Kinder Morgan, Inc. (KMI) Q4 2010 Earnings Report, Transcript and Summary

Good morning. My name is Brooke, and I'll be your conference operator today. At this time, I would like to welcome everyone to the El Paso Corporation Fourth Quarter 2010 Earnings Conference Call. [Operator Instructions] I will now turn the conference over to Bruce Connery, Vice President of Investor and Media Relations. Thank you. Mr. Connery, you may begin your conference.

Good morning. Thank you for joining our call. In just a moment, I'll turn the call over to Doug Foshee, Chairman and Chief Executive Officer of El Paso. You will hear from three other speakers on our call this morning: J.R. Sult, our Chief Financial Officer; Jim Yardley, Chairman of the Pipeline Group; and Brent Smolik, President of El Paso Exploration Production Company. During this morning's call, we will be referring to slides that are available in the Investor section of our website, elpaso.com. Also on our website, you will find a financial and operational reporting package that includes information we believe you will find helpful as well as non-GAAP financial statements and non-GAAP reconciliations. During this conference call, we will make a number of forward-looking statements and projections. We have 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, there are variety of factors that could cause actual results to differ materially from the statements and projections expressed during this call. You will find those factors listed under the cautionary statement regarding forward-looking statements on Slide 2 of this morning’s presentation as well as in other SEC filings. We do not assume any obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. Finally, I’d like to ask those of you who will be participating in Q&A to limit yourselves to two questions so that we can give more people an opportunity to ask questions. Thanks for your help on this. I'll now turn the call over to Doug.

Thanks, Bruce, and good morning to all of you. Four weeks ago, we had a 2011 guidance call, and I hope you came away from that call with a sense of a confidence we have going into this year and our ability to have another breakout year similar to 2010 operationally, financially and in terms of share price performance. We entered the year with a lot of momentum and a higher level of energy and excitement than at any time in my tenure with El Paso. In E&P, we're ramping up our activity in some of the most exciting oil plays out there, and our early results are very encouraging as Brent will share in more detail. In the pipes, we've now got 85% of the Ruby pipe welded up. And while we're increasing our estimated cost to $3.55 billion, we also have a much greater certainty on the remaining risks. Hence, the elimination of a range for completed costs. And while Ruby execution isn't what we forecast, we still expect to put the entirety of our $8 billion backlog in service this year. We don't have a Midstream update today except to say that Mark and his team continue to push forward on two key projects in the Marcellus and the Eagle Ford in addition to successfully expanding existing Midstream assets in the Eagle Ford and Altamont. And finally, you should expect continued improvement in our balance sheet this year as J.R., Jim and their teams continue to prosecute our successful drop-down strategy at EPB. With that brief introduction, I'll turn the call over to J.R. to review our financial results. J.R.?

Thanks, Doug, and good morning to everyone. On Slide 5, you'll see a snapshot of our fourth quarter financial results. We reported adjusted diluted earnings per share of $0.20 for the quarter. Now when compared to 2009, the difference is primarily driven by lower realized commodity prices. During the quarter, we only had about 60% of our domestic natural gas production hedged around $5.80 compared to nearly 90% at north of $6 in the first three quarters of this year. Compare that to the fourth quarter of 2009 when we had almost 75% of our gas production hedged at roughly $9. Bottom line, that lower realized commodity prices reduced our earnings by about $0.10 per share quarter over quarter. In addition to the impact from lower prices, fourth quarter results reflected higher performance-related employee benefit costs of about $0.02 a share. As a result of our strong share price performance relative to our peer group in 2010, we doubled the amount of the company matching contribution for our employees who participate in the 401(k) plan with El Paso stock. This discretionary matching contribution is only available when our total shareholder return performance versus our peers exceeds the median level. Now we think this is a great way to ensure our employees are aligned with our shareholders interest. And this additional matching contribution is, however, not available to senior management. Slide 6, is a bit of a report card in our key 2010 goals. Now I'm not going to go through to each and every one of these since we touched on many during our recent guidance call. But by all accounts, we certainly had a very successful year. Adjusted earnings per share and cash flow from operations were better than we guided to in late 2009 and that's despite natural gas pricing well below the $5.50 assumption that we had used in our original plan. And overall, both business units had a great year. And despite the challenges on Ruby, the Pipeline Group had an excellent year executing on the projects placed in service in 2010, putting five projects in service collectively $100 million under budget. And on the E&P side, our E&P team knocked it out of the park for the second year in a row. Brent will walk you through some of his key measures in just a couple of minute. On Slide 7, I round out a brief look back to 2010 with some of the other key year-end metrics. We ended the year with $13.7 billion of total net debt. This includes $3.4 billion of consolidated debt of our MLP, El Paso Pipeline Partners. It also includes $1.1 billion of Ruby debt that will be deconsolidated from our balance sheet shortly after the pipeline is placed in service. And at that point, it will be recoursed only to the Ruby pipeline. We came into 2011 with very strong liquidity, $2.4 billion, even after retiring about $700 million of El Paso debt late in 2010. And finally, 2010 CapEx finished the year $4.2 billion, pretty close to our original CapEx target for the year. Now remember, E&P CapEx included an incremental $265 million of lease acquisition capital for Eagle Ford and Wolfcamp oil acreage. And on the pipeline side, last year's $2.8 billion of capital will likely be the high watermark for many years to come. On Slide 8, we reiterate our primary financial objectives for 2011. And although I've covered these on our recent call, I think it's important to keep these front and center. First and foremost, we're intent on improving the balance sheet so that we achieve an investment-grade profile by 2012. There's no question that reaching this goal has very positive implications for shareholder value. The best tool we have to accelerate our deleveraging is continuing our MLP drop-down strategy using EPB. And make no mistake, we're focused on maximizing the impact of this strategy to the benefit of El Paso and El Paso Pipeline Partners stakeholders. In the last month's call, I noted that our guidance assumes we complete two to three drops in 2011. And finally, we'll maintain adequate liquidity throughout the year to support our businesses. As we progress through the year, the need to maintain our historic liquidity levels will diminish as we complete the pipeline backlog and continue to improve and further de-risk our balance sheet. I'll wrap up this morning with an update on our hedge positions on Slide 9. Since our last call, we added 2.7 million barrels of oil hedges for 2012. So based on our forecasted 2011 production, we've got about 70% of our 2012 oil production hedged with downside protection at $90. So despite the constructive macro outlook for oil, the $90 floor feels pretty good. Nothing's changed on our gas hedges, other than they're fact that they're further in the money and continue to look great. And by the way, our hedges boosted our cash flow by roughly $300 million in 2010, which when added to about $1 billion generated in 2009, equates to almost $2 per share of incremental cash flow. So I'm quite proud of the value our disciplined hedging programs created over the last couple of years in what has been a very challenging commodity market. That's it for me. I'll turn the call over to Jim for pipeline update. Jim?

Thanks, J.R. With the pipelines, the fourth quarter was a busy one as we placed and serviced three more growth projects; two in the Rockies and one in the Southeast to supply gas to a newly converted coal plant. All three are now generating revenue. It came in approximately $100 million under budget, as J.R. said, completing an excellent year of executing on projects that went in service last year. As you know, this year will essentially complete our regional $8 billion backlog by placing five more expansions in service. We've made good progress on Ruby, and it's getting closer to completion, but our cost estimate is higher. The other four projects are all on-time and on-budget, with the first of these, FGT Phase VIII, scheduled to begin service in April. As we said on the guidance call, we also have three major rate cases this year. Our aim is to try is to settle all three by year end and get back to the business of serving our customers, meeting their needs safely and reliably and growing with them. On Slide 12, Slide 12 summarizes throughput trends for the year. Throughput was down approximately 2% overall from 2009 with increases in the East and decreases on our Western pipes. In the East, both SNG and TGP benefited from a very hot summer and cold winter. Also, TGP throughput increased due to the receipts from Marcellus in Pennsylvania and REX in Ohio. Marcellus production into TGP is now running at approximately 1.2 Bs [BCF] a day, up from only 250 a day at the beginning of 2010. In the West, throughput was down on both our Rockies pipes and on EPNG, not due to market demand which was pretty flat along both the front range and on the Southwest but rather mostly due to competition. In the Rockies it was increased competition on both intra-Rockies flows and exports out of the Rockies. On EPNG, it was supply alternatives into California. Much of this additional supply was for LNG imports at Costa Azul, which more recently have declined. Importantly, we also see tangible signs now of improving market demands long-term on EPNG. While we're on throughput, let me take a minute to talk about our service to customers during the record-breaking cold weather of a couple of weeks ago. In short, our pipes were to demonstrate clearly their value to customers. We met the peak day needs of all our customers in the Northeast, Southeast and Rockies. This resulted from the diverse gas supplies behind our pipes, extraordinary performance by our field operations people and a lot of communication between our customers and us. Our only service impact across the country was on part of EPNG's South mainline in extreme West Texas, New Mexico and Arizona. This was due primarily to freeze offs of Permian production and processing plant offsets, which in turn resulted in lower delivery pressures on EPNG. But even here, and with cold temperatures not seen in 45 years, we delivered to our customers substantially more gas than they received from their suppliers. And I want to share my appreciation to our workforce across the country, both field and office, for going the extra mile to serve our customers during this period. On Ruby, we've made substantial progress on Ruby. As Doug said, we're now about 85% welded out, up from 70% reported just a month ago. At the same time, however, we've seen some cost and schedule slippage and now expect Ruby to cost approximately $3.55 billion and be in service in July. This results from the combined impacts of extremely wet weather in December across Northern Nevada and Southern Oregon, delays in permitting and restrictions due to fish and game habitat. Also, until recently, we expected to complete a 40 mile section of Spread 5 in Nevada before the sage grouse mating season begins on March 1. We haven't been able to do this, primarily because of delays in obtaining final cultural resource clearances. Now we won't start construction on short stretches of that section until the mating season ends in mid-May. And we've temporarily shut down that spread's pipeline. So we're unlikely to complete Spread 5 until July. Some of the increase in project costs is additional cash costs and some is non-cash AFUDC costs associated with the later in-service. The good news is that we believe we have more certainty now on our cost estimate. We feel better about each of the three critical issues that we've highlighted for you since the first of the year: First, the worst of the winter weather is behind us; second, permitting and cultural resource clearances are for the most part, complete; and third, we have greater clarity around fish and game construction windows, although we're still dealing with a few issues on some stream crossings. Not only have we made good progress as evidenced by the percent welded, but also the Eastern spreads are all very nearly complete. So our run rate monthly spend is dropping off. So we have better line of sight now on the finish line, and we'll update you again on our May first quarter earnings call. And now I'll turn it over to Brent.

Thanks, Jim. Good morning, everyone. I'm going to begin this morning on Slide 15. I've met with a number of investors over the past few weeks, and it was great to hear feedback and recognition that our E&P strategy is working. We posted good numbers again last year, and I'll review some of those with you in a moment. But we also know that we had to continue to deliver, and we're off to a good start. We began the year with our production at roughly $800 million a day within our guidance range for this year, so we're on plan. But remember that our relatively wide guidance range has taken into account the potential to further shift capital from gas to oil, which may impact volume guidance providing growth for that greater value. We continue to ramp up our oil activities with two more rigs in our essential Eagle Ford area. Our results on the program continue to be at or better than our pre-drill models, and we're delivering some of the same efficiency gains in the Eagle Ford that we delivered in our Haynesville program. We've drilled four Wolfcamp wells, one is online and we are currently completing two of the wells. We're on track with our delineation plan there with two of the wells drilled today in the eastern portion of our acreage, one in the center and one on the Western side. We've also taken hole cores on two wells and the coring, drilling, logging data that we have gathered so far has been very consistent with our expectations. There's also been some horizontal wells drilled to offset our acreage that look very good and adds to our enthusiasm about this program. Considering the date of the timing of data flow in the play, we're currently planning to update on our Wolfcamp program in our May 5 earnings call or perhaps sooner at one of the conferences. Some of the key metrics from 2010 performance are shown on Slide 16. Our production was 782 million equivalent per day, which is above the high end of our guidance and above 2009 results. Our fourth quarter production was 795 a day, which is up 7% year-over-year and was the highest quarterly production that we've reported since the first quarter of 2009. Cash costs were also lower than they were in 2009, coming in at $1.78 versus $1.82. I'm also very pleased with our reserve growth and efficiency metrics in our inventory growth for the year. When you look at 2010 E&P performance, I think the key takeaway is that we've reached a point where we can consistently deliver results that are very competitive with the best of our industry peers. We've updated Slide 17 from our guidance call to show you our current drilling activity. We've added two oil rigs, both in the Eagle Ford. So in total, we now have over twice as many oil rigs than gas rigs working, and we plan for that ratio to increase during the course of the year. In the near term, we still plan to run four rigs in the Haynesville program, which is a very optimized and economic activity level. But as I said in our guidance call, depending on gas prices and service costs, we may choose to further reduce our activity and shift capital to one of our oil programs. Another factor that can change our activity level is whether or not we take a partner in the Eagle Ford. We're very much in the throes of those discussions and we'll likely decide by the end of Q1. If we can accelerate our Eagle Ford program while improving the value of the opportunity by taking a partner, then we'll do it. If not, then we'll go it alone and shift capital as we need to in the second half of the year. And let's stay with the Eagle Ford with an update on Slide 18. We're pleased with our results to date so we've essentially doubled our activity level since the first of the year. We're achieving production tests and expected the EURs that as good as or better than expected, and we're pushing to gain additional cost efficiencies. Most of our activity is in the Central LaSalle County area where we have our largest acreage position. And we now believe that area contains volatile oil, meaning that we have oil in the reservoir with associated gas at the surface versus having gas wells with condensate dropping out of the surface. Three of the 14 wells that we've drilled here had initial rates in excess of 1,000 barrels a day equivalent. And we recently drilled our longest lateral roughly 6,400 feet, completed the well with 21 frac stages and have seen daily producing rates of over 900 barrel equivalents. So as we move into development phase, the Eagle Ford will become more impactful in 2011. Since the beginning of this year, we have completed nine new wells and when we get the newer completions online, we expect to double production from the field. On Slide 19, we showed that production mix over the expected life of the wells in the central and the northern area of Eagle Ford, which is consistent with a models that we published last October at the time of our Eagle Ford field trip. Now I want to briefly revisit this topic because in recent conversations with investors, I've heard some confusion about the product mix from our northern and central areas of the Eagle Ford, and those makes up about, as a reminder, about 2/3 of our total acreage position. And we believe that in the central area, about 75% of the recoverable reserves are expected to be oil. NGLs are only about 10% of the volume, with which means that while ethane and other liquid prices improved the economics, they're not a big value driver in our program. In the northern area where we have currently one rig working, the oil contribution increases even further to 85%. All the wells in that northern area will need artificial lift almost from day one, so we're quickly working to determine the best method of pumping the wells both while we're producing back the frac water initially and in the long term, production mode. Note that Frio County wells has been completed, and we're currently installing artificial lift in that well. And also in our northern area, we've drilled the well in Atascosa county. It's our first well there. And we drilled and logged a vertical pilot hole and then we drilled the horizontal section and early worklog responses in both are very encouraging. So we're anxious to see how that well produces. Our last chart is on Slide 20 this morning. And we're always focused on continuous improvement in all of our programs, all of our asset areas and with with all parts of our business. And as a result, we believe that the Haynesville execution and cost structure is top quartile and often, industry leading. We've taken our Haynesville practices and moved them down to the Eagle Ford so we're moving up the learning curve rapidly, which means we're finding ways to cut time and capital costs per well. And we've only been drilling the Eagle Ford for a little over a year, and the results shown on this slide are based on about 20 well data set. We made significant progress during the drilling phase, improving from 500 feet per day to about 1,200 feet per day. We also had similar success in the time required from spud to total depth, cutting the number of days by over 60% from about 31 days to 11 days on our best well to date. And just as we have done elsewhere, our drilling team's delivered these efficiencies by optimizing the drill bit, the downhole motor and the drilling fluid designs and combinations. And then, we believe later as we move into multi-well paths, we expect to see continued reduction in cycle time. Remember though that more than half of our well costs is for completion and simulation, so finding efficiencies in frac-ing these wells also has major cost benefit. Averaging 3.6 fracs per day at far best well today is great progress for our Eagle Ford team. We've benefited from having a dedicated completion crews with Foster's better safety performance and better teamwork and coordination, and we expect additional gains as we continue to find ways to further eliminate the non-productive time or downtime. About 40% of our stimulation costs comes from fixed equipment charges, so we'll see a lower per well cost as we improve the efficiency of Eagle Ford completions or as we further improve the average number of fracs per day. And then, we'll spread that fixed costs to over more completions. At 3.6 fracs a day is our best Eagle Ford pace, but we're not stopping there because we're now consistently averaging closer to 4 fracs per day in the Haynesville. Overall, I'm really pleased with how this development is progressing and I continue to believe that the Eagle Ford will be a long term anchor program for us. I'll now turn the call back to Doug for closing comments.

Thanks, Brent. We're off to a great start this year. It's exciting at $100 crude world to have a meaningful oil component in our E&P story and when we intend to make the most of that opportunity. By year end, we'll have at least 3x as many oil directive rigs as gas directed rigs and maybe more. And that's going to yield 30% to 40% growth in oil production this year and another 50% in 2012. Restoring our balance sheet strength is also a top priority for 2011. One of the primary tools to accomplish this is EPB, and there's every reason to believe we'll have another successful year growing EPB to the benefit of both the MLP unitholders and the EP shareholders. We know that this continued improvement is key to getting the premium multiple for our stock that we believe it deserves. Another valuation key is the completion of our extensive backlog in the pipes, as well as successfully concluding rate cases on EPNG, CIG and TGP. We expect to get all this done, much of it in the first half of this year. And in Midstream, you'll more from Mark on our Analyst Day in May. But in the meantime, his team is very busy completing for the mass project in the Marcellus and the Camino Real project in the Eagle Ford. And while each is very competitive, we're competing hard to get these across the finish line. We're making great progress already on these and other milestones we laid out for you in our earlier guidance call, and that means we have every expectation that 2011 will be another rewarding year for our shareholders. Finally, while we're on the topic of rewarding our shareholders, I'll wager that someone on the call is planning to ask about corporate structure given recent events in the capital markets. The key message I want you to take from this call is that we'll do what is right for our shareholders to create long-term sustainable value. And that's whether we are talking about the management team or our Board. So while our immediate focus is on all those milestones we laid out for 2011, we're not deaf to the markets. In fact, recent events we think are very exciting for anyone who is an EP shareholder or considering being an EP shareholder. Case in point. So a new high watermarks have been achieved recently in terms of valuations for high-quality GPs. We think that's not only appropriate, it's outstanding. And we just happen to own 100% of the highest quality GP. And the great news is, it has a tremendous growth profile. We only reached the 50% incentive distribution rights in the fourth quarter of 2010. So that $50 million to $60 million in distributions to the GP in 2011 is still toward the front end of a very high growth trajectory that will create lots and lots of value for EP shareholders. And because it has the lowest-risks, highest-growth characteristics out there due to its sponsor and due to the fact that it's the only pure play GP, it sets the high watermark for what GPs are worth. In addition, recent transactions point out that companies with strong balance sheets and high cash payouts are highly valued in the market. That's why we're running as fast as we can to make sure we maximize the strength of our balance sheet. And we have every expectation that we'll do just that. And E&P companies and assets that have low risks, repeatable drilling inventories at the lower end of the cost curve and with oil exposure going to higher valuations, that's exactly what we think we have. So if you believe that management is properly incented and the company is properly governed, then there's really nothing but upside all in our shares in this regard. So where do we stack up on those dimensions? Management has higher-than-average leverage and compensation to changes in equity values. And given that as a group, we haven't been sellers and we are all very large owners relative to our personal worth, you should assume we think and act like owners. We also have a very independent, very shareholder-minded Board that I think stacks up well against any competitor we have. So I think on those two key dimensions. We have a vision of a company that will stay laser focused on taking the actions that will maximize the long-term share price of El Paso. In addition, we have a track record of doing just that, having made many, many shareholder-friendly decisions as we brought this company back from the brink. While we like the integrated model and see key benefits to it, we're not married to it. We have looked and will continue to look at structure. And the great news is, we're not doing it in a vacuum. We've got interesting real world data points to analyze and monitor, some from well-seasoned transactions and some from more recent announcements. I believe that significantly increases the likelihood that a dispassionate analysis will yield the right result. This has been and will continue to be a key topic of discussion in both the management and the Board level and we'll continue to keep you apprised of our decisions in this regard. And with that, we're happy to open it up to your questions.

[Operator Instructions] Your first question comes from Carl Kirst with BMO Capital Markets.

You know, maybe first, under the -- before we can do that kind to get to the end of backlog put in place, my first question is just on Ruby. And I know this might be difficult to take it a step further. But Jim, when we talk about the certainty, the additional certainty we have right now, is there any way you could even further quantify that? I mean, are we kind of in a 50% band moving to 75% band? Are we now at kind of this 95%-plus band. The only reason why I asked that is unless I misheard you, the Western Nevada piece getting finished in July, is that going to be making sort of a compressed window to get those pieces tested, et cetera, and get the actual entire project in service by July? I just wanted to get some more color on that if possible.

Okay. Yes. Carl, I think as a general statement, we're simply further down the road because we -- if you think about the 85% welded, we have a grand total of about 100 miles left to weld out. So we have -- and so, and that's in three discrete pieces. One is on Spread 5, where I'll talk about our plan in just a minute, and the other -- and so that probably comprises about 40 miles of the 100. And the other two pieces of 30 miles each or so are on Spreads 6 and 7 in Oregon. But on Spread 5, our plan, and I think it's a well-developed one, we know all the parameters because of the sage grouse mating issue, we -- within that 40 mile stretch, there's only about 12 to 14 miles that is impacted by this sage grouse mating issue. So we're clearing through what we can clear through now. As soon as we can, we'll start stringing and then welding up. Realistically, from an assembly-line-operation standpoint, we won't be able to get up to that. We won't be able to do appreciable welding on that stretch until mid-May. But when you go through that exercise on Spread 5, we should be welded up on the whole thing in June, do tie ends then into early July and have plenty of time for purging and packing, et cetera. Anyway, that's sort of the critical path matter. On Spread 6 and 7, in Oregon, we effective -- we're very close to having all of our permits there. And so there is more, continuing to grind it out as we have been doing. And we fully expect that as well as all of the rest of the pipeline with the exception of Spread 5 to be fully welded out by the end of April. So that there are -- then tie ends and testing on that will commence. So that as soon as we finish Spread 5 with very limited time after that, we'll be able to put it in service. So I guess my point is that on costs, we have a much better prune down now. We have ongoing weather issues, but gee, we're through the worst of that. We essentially have all of our permits in place. The worst of the construction is really behind us. The' work on Spreads 5, 6 and 7 -- on Spread 5, once we get in there, it's not difficult pipelining. So we just feel a lot better about our costs and schedule.

And then one additional question, if I could, maybe for Brent. You mentioned with respect to the Eagle Ford JV mechanics that the decision, I guess, hopefully by the end here of the first quarter. And I didn't know if there was any color you could provide on or would feel comfortable providing on the process of that's going through. And by that I mean, from the time that you guys first announced you were looking at this, we've obviously have much stronger oil and NGL prices. Obviously, we're in kind of a crazy oil market right now. But we've had better results kind of come in on the Eagle Ford. And what I'm wondering is, are we seeing sort of a creep up in the ask price? Or were we seeing a change in mix of customers or potential JV partners who might be looking at this? I'm just trying to get a little bit of different flavor of how the process is going.

Hey Carl. This is Doug. I think we'll probably not inclined to get into a lot of detail on that process other than to say, to sort of reiterate, we think we will have made an internal decision by the end of this quarter. That doesn't mean we'll have an announcement ready by the end of the quarter, but we will make an internal decision by the end of this quarter. The interest level continues to be high. The rise in oil prices, in our view, doesn't do anything but A, positively impact our hold case and positively impact the valuation on these assets. But beyond that, it doesn't change our process. And we think this is something that we should evaluate for the benefit of our shareholders, but we also don't feel like we have a gun to our head forcing us to do it.

Your next cushion comes from Steve Maresca with Morgan Stanley.

My first question is on Ruby. If you could just remind us on these cost overruns, how that is getting borne between you and your kind of partner project?

All us.

And also an update there in terms of the capacity that's not taken up right now. How you think that's going to play out over the next 12 months or so?

Yes. So we have 1.1 of the 1.5, as you recall, contracted long term. Realistically, Steve, we don't have a long list of prospects for the remainder of the capacity on a long-term basis. That's going to be dictated by Rockies production and probably more importantly to what's going on in the Northwest with respect to coal conversions. But it's just a step away. But with respect to actually how volumes flow once Ruby comes up, still hard to call. There are many reasons why more gas may want to flow West out of the Rockies than East especially with all the Marcellus and other shales in the East. We're not counting on a great deal of revenue from all that, but that's out there.

Yes, I would say that at this point, that for the most part is upside to our plan. And the issues with regard to Ruby in terms of that, the incremental 400 are really more macro issues that we think get resolved, but they don't likely get resolved in terms of having firm transport contracts in the next 12 months.

And my last one would be on Midstream side. Any color on timing or level of discussions as it relates to Midstream projects, maybe specifically, the Marcellus one with Spectra but others in general, level of producer commitments and timing as you think you may get something else?

Steve, it's a highly competitive situation. We're talking to all the major producers, as well as the Gulf Coast petrochemical complex for firm commitments. And you know, I think that's something that will resolve itself over the next three, four, five months. It could be midyear before we really know things will shake out.

These decisions are highly likely to be made by the big subscribers capacity in 2011.

Correct.

Probably, and I'd say more likely in the first half.

Your next question comes from Kevin Smith with Raymond James.

Can you talk a little bit about your production impact from this cold weather we saw especially in the kind of first 10 days of February? Do you see any downtime?

This is Brent, Kevin. We did see some but compared to rest of industry, we were relatively unscathed. We have a couple of really cold mornings where we had a little bit of Raton, a little bit of Oklahoma, a little bit of ArkLaTex, kinds of things we had to work through but you're not going to see much of an impact in any of our monthly production due to freezing or due to cold. So to further Jim's comment, credit to the team in the field. They were out in some pretty tough conditions, keeping everything moving and they were able to keep it going. And then, in the Texas issues, because of the some of the outer power outages, we didn't have production in any of those areas. And so again, we dodged that issues that some of the other producers faced.

On your ceiling test charge, it looks like you took a charge in Egypt. Could talk a little bit about that?

Yes, because we don't have production in Egypt and any of the wells that we drilled that were unsuccessful, it's an accounting ceiling test charge but it's really dry hole expense.

It has absolutely nothing to do with the politics or moving any acreage or anything?

No. It's a great question. No, it's really just related to the dry hole that we take to expense.

Your next question comes from David Heikkinen with Tudor Pickering.

Just want to understand a little bit of thoughts around the Camino Real system and any thoughts about type of hydrocarbon you might move whether or not that would transition towards oil or have you thought about that at all?

Yes. I think that, David, that's really focused on gas. It's going to be rich gas, and there'll be probably some condensate that comes through. But we're really focused on the gas system as opposed to an oil system. The reason is, is we can leverage Tennessee Gas pipeline as an outlet and that's kind of why we think we have a potential project there.

Can you talk how, and Brett maybe just some thoughts around some of the flarings that's going on in the Eagle Ford then and kind of how and what you do with oil and gas in the overall development and how you're planning that out from a capacity standpoint in the next year or two years?

Yes. In the near term, we think we've got enough capacity on the gas side. Really, we're talking about longer term solutions, Camino Real and others, to be able to move gas as we ramp up over the next two or three years. So I don't think that'll be the bottleneck. There is currently a trucking tightness out there in the Eagle Ford, and so we're having to manage that very carefully as we grow oil volumes to make sure we've got enough tracking capacity and/or storage in the field to be able to have short periods of time when trucking gets tight. But I think that's all manageable. Until we get longer-term, more permanent solution. So either several of the pipeline, oil pipeline solutions we're looking at right now and then the new terminal that we're looking at that would have the potential to rail some of it. And so we're looking at all the options for longer term as we grow out past where we think it's sensible to use a truck.

David, I'll just add to that, that in a $100 per barrel WTI and a little to no barrier to entry to the trucking business, I don't anticipate that would be anything other than maybe periodic short-term challenges.

And so you as you think about your development for any kind of hit on the oil side of how you produce these wells, I'm thinking about how do you produce the wells in West Texas as well from an artificial lift and just sustainability. You talked about how the oily wells are actually producing and what you're thinking about or how do you design and maintain and sustain productions from those areas.

Yes, just generally, the high level, the ones that are oily but high gas, we're able to get those to flow for a reasonable period of time, long enough to be able to get frac load off of them, get to where we're making oil and get decent test rates. But they at some point will log off to. The once we go further north and Eagle Ford, we'll have less gas associated with them. And so we will be pumping almost day one. And so that's how we're designing those rigs. You're going to have to put high grade pumps on them, jet pumps or sub pumps or something to get the frac water cleaned up and the early kind of high flow rates. And then have a program in place that rotates those to the new wells and rotates them in a more permanent solution, probably rod them up in a lot of cases, just sort of high-volume rod pumping, that's what we're thinking. But we don't have that solution yet. And it's going to be some combination of flowing wells, high rate, getting the frac to it all and then long-term pumping science.

And what do you think about access to electricity and then, it's kind of the same question in the Wolfcamp, how do you think about that if you have to use that type of system?

Well, if it's pumping, we can always use gas for our pumps too. So I don't think that will be as big a challenge. It will just be managing the high flow rates initially and then long periods of time with more modest flow rates. And then to answer the Wolfcamp, what we're seeing so far is that fairly higher gas rates. And so we're getting a lot of early flow on net full [ph] on those wells.

So basically, you're going to unload the frac with the gas charge?

That would be ideal. The ideal scenario is to do that.

And then, additional acreage added in 2011. As you think about what you've done over the couple of years, how do you think about capital? And could you expose a couple of hundred million dollars to any new plays this year?

What we have been saying is that we expect something more like a traditional run rate for us for new lands. It's kind of how we've guided in our capital plans right now. Last year, it was kind of almost 2x a year for land dollars for us. And then, also think beyond new lands. I mean the inventory growth, if you have inventory growth, it's likely to come first on the existing lands that we have as we continue to de-risk Eagle Ford and Wolfcamp more importantly. And as we look at infilling some of the areas, more density like the Haynesville and Eagle Ford. And so that would be the first place we'll have inventory above, the next place would be new lands and then the third place is kind of a new play, light-space area.

Your next question comes from Ted Durbin the Goldman, Sachs Co.

First question is for Jim. How are you thinking about when Ruby comes online, how that might impact of flows on EPNG? Anything you have for rate case there? Have you kind of factored that into the rate case? How do you think the flows kind of changes as Ruby comes on?

That's a good question. One of the impacts on EPNG to date actually has been increased flows from Canada into the Northwest, as Canadian imports have been backed up in the Northeast. Actually -- and while Canadian imports in total are down, they've actually been up on GTN coming into northern California. So that has impacted EPNG to date. So our view is that for the most part, when Ruby comes on, it displaces those flows. I don't think we see any material further impact on EPNG from that. I'd reiterate again what I said on the script that really, we see EPNG pretty much bottoming out now with respect to throughput. And we see some very nice tangible signs of increasing demand down. there.

And then, J.R., if I could just mention, I think you said you'll need less liquidity as you get through this CapEx cycle. Can you give us a sense on where you want to be in the end of 2011, as we get into 2012 in terms of liquidity profile?

I think, Ted, you should think that once we get that portion [ph] of the capital spend associated with the pipeline backlog, once we put Ruby in service and kind of the contingent nature of our obligations associated with all of the various agreements associated with Ruby behind us, I think something in the $1 billion to $1.5 billion at most range is more than sufficient to manage the enterprise.

Our next question comes from Craig Shere with Tuohy Brothers.

I got a couple of questions about the MLP strategy. J.R., I know you've repeatedly said that you'll go pedal to the metal as much as the market will bear on absorbing debt and equity from EPB. I guess I just wanted to chat for a quick second about what type of dropdowns are that you'd envision and the sizes, I mean you talked about the two to three dropdowns this year. In terms of the type, it seems like it's been a really gold-plated MLP with very high cost basis, recently constructed assets that are fully contracted. Does that for now preclude things like FGT Phase VIII, which is not fully contracted, Ruby not fully contracted or legacy pipes that have been depreciated and have lower basis from being dropped down in the near future?

Absolutely not. Craig, as we talked about a lot, virtually every asset in the Pipeline Group is an asset that can find its way down into EPB. We talked before specifically because you mentioned the FGT, great asset. FGT, we currently own 50% with a partner. That investment today is held into C corp [C corporation]. So we would just have to work, ultimately work with our partner and to find more of a tax efficient manner in which to hold that asset before dropping it down into the MLP. But I think you should look back at the pipeline assets that are currently generating cash flows as well as all those pipeline assets. We're just finishing construction as being good quality assets that EPB could own one day.

And I think early last year, you gave guidance that dropdowns roughly, back of the envelope, you might think about $400 million or $500 million in size. But you kind of obviously leapfrogged that considerably by the end of the year in terms of what you're able to do. As we think about that two to three dropdowns this year, are we still thinking about that kind of a $500 million mark or something substantial larger each?

Yes. As we have said before, the only governor today at least on the pace and size, how quickly we can execute and prosecute our MLP strategy is the MLP equity markets and how much equity that we can put out on the system every year. What I've said on the guidance call is we get $1.4 billion last year of equity last year, the most ever raised by an MLP, and we just simply didn't play in for that in our guidance. But what you should approach it is the same way we've talked about before, Craig. And that is today, we could probably raise around $350 million of equity in any one time. You should assume that we would capitalize any acquisition 50-50. And so that puts you in a $700 million range from a total dropdowns standpoint, and we think we can do two or three-year.

Having said that, and that is how we build our plan. If you said at this red hot moment, how does February of 2011 compared to February 2010, you'd say it's going into the year more robust. So we'll continue to watch that market and take advantage of it as we can.

Your next question comes from Rebecca Followill with U.S. Capital Advisors.

My two questions and only two are, one, can you give us an update on the rate cases? I think you're assuming that EPNG goes into service in April and Tennessee in June, so where those stand? And then second, on your agreement with GIP on Ruby, I think that if I'm correct, that it has to be placed in service within 16 months of obtaining the FERC approvals, so where do you guys stand on that type of window and your agreement with them?

Let me handle the rate case question, Rebecca, there's really no news. You're right, the rates go into effect in April on EPNG and June on TGP. Early days with respect to settlement discussions on both. I think we have a good track record of settling things. We certainly like to do that. I'd be surprised, at least on TGP, if settlement discussions didn't start up soon. But remember that this is, as you well know, this is the first rate case on TGP in 15 years. So there's a lot of players at the table. So I think the long and short in the rate case question is not a lot of new news today but our aim is still to try to settle by the end of the year.

This is J.R. On the GIP question, it's actually 14 months from financial close when we closed the project financing. And so that would put it in November that our partner, if there was not in service by November, would have a put right. But all indications are, at this point in time, I think our partners are very happy with the progress that we continue to make and so, I don't see that being an issue.

Our next question comes from John Edwards with Morgan Keegan & Company.

Can you remind us now when does El Paso now expect to achieve metrics sufficient for investment-grade status? And then would do you expect to receive such?

John, what we said on our guidance call last month was we saw that by 2012 that we would have -- we have one metric, we had debt to EBITDA less than 3.5x in 2012 for El Paso Corp. And we felt like, when we look about the qualitative and quantitative credit metrics, we thought that, that was an appropriate investment-grade profile. What we haven't said is we're actually going to get the rating, necessarily, in 2012. We clearly can't control that. But by that point in time, we think we've got the metrics to support an investment-grade rating.

And then, what's the total pipeline asset profile upon completion of the backlog?

You better repeat the question, please.

What's the total amount of pipeline assets that you'll have upon completion of the $8 billion construction backlog?

The rate base, if you think about investment as being generally rate base, the rate base today of our legacy pipe is $10 billion to $11 billion. And by the time you work through the backlog, it will be north of $15 billion because of the pro rata nature of some of the $8 billion assets.

Our final question comes from Nathan Judge with Atlantic Equity.

One would be related to Pinauna. Is there any different view on perhaps looking at developing that on a more accelerated schedule and/or looking at monetizing the asset?

I'll take that one, Nathan. The Pinauna is really on the exact kind of same spot it's been for the last couple of updates. We weren't helped out by the BP spill in the Gulf because that put a little bit of shock in all the regulators around the world for offshore projects. But also, we've had Brazil elections. We have a new President and we will get new ministers, new energy ministers. But right now, that post is open for the environmental ministers. So we haven't advanced the permit, the environmental permit much at all. We have on our side, we've done everything we need to do to prepare it for the next round of submittals. But we're waiting for the appropriate time to do that with Obama and the regulatory body. And I think it's going to be for planning purposes, think about most of this year before we think we're going to be able to break through that log jam. And that's really the critical path item to do either. Either self-development or to do anything else to the partner to monetize it is getting regulatory approval to build it. And then once we do get the permit, we've got two or three years after that, if the permit is still active, before we have to be able to spend capital. So it's just a good option, especially in high oil prices, we continue to work and probably most of this year working on it.

Just with the regulated to -- thank you very much, Doug, for making the comment for essential strategic option of the company. I just wanted to get perhaps a better understanding of how the relationship of balance sheet improvements, the share price and potential split options could, how you think of them, for example, does the balance sheet need to be in shape before something or that there'll be something before that and just how those relate?

I think what we've said was just hasn't really changed, is that we view from here on out that our balance sheet isn't going to do anything but improve driven by a whole host of things, not the least, which is the continued strategy at our MLP. Achieving not only free cash flow but also investment-grade metrics in 2012 is a corporate goal. And as we get between here and there, our view is that our options open up. And we can do whatever decisions we choose to make really from a position of strength. I think what nobody wants is companies that are somehow balance sheet constrained in terms of funding themselves adequately and being competitive in their own right or in combination.

All right, that's the last question. We want to thank you very much for joining us. And if you have any follow-up questions, please give us a call.

Thank you. That concludes the conference. You may now disconnect.