Kinder Morgan, Inc. (KMI) Q1 2011 Earnings Report, Transcript and Summary

Good morning. My name is Amanda, and I will be your conference operator today. At this time, I would like to welcome everyone to the El Paso Corporation First Quarter 2011 Earnings Conference Call. [Operator Instructions] Thank you. I'll now turn the call over to Bruce Connery, Vice President of Investor and Media Relations.

Good morning, and 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 3 other speakers in our call this morning: J.R. Sult, our CFO; Jim Yardley, Chairman of the Pipeline Group; and Brent Smolik, President of El Paso Exploration & Production Company. Mark Leland, President of our Midstream Group, is here as well and will be available during Q&A. During this morning's call, we will be referring to slides that are available in the Investors section of our website, www.elpaso.com. Also on our website, you will find a financial and operating reporting package that includes information that we believe you will find helpful, as well as GAAP financial statements and non-GAAP reconciliations. During this call, we will make a number of forward-looking statements and projections. We have made every reasonable effort to ensure that 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 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 update publicly 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 the Q&A to limit yourself to 2 questions so that we give more people an opportunity to participate. Thanks for your help on this. And now I'll turn the call over to Doug.

Thanks, Bruce, and good morning. Before we begin the call this morning, I'd like to reach out to all of our employees, their families, our customers and our neighbors in Alabama. Our thoughts and prayers are with you as you begin the recovery process following the recent horrific storms. El Paso and our employees are supporting Red Cross relief efforts and will continue to do so. Now for our first quarter results. We are delighted to have another good quarter in the books. The momentum we felt at year end has continued through the first quarter, and we hope to show evidence of that this morning and again on May 24 at our Analyst Day in New York. J.R. will go over our financial results in some detail, but let me say here that we are ahead of our own internal plan in virtually every financial area. The E&P team continues to hit on all cylinders, with volumes ahead of plan, unit cost coming down and inflation being kept in check with continuing efficiency gains. We announced earlier this quarter that after a lengthy process, we've decided to go it alone on our Eagle Ford acreage. We had a fulsome process and received quality bids. In the end, however, our judgment was that the highest return outcome for our shareholders was to hold this acreage and develop it ourselves at our pace. As we've matured our activity there, we've gained confidence that this is the kind of high-quality, repeatable resource that fits our strategy to a tee. As this occurred and we derisked the acreage, its value went up. And given current and anticipated commodity prices, we felt that the value of this high-quality liquids inventory was key to our ongoing E&P story. We'll give you a full update on the impacts of this decision to our overall plan for 2011 at our Analyst Day later this month, but the news will be good. Brent will talk in more detail about another exciting oil-related story, the Wolfcamp. But the short story is that we're extremely pleased with what we see on our own, as well as on offset acreage. We're still early, but we know enough already to know we will be drilling in the Wolfcamp for a very long time. With prices at the most recent university land sale having more than doubled since our entry less than a year ago, others apparently share that opinion. In the pipes, we continue to make progress in putting into service the balance of an $8 million backlog or growth projects. During the quarter, FGT Phase VIII went into service on time and on budget. The second phase of the SNG expansion will go into service June 1. And Jim will provide an update on activities at Ruby where we expect to go in service in July. Out West, EPNG has been our most challenging pipeline, given that it serves the Arizona and California markets, which have been particularly hard hit during the recent recession. We've alluded in the past to the potential for expansion at EPNG to serve new utility load in Mexico. We've now brought the first of those expansions to fruition with a project to serve 2 new power gen plants in the state of Sonora. This represents 185 million cubic feet a day of incremental firm transport on EPNG, a significant addition to loads on this pipe. And given that between TGP and EPNG we now provide 75% of the transport into Mexico, we expect to compete very favorably for any additional load going forward. This is a great piece of business and a big win for our team out West. While we don't have a report on our Midstream efforts today, I will say that we are very encouraged by recent announcements by Dow Chemical, Chevron Phillips Chemical and Westlake Chemical about their expansion plans, primarily on the Gulf Coast. Others have estimated that this could result in an additional demand in the Gulf Coast of over 250,000 barrels a day of ethane. This means that the Gulf Coast will continue to be the demand center for ethane. We believe our MEPS project is best positioned to move the large volumes of ethane produced from the Marcellus to the Gulf Coast, and we continue to work closely with our customers to get this one over the finish line. Finally, we completed our first MLP drop of the year in the first quarter, continuing a string of successful drop downs, with EPB issuing more than $450 million of new equity. As in the past, we continue to target MLP proceeds to improving our balance sheet strength, as we march toward investment grade. With that, I'll turn it over to J.R. to review our financial results for the quarter, and I'll come back at the end to wrap up.

Thanks, Doug. And good morning, everyone. As Doug just mentioned, we are off to a good start this year. So that makes my job this morning pretty straightforward. After highlighting our latest drop down to the MLP, I'll provide an overview of our financial results for the quarter and close with an update on our hedge positions. We completed yet another drop down to El Paso Pipeline Partners during the quarter, our first for 2011 and sixth since our IPO, raising $667 million of cash proceeds. Consistent with our stated strategy, we are using the proceeds to reduce debt at El Paso Corp. Continued balance sheet improvement remains a top priority for us. That means you should expect more of the same, as we move throughout the year. Although not mentioned in my slides this morning, we also converted our 4.99% preferred into about 58 million shares of El Paso common stock during the quarter. Now this action further demonstrates our commitment to the balance sheet and moves us closer to our goal of achieving an investment grade profile. Now the conversion does not have an impact on our previously announced 2011 earnings per share guidance. Moving to Slide 6. We reported adjusted diluted earnings per share of $0.30 for the quarter, which was slightly below last year. Operational performance in the business units was offset by higher aggregate financing costs attributable to the pipeline expansion projects, namely Ruby. Our effective tax rate for the quarter on a GAAP basis was about 12%, driven by the resolution of several tax matters, as well as earned state tax credits related to recently completed capital projects. Now excluding these items, our effective rate would've been 22% for the quarter. Now our rate will remain well below the statutory rate of 35% and lower than 2010 due to the growth of earnings attributable to non-controlling interests, as we continue to drop more assets into the El Paso Pipeline Partners. Adjusted segment EBIT was essentially flat quarter-over-quarter, as increases in the Pipeline Group were offset by declines in E&P. In the pipes, higher revenues from the expansion projects placed in service, as well as an increase in allowance for funds used during construction related to Ruby were partially offset by lower revenues in our EPNG system. In E&P, declines from lower realized natural gas prices and a higher DD&A rate were partially offset by a 5% increase in equivalent production volumes, as well as higher crude oil prices. Now despite the lower earnings, E&P posted strong operational results, as Brett will discuss in a few minutes. And as we talked about back in our January guidance call, we're reporting business segment results using a new measure this year that excludes non-controlling interests from EBIT and EBITDA. Now remember, this change only impacted the Pipeline Group, and we've adjusted our 2010 measures to conform to the new presentation. So let's turn to operating cash flow and capital investment on Slide 7. We're essentially on track or even slightly ahead of where we expected to be at the end of the quarter. Cash flow from operations for the quarter exceeded the prior year due primarily to higher E&P cash flows and positive working capital changes. On the capital slide, you see the ramp up in pipeline spending from last year, as we progress through the final phases of several expansion projects, most notably our Ruby Pipeline. The first quarter capital level for the pipelines is expected to be the peak as our spending declines in subsequent quarters, as we near the completion of the original $8 billion expansion backlog. In our E&P business, spending was up for the quarter, reflecting higher horizontal drilling and completion activity in our core areas in 2011. On Slide 8, I'll close out my comments with an update on our hedge position. During the quarter, we added a bit to these positions. And as you can see, we are well protected from the risks of low natural gas prices in 2011, with 80% of our gas hedged at an average price of $5.78, well above current market prices. We also have nearly half of our 2012 natural gas production hedged at about $6. And while the near-term gas price environment remains difficult to predict, we are pleased that our hedge positions will provide a level of stability to our cash flows, as we execute our business plans. In fact, since the end of the quarter, we've been able to add some very attractive oil positions that I'll share with you at our May 24 Analyst Day. So that's my update for you this morning. I'm very happy with our strong start to 2011, and look forward to updating you on our progress throughout the year. With that, I'll turn the call over to Jim.

Thanks, J.R. The pipelines are off to a very good start in 2011. As J.R. showed, the pipes financials for the quarter reflect our expansion mode, very nice EBIT growth and big CapEx spend. And this year, we're continuing to complete more expansions, 5 additional projects enter service this year. The first one, as Doug said, the FGT Phase VIII expansion, was completed on budget and on-time on April 1. It's a big one, over $2.4 billion of CapEx, 800 a day of additional capacity increasing FGT's capacity into Florida by over 1/3. On the business development front, also as Doug said, we've just signed an agreement for EPNG to supply new power plants in Mexico. I'll review this project. Generally, it demonstrates the expected increase in exports to Mexico is happening and EPNG is well situated to capitalize on this trend. Slide 11 summarizes throughput trends for the first quarter versus last year. Overall, flat year-to-date. On the individual pipes, throughput was heavily influenced by weather. On our eastern pipes, significantly colder weather in the Northeast this year benefited TGP. TGP's throughput was at a record high. And in the Southeast, more normal winter temperatures after a very cold early 2010, resulted in lower throughput on SNG. Other than weather, on our recent pipes, a couple of recent trends continue. One, is that TGP continues to benefit from Marcellus production. Marcellus receipts into TGP are now 1.3 Bs a day, up from 1/2 B a day at this time last year. About 2/3 of all Marcellus production in Pennsylvania is flowing into TGP. As you know, we have $1 billion of expansion projects in process in Northeast Pennsylvania. They will significantly increase our takeaway capacity to help keep up with Marcellus production growth. Another trend also on SNG, note that despite the more normal winter weather, power gen loads increased up over 10% continuing a trend that we've now seen for the last couple of years. On our Rockies pipes, throughput decreased, generally WIC and Cheyenne Plains volumes were down due to slightly lower Rockies production and lower overall exports out of the region. CIG was also impacted by this, but much colder weather along the Front Range helped to offset it. Finally, on EPNG, throughput was down mostly due to higher withdrawals from storage in California this winter. This backed out interstate transport into California. But importantly, we see signs of increased throughput in the Southwest with the beginnings of an economic recovery there. So across the country, some ups and downs, but overall, flattish throughput. Also on EPNG, Slide 12 describes a meaningful new expansion project. This is to serve 2 new power gen plants in Mexico in the state of Sonora. EPNG will provide firm transportation, 185 a day, on our mainline and lateral that extends to the Mexican border. From there, third parties will transport the gas to the plants. This service will start in 2013, and we'll spend $18 million to upgrade the lateral. It means over $30 million in annual revenue for EPNG, which had EBIT of just over $200 million last year as a point of reference. This is the first in what may be more opportunities to serve growing exports to Mexico. As Doug said, between EPNG and TGP, today we transport about 3/4 of the 1 B a day that is exported to Mexico. We and most consultants expect those exports to double over the next several years, as Mexico turns to gas-fired power gen and as Pemex emphasizes oil production over gas. EPNG is particularly well positioned for this business. So while EPNG remains the most challenged of our pipes, we see some tangible signs now of improving market demand long-term. Slide 13 summarizes our big slate of expansion projects that will complete this year. With FGT VIII complete, the next one to go in service will be the second phase of the SNG expansion for Southern Company. It will go in service on June 1. It's on time and likely will be under budget. As you may recall, this expansion serves a newly converted coal plant of Southern's. It's a 2,500-megawatt plant. Then, next comes Ruby. I'll take a minute here to add some color on current construction activities on Ruby. We are nearly 90% welded out. We have about 80 miles left to complete, all in the western end of the route. About half of this 80 miles is in Western Nevada and half in Oregon. As we said on our last call, we largely shut down our Spread 5 in Western Nevada in March and April for the sage grouse mating season. Just recently, we brought back the pipe gang there and have restarted welding activities. And when the mating season ends on May 15, we'll resume construction on those restricted areas. During April, we also pulled most of the crews off our spreads in Oregon to let the right-of-way dry after a very wet weather in March. We're going back to work right now on that section. In the interim, we've completed most of the critical stream crossings in Oregon, which is a significant accomplishment. Outside of these areas that are on the western end, Ruby is very nearly complete. We expect to purge and pack the entire eastern portion of the pipe in May. Also, construction of the compressor stations is now over 90% complete, and commissioning is well underway at the Big Head Station at Opal. So the finish line on Ruby is in sight. Now as we get back to work on the western end, we'll know more about our progress toward final completion by the time of our Analyst Day at the end of the month. After Ruby, in the fourth quarter we'll complete 2 more projects. The LNG terminal in Pascagoula and our TGP Line 300 project across Pennsylvania and New Jersey. Both of these are fully subscribed with long-term contracts. So by the end of the year, essentially all of the original $8 billion backlog will be complete. Our focus at the pipes remains very clear, it's to complete these projects successfully. And with that, I'll turn it over to Brent.

Thanks, Jim. Good morning, everyone. I'll begin today on Slide 15. And I also plan to keep my comments fairly high level and focused on the quarter, and then share more detail in New York on the 24th. After a strong finish to 2010, we're off to a great start so far this year in E&P. We continue to grow production, and the Haynesville core continues to perform very well on the gas side. And at the same time, oil and condensate volumes are rising fast, up roughly 24% year-over-year, consistent with our increase in oil-directed CapEx. And even though we are seeing cost inflation in many aspects of our business, our teams have done a great job of mitigating most of those costs, including drilling, completion and production operations by continuing to increase operating efficiencies. We're actively advancing our Eagle Ford and Wolfcamp oil programs, and the news is good on both fronts. We've delineated our Eagle Ford central acreage, so we now know what we have there, and the results have been at or above our models. Our early West Texas Wolfcamp drilling results are also encouraging. So far this year, we've drilled and completed 3 wells, which has told us a lot about our acreage. What seemed like a big step out just last September is shaping up to be another core program for us. We're on a steep learning curve, but we still like what we see in the Wolfcamp. And going forward, we'll continue to utilize the same approach that's proven successful in the development of our Haynesville and our Eagle Ford Shale programs. So turning then to Slide 16. We are pleased with our Q1 production and operating cash cost results. Our production was $821 million equivalent per day for the quarter, which is up 5% from last year and 3% from the fourth quarter. Again, liquids were up 18% from Q1 of last year. Cash costs were down $0.03 to $1.85, and that's primarily driven by higher volumes. And while there's been a lot of recent discussion regarding inflation of drilling and completion cost, it's also a cost pressure on the operating expense side, so reduce in unit cash cost is a big win for us. We have a pretty good example of how we are overcoming service cost inflation on Slide 17. The example shown is a fully completed Haynesville well, which is our most mature shale program. We began the year with completed well cost of about $9 million, well below the $10-plus million level for many of our peers. Drilling cost began to rise, as we increased the average lateral links and as rig rates have increased, but we fought off those increases with a 3-day reduction in drilling time. On the completion side, while we have a dedicated frac crew, there's still some costs that are being passed through such as some of the pumping cost, fuel and other non-pressure pumping completion cost. To offset those increases, we were able to reduce the time it takes to complete the wells. We're now pumping up to 5 frac stages per day. And I believe that many others in the play would consider 3 to 4 in a day to be a good day. In addition to the cost savings, the improvement efficiency also results in one additional well coming on production each month, which also contributed to our Q4 and our Q1 production results. Overall, our asset and our operations teams have done a great job of creating a continuous improvement culture and coming up with new ways to gain efficiencies across the board. Let's turn to the Eagle Ford on a -- with an update on Slide 18. Doug shared an overview of what's taken place in the Eagle Ford. But to expand a little, we currently have 4 rigs working in the play. They're all in the central area in La Salle County, which is up from 2 that we started the year with. And we've now fully delineated our central position, so we are very much in the pilot phase in the northern areas. And as you'd expect, we don't have much activity planned in the dry gas area in the South. We're still treating the southern area as a call option on higher gas prices. And we're working hard to deliver the same kind of cost efficiencies here that we're delivering in the Haynesville. On Slide 19, we provide a few more details of the central area. And remember this area, we expect 75% of recoverable reserves to be oil. We drilled 30 wells here, and we drilled them across the block, as you can see from the green dots, so we're developing a very good understanding of the well performance and our acreage position. As we learn more, we think we'll have the opportunity to move to even denser space and perhaps 80 or 100 hundred acres versus the current 120-acre space. And we're piloting that concept this year. If we're proven right, then we'd expect to drill more wells in this area and significantly increase our recoverable resources. Our productive capacity is growing rapidly, and along with Mark and in the Midstream company, we are actively building in-field infrastructure, which will result in a step-up in production rates later this summer. We're pleased with our results today, and we'll definitely spend more time laying out our Eagle Ford story in a few weeks. So let's move on to the Wolfcamp. We've included a map on Slide 20. Last summer before we bid on the university lands, we drilled a pilot well in the eastern side of our position. That well provided us with subsurface core and log data that gave us confidence to spend $180 million on land and to get into the play early, at least in this part of the play. And so far this year, we drilled and completed 3 wells, which are shown as red stars on the map. And as you can see, as you go across -- they go across our entire acreage position that spans roughly 35 miles. And we'll show you more of the technical subsurface data in New York, but we found a very consistent high-quality Wolfcamp section across this area. We're in the early days of the program and much optimization work remains, but everything that we've seen confirms the view that we showed you back in November. At that time, we showed a single average well model across the acreage, but we'll likely start to discuss a couple of different models from east to west as we continue our appraisal drilling. But overall, the models will be in line with our average type well. We've added a second rig in Q1 and will likely stay at this level for the remainder of the year. One very important development since our last call is we've now finalized unitization agreements with the university land office, where we've created 4 drilling units on the acreage that we picked up last September. And what this means is, instead of having a bunch of 640-acre section-size three-year term leases, we've now combined our leases to create groups of leases or units that we can hold by drilling for up to 7 years. Now forming these units is an example of the benefits of having all of our leases with a single co-development land owner. Turning to Slide 21. I can't resist including a little science. On the right-hand side of the chart is a picture of a whole core section from one of our wells. Now we normally think of shale as dense, silt or mudstone type of rock. But remember that we said that the Wolfcamp source rock in our lease area has high quartz and high carbonate content. So it has some of the same rock characteristics as conventional reservoirs. Now granted this is a significantly magnified view, but the black dark areas that you see are nice-looking pore spaces, pore spaces that can hold a lot of oil. And we see that kind of quality rock vertically up and down throughout the Wolfcamp shale section. On the upper left, we summarize our originally assumed Wolfcamp geologic and petrophysical parameters, and we've included the results so far from our first 4 wells on the right side of the table. All of the values in the table are for the entire Wolfcamp section. To date, we've only targeted the upper Wolfcamp, which is a little over half of the total thickness. And our published type curves and their future inventory only include the upper Wolfcamp section. All told, though, we are finding thicker sections and more net pay. The average porosity is higher and the organic content is very good. So we have a very nice looking interval, which is also why we see an industry competing aggressively to get into this part of the play. We've included some early production stats on Slide 22. We've tested 4 wells. The 38-29-1H was our pilot well, which we're only able to frac with 7 stages over a 2,000-foot interval, but achieved -- it still achieved good initial test rates. We've been experimenting with lateral length and a number of frac stages, and our last 3 wells have all tested nearly 300 barrels per day plus the associated gas. And the greater amount of gas in the oil has been positive. It's good news because it provides energy for more oil to be able to move to the pore spaces. But as we've discussed before, these wells also go on artificial lift almost immediately, and so more gas makes the pump selection a bit tricky. So pump design and a post-frac, flowback rates are also through the areas that we're optimizing. We also have 2 wells nearing completion, shown on the bottom of the slide. One of them is a 7,000-foot lateral, and we plan to complete it with 24 frac stages. So I'll wrap up on Slide 23. While it's admittedly early days for the Wolfcamp program, and we still have a lot to learn, we're encouraged by the results of our pilot wells. The highest value items that we'll be optimizing include lateral links, the density or frequency of the frac stages, the artificial lift options, optimal initial producing rates and the facility design. And we are also considering drilling a vertical well this year to test the entire Wolfcamp section, including that lower portion. So I've covered a lot of high points for the quarter this morning, and I'll expand all of these discussions further on the 24th. But again, we're pleased with our execution so far this year and the way that our programs are advancing. And I'll now turn the call back to Doug for closing comments.

Thanks, Brent. We were successful in carrying our momentum at year end through the first quarter, and the businesses are hitting on all cylinders right now. We're delivering on all the elements of our plan for 2011, and most of them are ahead of schedule. Our financial strength continues to grow, and we anticipate that trend continuing, as we continue to grow El Paso Pipeline Partners, our MLP. All this means that we're very excited about what we can accomplish this year. We are looking forward to being with all of you in New York later this month, where we intend to take a deeper dive into each of our 3 businesses, update our guidance for the year, and lay out the long-term strategy for the company at what is one of the most exciting points in our history. Operator, with that, we're happy to open it up to questions this morning.

[Operator Instructions] Your first question comes from Faisel Khan at Citigroup.

On the Wolfcamp, I wonder if you could give us just a little bit more color on kind of well cost. And then also on what looks to be kind of a diminishing kind of margins of returns, as you kind of extend the lateral length and the number of the stages. And maybe you can also tell us what you guys think of kind of EURs per well at this point in time would be helpful.

We're going a lot more detail later in the month, Faisel, but we really haven't changed our model. If you look across the play, there might be a little gas here on one end than the other, but our EURs are going to be very comparable and the economics are going to be very comparable. And cost are right at a midpoint of the range that we've given you in the model before. So I think the lateral length is part of what we are optimizing with a number of fracs, and I don't think we'll necessarily see a degradation in the value, it will likely go up because we're going to get incremental oil per stage, we think, and we're going to get a good test to that with that 7,000-foot lateral and 24-stage frac. So I think we'll be optimizing and trying to find the best value proposition, but I think it will go up as we increase the lateral lengths, not down.

Okay, got you. So everything is kind of trending the way you guys had talked about beforehand?

It really is. That's the key message, I think, is everything we've found in the first 3 wells has confirmed what we thought going in. We got a thick, porous, all-saturated section. And that's a good place to start in one of these kinds of projects.

Your next question comes from Carl Kirst at BMO Capital.

Just broadly speaking on the E&P and understanding we're not going to get the details here until the Analyst Day. But as we look at the capital expenditure budget, it's not just sort of the Eagle Ford JV or lack thereof that we have to blend in, but the fact that clearly we have a much more robust oil market. And so I guess maybe the question is, how much cushion do you think you guys have to continue shifting more towards an oilier drilling inventory budget, if you will. You're moving that $1.3 billion higher. Is it something 10%, 23%? Is there any color you can add to that?

Carl, this is Doug. I think you hit on the issues that we are grappling with now and expect to conclude this month and report on, on the 24th. And that is operationally, we are ahead of where we thought we would be right now. Commodity prices are higher than we thought they would be year-to-date. And we're slightly ahead of where we thought we would be with regard to the MLP year-to-date. And so as we think about the fact that we did have a JV in our plan for 2011, we are grappling with what -- when you roll all that stuff up together, not just oily E&P, when you roll all of that together, how do we reapportion capital for the balance of the year? And that's where we'll be going into detail on the 24th. The short answer, I think that's going to be good news. If I could just add one thing, Carl, that the spread again, that we don't want to declare victory after the first quarter, but what we've seen so far is we're holding the line against service cost inflation. So if we do increase capital, it will be activity-driven, not necessarily -- not a response to higher cost. We're managing those with some of the efficiency gains that we tried to highlight with that one Haynesville well here.

Point well taken. One other question, if I could, more for J.R., and this is a bit of a false objective question here. But how are you viewing the MLP market right now? You've got sort of 2 to 3 drops baked in your plan. We had a successful recent drop. We kind of are getting a little bit of some -- I don't necessarily want to call it dislocation, but some concerns coming up on the tax side. Do you see any risk to being able to achieve that 2 to 3 drops this year?

Karl, despite the recent softness, really, just over the last couple of days, I still feel very good about our ability to accomplish our 2 to 3 drop down objective that we have baked in the plan. Really the tax noise coming out of one of the trade associations is not new, I don't think. It has been a focus. We think the probability of something being done here in the near term is very low. I think when you think about the tax aspect, you also got to think about the role that MLPs play in the midstream infrastructure space, and how what a critical role they play. I think you also ought to think about who owns MLPs, as well, being individual retail investors. So I -- well, I feel good about, absent just the last couple of days, impact on MLP price. And I feel really good about being able to finish 2 or 3 more this year, or 2 or 3 in total for the whole year.

Your next question comes from Bradley Olson at Tudor, Pickering. Brad Olsen - Tudor, Pickering, Holt & Co. Securities, Inc.: On your Eagle Ford slides, the rigs still look as though they're kind of in that core area that you guys have talked about, how you're pretty far along in delineating that acreage. Do you guys have any internal targets about when you might return to Frio, or the more oily area of the Eagle Ford, to test that area again?

Well, if you think of them, kind of break it into the 3 parts, we think that essential area is essentially delineated, or fully delineated today. And it is oily, right. It's 75% oil in that area. We're off to full scale development in that part of the play. The Frio County area, we'll do some more testing in the northern areas, and we'll watch closely what the industry is doing, but it's going to stay in the pilot phase throughout this year and maybe even in the next. And in the gas, we're going to do very little activity there and hold that for a longer-term higher gas price option. So that's exactly how we're thinking about it. Most of the rest of the capital this year is going to go into Central. Brad Olsen - Tudor, Pickering, Holt & Co. Securities, Inc.: Okay, great. And just one follow-up. One thing about the Eagle Ford JV, not to put words in you-all's mouth, but when thinking about the fact that you guys declined the Eagle Ford JV, I mean is it reasonable to think that you guys are looking at the MLP drop-down strategy and thinking about proceeds from MLP drops, as perhaps supplanting the proceeds that you might have gotten from a hypothetical JV?

I think it's fair to say that in the course, when we started out looking at the possibility of a joint venture, it was really at the corporate level at financing mechanism for our business, and several things have happened since then. Our balance sheet has improved at a rate faster than we would have anticipated when we started. We got further along in the delineation of that acreage than we thought at the time, and commodity prices went up dramatically. And so, yes, in some level I think you would say, our view of the cost of capital of that financing, relative to the cost of capital of other financings, including the net cost of capital to us from MLP financings, was just high enough, enough higher enough than our other alternatives that it didn't make sense for us to do. Brad Olsen - Tudor, Pickering, Holt & Co. Securities, Inc.: All right, great. That's it for me.

Your last question comes from Craig Shere with Tuohy Brothers.

A couple of questions on Carl's question about turbocharging investment and the accretive liquids plays even without the JV. Can you comment on the level of commitment that was discussed over the last year and a half or so towards free cash flow in 2012? And then a couple more quick questions after that.

We haven't changed our commitment for 2012 at all, and we won't. You shouldn't expect us to on May 24.

Great. And I think on the last call, J.R. may have noted that you would need to change the JV structure from a C corp. to a partnership arrangement for FGT before considering any of that for a drop down. It's probably one of your most attractive fee-based growth assets with the highest cost basis following the buildout. Can you discuss what process and tax implications might be involved in moving that to more of a partnership structure?

No, Carl, I really don't have any other color to add. What I said was is, to have it be more efficient, it would need to be in a different vehicle than it is today. But we've got a very large portfolio of assets at the Pipeline Group to choose from, many of which have good solid growth profiles as well. So we really don't have anything to add to my comments from the last call.

Okay. Last question, Jim, on Ruby. I know that there's going to be a lot more known in the next 3 weeks or so, but can you handicap the ability to stay within the prior disclosed, I think it was roughly 20% aggregate cost overruns from the original guidance?

Yes, I think what I'd say there is that, really, we're down to the end here. The scope of work left is small. We have probably $300 million or so, plus or minus, left to spend. So the chances for a material increase or decrease and the estimated capital is probably low. If there's been any new news over the course of the last couple of months since our last call, it's been that we suspended operations on the very western end as a result of the wet weather. And so that becomes more on the critical path, together with the Spread 5 in Western Nevada. We’re starting up both now. And I think we will have a lot more information over the next few weeks.

At this time, I'll turn the call back over to the presenters.

Okay. Thanks for joining our call. We look forward to seeing you in New York on the 24th. And thank you very much.

This concludes today's conference call. You may now disconnect.