter is driven by strong realized gas prices which were up $1.80 per Mcf to $8.92 per Mcf. Interest expense was $221 million again this quarter, which is down from $228 million in the third quarter last year. The items impacting earnings this quarter are highlighted on Slide #9. As we previously discussed for 2008, we’re only adjusting for significant mark-to- market items and legacy matters in our non-core or discontinued up businesses. We’re not adjusting for the impact of hurricane or the unique items in either of our core business units. The first item is the $63 million pretax or $0.05 per share mark- to-market gain from the change in fair value of legacy power trading contracts in the marketing sector. I’ll give more color on the PJM basis in a couple of slides by the last quarter. The second significant item impacting the quarter’s results is the $12 million or $0.01 per share loss associated with legacy indemnification related to the sale of ammonia facility. The third item is the $14 million pretax or $0.01 per share gain associated with the change in fair value production puts and calls in the marketing segment eased to head E&P cash flows. The remaining transactions in the marketing segment relate to oil and gas hedges that we entered when we closed the Medicine Bow transaction in 2005. We’ve done all of our 2008 and forward hedging for oil and gas production in the E&P segments and some of those hedges have not been designated for hedge accounts. So, the final adjustment relates to that $215 million mark-to-market adjustment or $0.18 per share associated with gains in the E&P segments due to lower oil and gas prices at quarter end. This amount is net of the million dollar in the current quarter settlements. So, accounting for these items brings adjusted EPS to $0.35 per share. Slide #10 highlights our business unit contribution. On a combined basis our core pipeline and E&P businesses generated $1.98 billion of EBITDA and adjusted EBITDA of $1.73 billion. Adjusted EBITDA is calculated with our 50% interest in Citrus and 49% interest in Four Star on a proportional basis and as you remember there is no debt on Four Star. Marketing reported an EBITDA gain of $82 million, which I’ll provide more detail in a minute. Power EBITDA was at $6 million loss due to foreign exchange movements and corporate EBITDA was at $1 million due primarily to litigation accruals. There’s a chart in the appendix that gives pro forma details for the adjustment EBITDA calculations. Now, I’m turning to cash flow on Slide #11. For the first three quarters of this year, cash flow before working capital changes was just under $2.3 billion up $694 million or 44% and cash flow from continuing operations was $2.51 billion compared to a $1.493 billion this time last year. CapEx through September this year is a $1.905 billion and we spent $352 million on the acquisition of our 50% interest in Gulf LNG and some producing property in the Rockies. Also so far this year we completed the E&P property sales as well as two sales of more international power plants and received $671 million in cash proceeds. So far this year we have cash flow -- we’re cash flow positive by over $300 million taking into consideration a strong operating cash flow and asset sales. Slide #12 details earnings for the marketing segment this quarter. The bulk of what goes on the marketing segment is related to the roll off of our non-core legacy trading book. For the quarter we realized an EBIT gain of $14 million due to the change in fair value production related derivatives compared to last year gain of $15 million. The gain was primarily driven by mark-to-market gains on 2008 oil callers used to hedge Medicine Bow acquisition which we closed in ‘05. In the other category of marketing positions, the gas book was up $7 million primarily due to higher interest rates this quarter and we realized the gain of $63 million in the power book mostly due to the narrowing of the PJM basis and I’ll give more color on this in the next slide. So, in total marketing segment realized the gain of $82 million this quarter. Slide #13 chronicles the mark-to-market earnings impact and quarterly cash settlements of our long dated PJM basis position. We showed this slide last quarter and the point here is that well a PJM basis contract is treated as a level three derivative contract valued on a quarterly basis and given its long dated nature and illiquid trading point is subject to fairly large mark-to-market earnings swings. Quarterly cash impact that was really pretty low like this quarter which was only a $7 million cash out compared to $63 million gain. Slide #14 summarizes our 2008 hedge program for October and forward. In short the balance of our ‘08 program is 42 TBtu with an average floor of $7.93 and an average ceiling just over $10. On the oil side we have 100,000 barrels of oil hedge with an average floor and ceiling of around $80. We have a very outstanding hedge position for 2009, which is summarized on slide #15. The ‘09 natural gas hedges have an average floor of just over $9 million on a 176 TBtu and an average ceiling of just over $15 on a 151 TBtu. On the oil and other liquid side we have swap selling 3.4 million barrels at an average price of about $110. In oil about 70% of our domestic gas and 60% of our domestic oil production is hedged. For 2009, hedge program is in the money by about $500 million with multiple aerated counterparties all of which are in our E&P company credit facility. These hedge positions will contribute significantly to our cash flow stability and liquidity in 2009. Now, for what many of you have been focused on and that’s the status of our liquidity, which is summarized on Slide #16. First, we had $1.9 billion in liquidity at the end of the quarter, a $1.2 billion of which is in cash and approximately $700 million is available on our revolving credit facility. The picture is pretty much the same at the end of October. Supporting our liquidity we have $2.5 billion in revolving credit facilities that don’t mature until 2012. And we have $1 billion in LC facility that expire in 2009 and 2011, which is somewhat inline with the reduction of our LC needs as the trading book rolls off. We have a diverse group of 31 banks supporting our facilities. Only Lehman has failed to fund and the potential impact of them not funding the future is about $27 million dollars and we are not including that 27 in our liquidity numbers. Our credit facilities have two primary covenants. Debt-to-EBITDA and EBITDA-to-fixed charges, the Debt-to-EBITDA covenant can’t exceed 5.25 times and for the 12 months ended September of this year that ratio stand at 3.4 times leaving over billion dollars of EBITDA cushion. EBITDA-to-fixed charges were 3.1 time growth and 2.0 time covenant for the same time period. As you can see on Slide #17, we have about a $1 billion in debt maturity by the end of second quarter 2009 and in 2010 we only have $251 million in maturities, which matches up very well with our pipeline expansion CapEx, which is heaviest in 2010. And finally, Slide #18 highlights our plan and outlook for the balance of 2008 and 2009 which I think is quite good. With substantial reduction in commodity prices and the impact in shut-in production from Hurricane Ike, we expect 2008 earnings to be around $1.25. We’ve already started to flow discretionary capital spending in 2008. We last targeted ‘08 CapEx of $3.8 billion and now we are targeting $3.5. Our 2009 capital program is being pared down to $3 billion with a $1.7 billion spent on the pipeline and $1.3 at E&P segment. We plan to meet our 2009 maturity primarily to CapEx reductions and other actions including taking partners on pipeline projects, which we’ve highlighted before and some previously planned non-core asset sales. Our plan does not conflate us having to access capital markets until the second half of ‘09. And as we have proven time and time again over the last several years, we will be opportunistic in the capital market. Finally, we have multiple levers to pull, to meet further liquidity challenges to dig this. Additional CapEx reductions, secured financings with our solid stable earnings asset base, additional non-core asset sales, and taking partners on growth projects. So, I feel pretty good about our position of where we stand for 2009. So, with that I will turn it over to Jim for an update on the pipeline.

Thanks Mark, and good morning. Third quarter was a successful, blocking and tackling quarter to pipelines. We continue to deliver consistent financial results throughput grew in spite of hurricanes, the economic slowdown, and a generally cooler summer. And we made very meaningful progress on our significant backlog of highly attractive expansion projects that will generate substantial long-term growth. During the quarter, three more expansions were placed into service. On Slide #21, I will summarize our financial results. Third quarter EBIT before minority interest is 285 million, up 4% in third quarter of ‘07 and year-to-date up 2%. EBIT less minority interest was essentially flat. In the quarter we continue to see increased revenues from expansions, higher throughputs, and capacity sales offset by increased O&M from higher labor cost and additional maintenance required mostly on TGP and EPNG. Also, the hurricanes had an unfavorable impact of approximate $12 million in the quarter. In addition to EBIT, we also show adjusted EBITDA for a 50% interest in Citrus. We think this better reflects the earnings power of our pipelines over $1.3 billion year-to-date. Capital expenditure year-to-date are higher than 2007 and are on plan .For the year we expect total CapEx to be approximate $1.7 billion. On Slide #22, throughput continues to increase up 5% versus 2007. This growth is on top of annual increases of 6% to 7% in each of 2006 and 2007. As we’ve said on prior calls, this multiyear growth is approximately double the rate of total US gas demand growth over the last three years. So, this is good evidence that our pipes are in the most attractive markets and supply basins in the country. Some of the increase is demand driven particularly in Florida and California, but more of it is supply drive particularly out of the Rockies. The increase was despite a significantly cooler summer in both the Northeast and Southeast about 14% fewer cooling degree days. Also, despite the hurricanes’ impact on volume total to Gulf of Mexico. Somewhat surprisingly we have not seen any impact on throughput from the economic slowdown including among our industrial customers. Gas used by steel plants and fertilizer plants in particular were strong in the third quarter. Paper plants usage was essentially flat. Remember the changes in throughput have only a very minor impact on our earnings because our revenue stream is mostly derived from capacity payments that are independent of changes and throughput for gas prices. So, as Doug said, our pipeline business is well positioned to whether the economic downturn and a decline in gas demand should that occur. On Slide #23, just a quick review of the hurricanes’ impact on our TGP system in the Gulf. We had some damage on our pipelines, pipes either severed or displaced. Also, as you can see from the map, several producer on platform connect the TGP either toppled or were significantly damaged. A very preliminary estimates to repair or abandon our facilities in the range of 80 to $120 million. We have over 500 a day shut in, which is about 25% of TGP’s pre-hurricane volume out of the Gulf. But the revenue impact from this lower volume is nil. Importantly through all this we have been able to meet all the needs of our market area customers. The next two slides talk to our good progress on executing on our growth backlog. First on Slide #24, we’ve now placed in service five new growth projects this year that are now earning revenue. These 2008 projects are centered in either the Rockies or the Southeast. All of the El Paso managed projects have been placed in service essentially on budget. The large remaining project to be completed this year is our high plants pipeline that will increase deliverability along the front range of Colorado for both residential home meeting and for power generation. High plains involve the installation of 140 miles of 24 and 30 inch pipe and it’s our largest construction project this year. It’s on budget and expected to be completed by the end of November. We also show here our projects to go in service in 2009, It’s a noteworthy list in that it represents a relatively light construction load relative to the past and is also small relative to the capital associated with our larger projects to go in service in 2010, and beyond, and these other projects are shown on the next slide. Slide #25, this is a breakdown of our backlog. For your reference we update it quarterly. This represents our committed backlog. We’ve committed to go forward with these projects and our customers, by executing long-term contracts to support this capital in turn are committed to us. It’s a very attractive backlog. It obviously provides us with significant growth for the next several years. It has attractive profitability. We expect the ratio of CapEx to run rate EBITDA to be approximately seven times. We continue to manage the CapEx risk and de-risk the projects. All the pipe for the larger projects has been ordered and on most of the projects, we’ve hired the installation contractors. Since our last quarterly call, we have seen no change in our capital forecast to complete these projects. On one smallish project, the work expansion, we’ve upsized it by $15 million to accommodate a customer that has increased its long-term volume and revenue commitment. A few specifics on progress during the quarter on some of our largest projects in the backlog. First of all, on Ruby, PG&E, our largest shipper received a favorable proposed decision from an Administrative Law Judge in California regarding PG&E’s contract with Ruby. Next the California Public Utilities Commission will review PG&E’s request for approval of the contract, and this may occur soon. Separately on Ruby, we continue to work with our three installation contractors on project planning, and refining the route. We expect to submit our FERC certificate application on Ruby shortly after the turn of the year. On FGT Phase 8 in Florida, we submitted last week our FERC application, which is a major milestone. We also are close to finalizing unit price contracts with three contractors to install the pipe in Florida. Under a unit price contract, unlike a time and materials contract, the contractor is paid a set fee per foot of pipeline laid. So the contractor assumes both productivity and weather risks. Once finalized, these arrangements will substantially de-risk this project. Finally, on our LNG-related projects, about half the pipe has now been delivered to Savannah for our Elba Express Pipeline project in Georgia. Pipeline construction will start next spring, Also under a unit price contract, Elba Express will be our largest construction project next year, 100 miles of 36 inch and 42-inch pipe. On our Elba III expansion, construction of the new tank is well under way, with six of the 14 rings of the outer tank complete, and we have now modified the slip to accommodate the larger LNG shifts. Finally at Gulf LNG in Pascagoula, tiles are being driven to support the construction on the first tank, dredging of the marine berth is complete, and as you recall, both the Elba expansion and the Gulf LNG project being constructed under fixed price EPC contracts, which materially reduces our risk there. So, all this is to say, we are continuing to execute on what we feel is the most attractive growth backlog in the business. On Slide #26, in summary, on the pipes, despite the distractions around us, we have our heads down, and are executing on our long term strategy and plans. We are obviously paying a lot of attention to costs, and we continue on track to achieve our 2008, earnings target. And with that I will turn it over to Brent.

Thanks, Jim. Good morning, everyone. I am going to start on Slide #28. From earnings perspective, E&P had a good quarter. EBIT was up sharply from a year ago. Much of that is due to higher commodity prices, and then our realized prices were about $80 per M on gas, and about almost $22 for a barrel of oil above the same period last year, and the $15 million mark-to-market gain on hedges that Mark mentioned. Although we had some positives in the third quarter, our aggregate production was below our expectations. Last call I said we were working hard to increase production from the Peoples Energy properties. The good news is we did just that. Now those properties are actually ahead of plan. Another positive note, the Central division, which includes our Arklatex operation continue to perform well and we have grown that division six of the eight last quarters on a performance basis. Unfortunately, the hurricanes reduced third quarter production by about 41 million a day. Mostly in Gulf of Mexico, and we had a shortfall in a couple of our Texas gulf programs in the quarter. Operationally, we made important progress in our Haynesville and Cotton Valley programs and I’ll review those in a few minutes. During the quarter, we also advanced the development in our exploratory projects in Brazil. Now turning to Page 29 titled hurricane impact, like Ike, while Ike was clearly the storm that had the greatest impact, we had four storms this year that created delays or shut-ins in South Texas, the Gulf of Mexico, and the East Texas, North Louisiana area. As you know, we issued a press release a few weeks ago stating we had a total of about 95 million a day of Gulf of Mexico production shut in. About 80 million equivalents per day is still waiting on downstream repairs on the High Island and the Stingray system. We expect to recover 25 million per day by the end of November with the repair of the Stingray system in about 55 million per day will come on in late to mid December with the restoration of the high up system. That leaves about 15 million per day shut in on our two platforms in Eugene Island area. They were more heavily damaged and we’re still in the process of determining the cost of repairing those facilities, and deciding whether or not to complete the repairs. And our early repair cost estimate is about 30 to $35 million, which we would expect to spend in 2008 and 2009. On Page 30, we have the financial and operational results for the quarter and for the year-to-date. As I mentioned earlier, earnings and EBITDA were strong for the quarter, and even without the $215 million mark-to-market gain, we still had a very solid increase in EBIT and EBITDA over the last year of 41% and 21% respectively. The 430 million of CapEx and acquisition dollars in the third quarter is actually lower than we previously contemplated, and by year end we now expect to spend about $1.8 billion, which is about $100 million less than we previously planned to spend. Turning to Slide 31 for a review of third quarter production, on the right side of the page are the volumes as reported, and on the left side are the pro forma volumes. The third quarter 2007-08 pro forma number reflects the adjustment from volumes of the properties that were sold in the first quarter, and then we assume that we owned the Peoples properties for all of 2007. The third quarter 2008 VAR has also been adjusted up, to include 41 million per day of lost hurricane volumes. On this basis, the Gulf is about flat, and the onshore divisions are up about a 1% sequentially, and up about 8% from Q3 2007. On an as reported basis, we produced 793 million a day in the third quarter. We had good growth in the Central division, which is where we are devoting much of our capital domestically, and we were flat to up slightly in our Western and TGC divisions. The Gulf of Mexico was down largely due to the shut -ins and Hurricane Ike. The Texas Gulf Coast came in below our expectations, and there are some pluses and minuses in that division. On the last call, I discussed that we started the year behind due to a combination of the slow start in our drilling program and poor results from wells drilled last year by Peoples, prior to closing the acquisition. We have also been disappointed with some of our legacy Yewah [ph] and Wilcox extension, and exploration wells this year, and we have moved capital away from those programs in the second half of this year, and our 2009 capital plan. On a positive note, we successfully grown the Peoples Energy production volumes, and across E&P, we are up from about 60 million a day, to over 100 million a day since the beginning of the year. And our October volumes are actually ahead of where we expected to be, when we put together our plan last December. And most of that growth has come from the South Texas division. In response to lower gas prices and the tougher capital markets, we have begun to reduce our CapEx in all divisions beginning in late Q3. In Q4 TGC will shift from 12 to about 8 rigs, Arklatex will decrease from the planned 10 to 8 rigs, and then we will drop one Altamont rig in Utah, and one rig in the Gulf. In total, we will likely drill about 10 less wells this year, which allow us a negative impact on Q4 and a very slight impact on the full volume guidance. So, for the year including Four Star, we are now expecting to wind up in a range of 815 to 825 today, which reflects the loss of full year average of about 30 million per day for the year due to hurricanes as well as the slow down in our capital program. Turning to cash cost on slide l#32, there is a few moving parts in this quarter. We were negatively impacted by hurricane cause in the gulf and an incremental work over activity in the Altamont field, but the Altamont field was designed to focus on increasing more volumes in a period of very high low prices, we were well above $100 for the quarter year. G&A benefited from a legal judgment we received in the quarter and while we still believe that the focus on managing these costs is an advantage for us especially be so in a declining commodity price environment, so the key massage I want to take from this slide is, our noble run rate for LOE and G&A is about a $1.50 per M and production taxes were about $0.50 for the quarter but remember that varies widely with the commodity prices. On slide #33, we have an update for our Cotton Valley horizontal and Haynesville programs in the Arklatex. In the Cotton Valley trend we fill four horizontal wells this year, with two currently producing and two currently drilling. And while we’re still in the early stage of this program we’re very pleased with the results to-date. We have been drilling these wells for roughly $6 to $7 million with five frack stages and we have seen initial production rates in the 4 to 7 million per day range. We expect to spread two more wells in 2008 and continue advancing the development of that program in 2009. In the Haynesville, we completed two wells and we have a third well drilling and we still may spud one more well before year end. We’ve got a tremendous amount of price and the experience as a company in Arklatex but remember the Miller was our first Haynesville shale well. We had some problems with a couple frack stages on the well, and although not as good as we hoped the well came in above 4 million a day, and is still producing above 3 million cubic feet equivalent per day. We took those learnings from the Miller well and we applied those to the Travis Lynch, in this well we had 10 frack stages versus 7 in the Miller well. And we changed the frack design significantly with better growth results and additional producing rates over 8 million cubic feet a day. So, we are still very early in the play, but we are learning fast. Regarding a couple of other pilot programs, we received 180 acre infill order for the Raton Basin CBM program in the Mexico and we are going to hearing in Utah for the Altamont oil field, where we will also seek regulatory approval to infill to 4 wells per section. Both of those improvements will enable us to add significant long life, lower risk inventory to our total. If you turn if you turn to Slide #34, I will give you a quick Brazil update. The development program at Camarupim or Bia, continues to move very quickly. Petrobras has completed and is testing the first of four development wells, and the pipeline to the field is nearly complete. We are also very close to finalizing the unitization and the other commercial agreements and Petrobras still expects to have first production in the first quarter of 2009. Under El Paso operated PinaAna inter project, we are also very please to receive the first significant environmental approvals from IBAMA, the environmental regulatory agency, during the quarter, and that is called the terms of reference. That is a key milestone in the PinaAna development. Going forward we plan to slow the pace of development on this project. First, we have several additional regulatory approvals that we need to obtain. Second, since we own 100% of the project, we have the option to manage the pace of spin, and we think it is prudent to do so, because we believe that with we can improve the economics by going slower, taking advantage of softening service and supply costs, and hopefully realizing higher prices for the crude. And third, the current credit Tele markets it also support a revised development schedule. On an exploratory drilling front Petrobras has not ye announced the progress on our Petrobras-operated Copaiba well. That’s located in BM-CAL-5 block, which is south of our PinaAna field or on our Petrobras operated top well it’s drilling in the ES-5 block, which is the same block as Bia, or the Camarupim block. And I don’t want to get too far ahead of our partners there, but the results are pretty exciting. We are about to flow test or production test the Copaiba well, and we are encouraged enough with the drilling results for logs, that we are continuing to drill on the Tat well. So, we will have more good news I think on those wells soon. We are very pleased with the early results, and we will have a lot more to discuss in the exploratory wells. We remain excited about the total potential of our exploratory portfolio in Brazil, and with the success on those projects, we could add meaningfully to our international reserves. And even in a capital constrained world, Brazil continues to be very a good option for us with very good near term cash flow from our Bia project next year, and then long-term growth coming from PinaAna, and the balance of our exploration acreage. Down page 35 as Mark said, we are planning for about $1.3 billion CapEx program next year, which is roughly 30% below the 2008 program. We are still finalizing the details, but here is the rationale driving our capital allocation. We are still focused on larger scale, lower risk repeatable programs, that offer solid economics, and provide more certain cash flows for next year. We made significant progress this year in areas like the Haynesville, the Cotton Valley and the Niobrara Shale, but we will have a large future inventory, and we will further optimize our horizontal drilling and completion techniques next year. Near term we will temper the CapEx allocated to the higher risk programs, such as TGC and the Gulf of Mexico, and as a result, both of those areas will see volumes decline in 2009. So, on balance we will focus our drilling on higher ROP areas so we will be trading off less near-term volume growth for a higher predictability and longer term results growth. In 2009, what we expect is for total production to be roughly flat with 2008, so that mean the growth and the volumes and from Camarupim, will offset declines in our domestic Gulf of Mexico TGC programs. Also we have lower beta programs that generates more predictable cash flows. Unfortunately, we have the discretion in our E&P capital program which can be accomplished for the manner that doesn’t negatively impact our long term inventory. Since we operate most of the properties, as Doug said and since we generally have a very high percentage ownership we can shift our activity levels to respond to the changes in the market environment. And finally, in closing on slide #36 will come with the quarter but it time to switch gears in terms of our capital allocation. In the fourth quarter of ‘08 in the 2009, capital flow downs will provide consistent cash flow we want and we will still have a deep inventory that is largely held by existing production. And 1.3 billion of CapEx production will be roughly flat with 2008, given that we still hurricane volumes shut in during the fourth quarter, and near-term we are shifting to higher ROP programs. We are preserving our drilling inventory and our organizational capability, so when the markets still open back up, we will have the opportunity and the flexibility to shift our E&P focus back to growth. So, then I will now turn back to Doug for closing comments.

Thanks, Brent, and let me wrap up this morning. Recent events have conspired to hurt our share price and our investors. Just a few months ago, we were trading at our six-year high, and just a few weeks ago, we were close to our five year low. Thirteen primary factors drove this dramatic change. First, the near-term drop in commodity prices, and fears that US and possibly a worldwide recession, could mean that these lower prices sustain themselves. Second, the near total closure of public capital markets more recently across every industry sector, and third, the recent reports of significant cost overruns on pipeline projects operated by others in the industry. The combination of these events has led to a change in people’s views of the value, and even the attainability of growth in our sector. In the case of El Paso, I believe that this has meant that our $8 billion backlog of growth projects in the pipe, which was our largest strategic asset six months ago, has more recently been perceived by some, certainly not by us, as a strategic liability, as people assess our ability to bring that backlog to fruition, both in terms of our execution capabilities, and in terms of our ability to fund that growth. We believe that the current market actually plays to our strengths in a relative sense. First, we have a track record of building infrastructure projects and bringing them in on time and on budget, and that continues to be borne out in our execution this year. Second, we have constructed a backlog of pipeline projects that allocates risks in a way that we think is both prudent and unique among our peers. Third, having an E&P business where virtually all of our capital spending is discretionary, means that we can use this to our advantage in the near term, cutting back now and having a flexibility to continue to shape this capital spend, to both ensure our ability to fund the total Company’s. plans, and at the same time preserve the inventory in our E&P portfolio. This is also prudent from a pure E&P standpoint as we are currently in that period where prices have affected our revenue line dramatically, but service costs which are always sticky on the way down haven’t yet come down commensurately. We can do all this and still preserve our profitability in the near term, as a result of a substantial hedge portfolio for oil and gas, and in the longer term, as those pipeline growth projects over time, add $1.2 billion year in EBITDA, to a pipeline business that today generates about $1.8 billion in total, all underpinned by long-term contracts. And finally, we have a work force that is engaged and committed to our success, as was evidenced by our most recent employee survey. In that survey, which we conduct every two years, 96% of our employees participated, and they told us that they understand our strategy, and that they are committed to it. In each of the 16 categories measured, we scored above the energy industry norm and above the high performance industry norm used for comparative purposes by the third party serve provider. So as a group, we are engaged. We have recent relevant experience in dealing with these kind of environments we have a plan to deal with the current environment, and finally, we intend to do that while at the same time preserving our long-term value creation objectives. With that, we will turn it over to your questions this morning.

[Operator Instructions]. Our first question comes from the line of Michael Sedoy from Diamondback Capital. Your line is open.

Doug, good morning can you please update us what’s your source regarding potential separation of the pipeline business from E&P?

I’m sorry could you repeat the question.

Yeah could you us update on your source related to potential separation of the pipeline business from E&P business?

Okay, thank you. That is some thing that is in our company sort of always on the table as a possibility. I would say we don’t have any current plans to do that, and right now don’t see the value proposition for our company associated with doing that today.

Okay, thank you.

Your next question comes from the line of Rebecca Followill from Tudor Pickering & Holt. Your line is open.

Good morning. Can you guys talk a little bit on your allocation of capital between E&P and pipes and is it driven by the high allocation of pipes versus E&P, is that driven by the return you see in that business, or the financial obligations you have to build those pipes?

Well, I would say Rebecca, we can’t ignore the current realities of the capital market, and so we have an $8 billion portfolio of pipeline projects that are 60 or 80 year kind of investments, in terms of the duration of those assets. And we do as a matter of corporate priority protect those and put those at sort of the highest part of the pecking order, from a capital allocation standpoint. And in addition to that, of course, we have made commitments to our customers. We have made commitments to contractors. We have made commitments to pipe companies, and those kinds of things. And by the way, we are very happy with that. We happen to have the flexibility, we believe, to respond to two things, one is the significant drop in commodity prices that hasn’t yet, but we believe will lead to a commensurate drop in the cost of services related to our E&P business, and we have a portfolio in E&P that lends itself to be in flexible in since that we have very high working interest we operate of properties we have interest in. So, we can flex our E&P capital spend up and down to meet those market needs, which we think is a prudent thing to do, frankly whether or not we had an $8 billion pipeline backlog, but it is certainly prudent to do in that circumstance, and we can do it without sacrificing significant profitability because of the fact that so much of our earnings comes from a pipeline business, that doesn’t have throughput or near-term throughput, or commodity price volatility.

In the event that the capital markets remain closed, and we know it won’t last forever, but let’s say it last through the third quarter of next year, what else could be cut? Where do you have flexibility to further cut CapEx?

Well I would say at the extreme, virtually all of our E&P capital, maybe with the exception of some of the international capital for 2009 is discretionary. In addition to that, though, we have a lot of other options besides just CapEx cuts, and we have a whole raft of things that we would consider to protect the business, and keep it intact.

Thank you. I am sorry. One final question, on your list of four year priorities for E&P, you mentioned the Niobrara and the Pierre in the New Albany. I thought all those areas were still kind of in the pilot program, so I was a little surprised to see those on there. Have those moved up on the priority list?

Rebecca, this is Brent. Think of them as extending the pilots. If the activity levels that we have in there for next year, they look like extensions of f this year’s pilot programs. We continue to learn about drilling techniques and costs.

Okay, thank you.

Your next question comes from the line of Nathan Judge from Atlantic Equities. Your line is open.

Good morning. I wanted to clarify as far as production was concerned for 2009. You said that your production will be flat. Is that based upon a production level this year that includes or excludes hurricane impacts, i.e., would it be the 815 level?

815 to 825, yes, flat to that.

So, what kind of reserve change would this type of capital, 1.3 billion capital deployment result in generally?

In terms of the existing reserves, Nathan, or next year’s capital?

Next year’s capital?

Shouldn’t change much. I mean on the margin we are spending less capital for the numerator, but on the denominator we still have some significant resource type plays in Altamont and Raton, and some of the Arklatex areas that have the ability to book some PUD. If anything, it takes a little less pressure off F&D.

And, the other thing I would say, as we roll into 2009, we should start to get the benefit in a way that we haven’t yet from the international stuff. So, for example Bia coming on stream in the first quarter of 2009, as well as we haven’t really booked any, obvious any of the exploratory reserves to speak of.

Just back to production then, if we were to look at perhaps a more normalized level, or an adjusted level for production of including, or adding back into the hurricane into full year production, and we also adjust full year ‘09 number production before the production from Bia, it looks as if $1.3 billion is not a level that would sustain your production on a 2010 basis?

We are still in that same neighborhood we have been all along for along for maintenance capital, if you define it by keeping production flat. We have said pretty consistently 1.2 to depending on commodity prices and therefore costs 1.3. And so, we are kind of in that same neighborhood of, we think, of staying flat at about 1.3 billion.

And I would say the one other thing I would add is we have not presumed in that 1.3 a significant reduction in oil field services costs. So, to the extent there is some upside there, we could benefit from that. We believe it is going happen. We don’t have enough confidence to forecast it yet.

And then just as a follow-on question, two, one of the questions asked earlier with regard to splitting the company, could you just, Mr. Foshee, could you just talk about generally about what change that would not be, before when the stock was higher, I think there was more focus perhaps on splitting the company and today there seems to be less focus on it, even though it is on the table. What has changed generally and strategically, that makes it not something that would add value?

Yes, I would say, first of all, I have to disagree with the premise from the management team standpoint and the Board, I wouldn’t say we are more or less enthusiastic about that today, than we were in a high price environment. I would say this though, when I think about what has hurt valuation on this rundown associated with commodity prices, and then the change in the capital markets, it seems to me in our particular case is mostly been driven especially more recently by the closure of the markets and people concerns over how we are going to fund our capital budget and how we are going meet, mature in 2009 and I hope we have laid out a plan that shows you that we are confident in our ability to do that, even in a capital constrained environment. And so, I guess our view is at this moment in time we don’t see tremendous value attributable to a split in this kind of an environment though that something we comfortably look at. But, I would that’s probably less of an opportunity for us at this red hot moment than it maybe in the future or has been in past.

Thank you.

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

Good morning, Faisel.

Good morning, guys. If I could ask I know when the maturities come due for next year in the first and second half of ‘09, given where we are right now the commodity price, given what you said for CapEx for both the pipeline business and E&P business, here is the question will you be free cash flow positive through with the second quarter of ‘09, given where we are right now?

If you look at our entire plan, we certainly don’t expect to be free cash flow for the full year and that’s why we probably that type of capital markets over the second half. Between the slowing down of capital currently and our current level of liquidity we feel comfortable that we will be able to meet those maturities in May.

From an operating perspective will you be free cash flow positive after CapEx through the second quarter of ‘09? I know you can meet the maturities but the question is on an operating basis can you only be free cash flow positive after CapEx?

No, no.

Okay.

We are counting on some of the liquidity that we have on the balance sheet today.

Okay. And then related to some of the comments, I guess, you made in your press release related to looking at possibly entertaining partnerships for some of the pipeline, I guess what’s the level of interest right now in kind of doing that, I guess have you begin phone calls or you yet to make more outgoing phone calls what is the level of interest there?

I would say that the level of interest on the inbound side has been relatively high. We haven’t made assumptions about what that might be but that’s really also not a change from what we would have been in our last call. We have always thought that it will be prudent to look at partners for some of the growth projects, the one I guess has been talked about most is Ruby.

Got you, okay.

That’s certainly the one on which we got the most inbound calls.

Okay. And how does the, is capacity in our fleet subscribed on Ruby, are we over subscribed now or where are we with that in that situation?

Capacity we are between 1.1 and 1.2 today of subscriptions and we are looking at a pipeline that would be sized somewhere between 1.3 and 1.5.

Okay. And do you expect, are there other indications of interest in the pipe in terms of taking phone capacity or you think we are pretty much there?

No, I think there are addition to this, there is a lot of interest on both the market side as well as the fiduciary side I think if you think about the 1.1 to 1.2 today its as you know, its 375 are the robust for the market side represented by PG&E and the rest is fiduciary and going forward I would think the mix might look something similar to that.

Okay, got you. And then, discussion to the E&P side for a question. I guess, for next year how much capital will you guys be deploying into the into the Haynesville and Niobrara, and those projects?

I don’t have that in front of me Faisel. The total capital we have right now splits about little over $200 through to $250 for all of the international and the rest is domestic and then the bulk of the domestic, almost half of that is going to be that central division and so that includes the traditional Cotton Valley side gas, and those kinds of things and then it includes Haynesville pilot program and Cotton Valley Horizontal program. So, it will be a shift in the aggregate to longer term, longer ROP and more predictable kinds of access in a shift away from the shorter life more risky more uncertain projects.

Okay, and then on Pinauna what’s the time line look like now. I guess you guys kind of hinted that time line kind of moves a little bit further back?

Yes, what we are going there is, we’re going to base that project, the development of that project with the regulatory environmental approvals. We are currently anticipating if we push back as much as a year and the plans that we have now, but will learn more about that as we go through the rest of the year. The first significant milestone that we got on that was in terms of reference that I talked about and then we got several more environmental permits to get following that.

And how does that drive would be with the expected capital that you’re going to spend on that project. Don’t you have to order some of that equipment ahead of time or could not be delayed?

Yeah, most of it can be delayed. We had a lot of things identified including FSO, some things long lead time items that we had started to procure but there is very little holding cost or cost of delay or slowing that project’s pace.

Okay, got you.

The main thing is we will project in working through all of the issues and we will keep working the environmental issues that will be the biggest cost in ‘09.

Okay, great.

It also gives us the benefit of a lot more learnings around what’s going on in Copaiba, which is a well as Brent said we are in the process of testing that.

That exploratory well is in the southern part of that same basin. So, given success there that would increase enthusiasm the basin.

You can tie that into your current project?

We can tie in that project but it would -- on the margin it would be the basin that’s been active historically for Petrobras certainly become more active.

Okay, got you, thanks for the time guys.

Your next question comes from the line of Maura Shaughnessy from MFS. Your line is open.

Good morning, Maura.

Just help me understand the seasonality of the cash flow what typically is the better seasonal quarter in terms of the cash flow such as maybe you just can talk to me about that all else equal obviously?

Maura, this is Mark. Fourth and first quarters are the strongest cash flow quarters on the pipeline part of the business. And, generally for the E&P side of the business given the hedges, not given the hedges, but given the overall normal cyclical commodity price environment. Our hedge position in ‘09 for the E&P side of the business is somewhat weighted to the first quarter, so we would expect strong cash flow for Q4, Q1 and then Q2 is usually pretty good quarter, Q3 is the lowest.

Okay. And getting back to the Ruby situation, can you describe what assuming you own a 100% in 9 and 10, what the capital spending is going to be on that project?

Yes, we probably spent, this is a $3 billion project, we probably spent about $100 million today, we committed as you know on the pipe, but total pipe order is over $900 million. A lot of that get spent over the course of ‘09, just generally you would be looking at probably over ‘09 and ‘010, $1 billion each for total capital spending and the remainder in early ‘011.

Okay. My guess, that the market reaction to capital plan one of the concerns clearly is the potential need to go to the capital markets in the second half of ‘09 and not that any one has any clue as to what that environment is going like? I guess, I am just trying understand you guys have talked in the past and been very open to partnership on the Ruby project and given the basis situation in the Rockies, I know that the producers are certainly in dire need of that kind of a project. And, I’m trying to understand because if some sort of partnership were done in the short term, lot of this capital concerned would be materially alleviated. So, I’m trying to understand frankly why we haven’t heard about a partnership yet on Ruby?

Maura, this is Doug. It would have been unusual, I think in any circumstance for us to have announced the partnership by this time when you consider the phase of the project. We will file our first certificate in January.

Okay.

We are still finalizing the volume commitment side on this because remember after we announce we were waiting some other actions in the marketplace and so we are still finalizing that. I think, actually we are in pretty good shape with regard to Ruby in terms of executing the project. But, it is still an early phase project that goes in, in 2011.

Right. So, Doug are you saying you need to have all of it signed up and the FERC?

No, no. But, remember we are probably days or little away CPEC approval.

We have regulatory approvals to get, PG&E has received yet the approval CPEC which may happen soon. As Doug, we are just starting into the regulatory year which will be next year. But, I think this clearly interest and growing interest as we continue to execute.

Okay, great well thanks very much.

Operator, take one more.

Your last question comes from the line of Carl Kirst from BMO Capital. Your line is open.

Hi, thanks everyone. Actually I just really wanted key off of Maura’s question, so it is apropos here, I would guess, I was trying to look at perhaps the timing of the partnership as well, is that something, well I guess two questions. One, as you take the color of the inbound calls is this primarily from private equity pension or is it also operators that’s one question? The second question really has more to do with timing, is this something that we could still be sort of in the second half of next year where once we kind of get the approvals this could be a relatively quick process, I understand it’s a difficult question to answer but any color would be helpful?

Yeah, I would first of all, we are not going to talk about as a matter of policy who we are talking to about partnerships except to tell you that there has been keen interest in folks partnering with us on Ruby on all fronts. In terms of timing it is a priority for us it’s not the only, remember it’s not the only lever we have to pull. So, it is something that we are focused on along with the host of other issues or other opportunities that we have and so, we are on our end of the table just so you know from a tone standpoint. We are confident in our ability to execute this plan. We are also confident in our ability to deal with capital markets as they sit today and just would remind people that this is company that in the last five years has been as active in a constraint capital environment as maybe any company in our pier group. And by and large especially when it comes to asset sales and partnerships and those kind of things by and large we have been able to deliver on our commitments. And so, we have a lot of levers to pull in this company, we know how to react in this kind of a market. And, I think while you may not agree with every decision we made, we’ve laid out pretty clearly what our primary objectives were which well have preserved the $8 billion backlog that we have in our pipeline. That means we know what our long term profitability looks in the biggest part of our business has no real exposure to commodity prices or throughput issues. So, we know what that revenue line looks like. We’re going to preserve that. And secondly, to use of our E&P business in the near term in order to flex capital spending up and down, which is prudent for a couple of reasons. One, we can do it because frankly we can, we have high working interest and we operate mostly properties we are in but also and we can do it without sacrificing the inventory that sits in that company. And secondly, it’s a prudent thing to do in any case because of what’s happened to commodity prices and the lag effect between commodity prices and service cost. And, we think in the end we will end up preserving our inventory, generating better returns and still have the opportunity to add some bulk businesses. So, with that I will wrap it up and thank you for your attention this morning.

Thank you.

This concludes today’s conference call, you may now disconnect.