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Executives

Bruce Connery - Vice President of Investor and Media Relations

Brent Smolik - Principal Executive Officer, President, Director and President of ConocoPhillips Canada

John Sult - Chief Financial Officer and Executive Vice President

Douglas Foshee - Chairman, Chief Executive Officer and President

James Yardley - Chairman of the Board of El Paso's Pipeline Group, Chairman of Southern Natural Gas Company, Chairman of the Board of Tennessee Gas Pipeline Company, President of El Paso Southern Pipeline Group and Executive Vice President of Pipeline Group

Analysts

Rebecca Followill - Howard Weil

Theodore Durbin - Goldman Sachs Group Inc.

Craig Shere - Tuohy Brothers Investment Research, Inc.

Carl Kirst - BMO Capital Markets U.S.

Stephen Maresca - Morgan Stanley

Brad Olsen - Tudor, Pickering, Holt & Co. Securities, Inc.

El Paso (EP) Q2 2011 Earnings Call August 4, 2011 10:00 AM ET

Operator

Good morning. My name is Kirsten, and I will be your conference operator today. At this time, I would like to welcome everyone to the El Paso Corporation Second Quarter 2011 Earnings Conference Call. [Operator Instructions] Mr. Connery, you may begin your conference.

Bruce Connery

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 3 other speakers on our call this morning: J.R. Sult, our CFO; Jim Yardley, Chairman of our Pipeline Group; and Brent Smolik, President of El Paso Exploration and Production Company. Mark Leland, President of our Midstream Group, is here as well, and he'll 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, elpaso.com. Also on our website, you will find a financial and operating reporting package that includes information that we believe will be helpful, as well as GAAP financial statements and non-GAAP reconciliations.

During this conference call, we will make a number of forward-looking statements and projections. We've 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 a 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. [Operator Instructions] I'll now turn the call over to Doug.

Douglas Foshee

Thanks, Bruce. I intend to keep my comments very brief this morning. We told you when we announced the separation in spin of our E&P Company back in May that we'll do 2 things: get the spin done by year end; and not take our eye off the ball in terms of execution in our 3 businesses. I think we've done that, and we hope to show you the evidence in today's call. We had a good second quarter. Earnings and cash flow were up and the business units performed well operationally. We've moved much closer to completion of our $8 billion backlog of growth projects at the pipes. Ruby's now in service and our other 2011 projects are on track.

In E&P, production is up, costs are down, and we continue to make progress in all 4 of our core areas. Midstream had a good quarter and made meaningful progress in moving the Marcellus Ethane Pipeline project along with a very successful open season. And finally, we completed another drop to the MLP during the quarter, once again using the proceeds to accelerate our balance sheet improvement as we move toward the separation prior to the end of the year.

On the separation front, we continue to make great progress. The management teams and boards for the 2 separate companies are now in place. We filed for our IRS tax ruling, we're very close to filing the Form 10, and we're completing the various required separation agreements. Each of these is in the critical path to the spin and each of them are on track. We're also moving towards finalization of the capital structures for both entities. So all of these is to say that there are a lot of work streams going on internally, but all of them are pointed toward completion by year end, and we remain on track for completion as originally contemplated. One final note before I turn it over to J.R., as you can see on Slide 4, we've completed our review and established the boards for the 2 companies post-spin. I'm delighted to report that we're able to populate both boards from the existing El Paso board, and we believe we'll create 2 outstanding well-governed boards, a key prerequisite to each company's success going forward. Now I'll turn the call over to J.R. and come back at the end to wrap up.

John Sult

Thanks, Doug, and good morning to everyone. Thanks for joining us. We had another active and very productive quarter as we continue to make great progress, both financially and operationally. Our progress to date in 2011 puts us in good shape to meet our full year financial goals. I'll briefly cover the financial highlights for the quarter, starting on Slide 6, and then Jim and Brent will update you on our operational progress.

Back in May, at the Analyst Meeting in New York, we talked a lot about the importance of our MLP drop down strategy and how the success of that strategy contributed to our ability to pursue a strategic separation this year, far sooner than even we would've thought possible back at the beginning of 2010. I hope you would agree that we've kept the RPMs running high on our MLP, maintaining an accelerated pace of drop downs through El Paso Pipeline Partners. During the quarter, we completed another drop to the MLP, our second this year and seventh since our IPO. The transaction raised nearly $750 million in cash for El Paso, bringing our year-to-date total to $1.4 billion, nearly $1 billion of which in new MLP equity capital. We're using the cash to reduce El Paso corporate debt and hopefully you saw our press release last week announcing the early results of our most recent liability management program. And although the tender and companion Dutch option are still in progress, we're confident we'll complete the entire $750 million transaction, further accelerating our balance sheet improvement.

While not so much a stated goal for 2011, a key goal for the finance team was to refinance our 3 primary credit facilities at El Paso Corp., El Paso Pipeline Partners and El Paso Exploration and Production, We did just add during the quarter. The very successful transaction involving over 20 financial institutions participating across all 3 facilities. The maturity dates of our $3.25 billion in aggregate credit have now been extended to 2016. The new facilities provide significant flexibility and position all 3 companies to successfully pursue their individual growth strategies.

Finally, with Ruby's successfully in commercial operation, we anticipate meeting the conditions in the financing agreements that will result in the $1.5 billion of project debt becoming non-recourse to El Paso in the next 60 to 90 days.

So let's turn the page and run through the numbers beginning on Slide 7. We reported adjusted diluted earnings per share of $0.25 for the quarter, compared to $0.22 last year.

Higher segment earnings before interest and taxes from our core businesses, lower interest expense, the lower effective tax rate contributed to the increase. Our effective tax rate for the quarter on a GAAP basis was 10%, reflecting the favorable impact from the resolution of certain tax matters. Excluding these items, our effective tax rate for the quarter would've been 14%. As highlighted on previous calls, you should expect our effective tax rate to remain lower than prior years as we continue to drop more and more assets into our MLP.

Adjusted segment EBIT was up just over 2% for the quarter, driven by increases in both Pipelines and E&P. Adjusted segment EBIT for the Pipeline Group was up about 9% from a year ago, reflecting completed expansion projects going into service, higher non-cash AFUDC, principally from Ruby, and a benefit related to a customer's election not to continue with Phase B of our Elba III expansion project.

In E&P, adjusted segment EBIT was up slightly for the quarter as a result of higher production volumes in crude oil prices, offset by lower realized natural gas prices and a higher DD&A rate.

Turning to operating cash flow and capital investment on Slide 8. We remain on track with our 2011 guidance for both. Cash flow from operations for the 6 months was up 11% from last year due to higher E&P cash flows, lower interest payments and positive working capital changes.

On the capital side, you can see the Pipeline spending ramped up from last year with Ruby as the largest consumer of capital. We're also nearing completion on our TGP Line 300 project, as well as Gulf LNG, which Jim will update to you on shortly.

Growth capital spending on the Pipelines will continue to decline in subsequent quarters this year as we near the completion of the original $8 billion backlog. I expect the Pipeline Group to transition from being a consumer to a provider of free cash flow beginning in the fourth quarter of this year.

In our E&P business, spending was up for the quarter, reflecting higher activity levels in our Eagle Ford oil program. And Brent is going to give you an update in just a few minutes on our non-core asset divestitures, which will more than adequately fund the increase in the Eagle Ford drilling and completion capital we announced back in May.

Now I'll wrap up with my usual update on our hedge program on Slide 9. We continue to have an advantage hedge position particularly for the remainder of 2011. We remain well protected from low natural gas prices for the balance of the year with 80% of our second half 2011 gas volumes hedged at an average price of $5.89, substantially above current market prices. We added on the margin to our 2011 positions since our May meeting but have made no changes for 2012. Our hedges have been a key contributor to our E&P financial success this year in the current low natural gas price environment with settlements adding $140 million to adjusted segment EBIT and operating cash flows this year.

That's my update for you this morning. I'm proud of the progress to date in 2011 and look forward to updating you periodically the rest of the year. With that, I'll turn the call over to Jim for an update on the Pipeline Group. Jim?

James Yardley

Thanks, J.R. The pipes delivered another very good quarter. Pipeline financials continue to reflect our expansion mode, a nice growth in EBIT, some due to noncash AFUDC, as J.R said, also substantial CapEx spend. The completion of Ruby is a major milestone for us, obviously. And we're well on our way now toward completing our big slide of growth projects scheduled for this year. In the fourth quarter, we'll complete our final 2 projects as planned. We settled the major rig case on CIG this quarter. That's a very good settlement for both our customers and us. It extends customer contracts and it provides great certainty most likely for the next 5 years.

Separately, on the rate case front. As you know, we have rate cases ongoing on both TGP and EPNG. I don't have much news on either of these and a settlement discussions at an early stage. Finally, as we've said at the New York City Analyst Day, we continue to see meaningful, new pipeline growth opportunities centered mostly on gas-fired power gen and the new shale plays.

Slide 12 summarizes throughput trends this year versus last. Overall, up 2% year-to-date. TGP is having a record year, through put up 21%. A lot of this is due to increasing Marcellus production. Marcellus receipts into TGP are now 1.5 Bcf a day, up for about 0.6 Bcfe a day a year ago. And TGP has in hand over 1 Bcfe a day of fully subscribed expansions in Northeast Pennsylvania to be completed over the next 2 years. So we'll continue to get our share of Marcellus' growth, and TGP is well positioned to further expand.

SNG throughput reflects more normal winter weather this year after a very cold early 2010. Powergen loads on SNG continue to increase each quarter, up 13% year-to-date. Throughput on our Rockies pipes is down this year due to slightly lower Rockies production and lower exports out of the region.

On EPNG, as you know, EPNG is our most challenged pipe due to pipeline overcapacity in the Southwest. Throughput this year had decreased mostly due to higher withdrawals from California storage fields this winter. This backed down interstate transport into California. But on the positive side, we see signs of the beginnings of an economic recovery in the Southwest, also as expected, increasing exports to Mexico.

So across the country, some significant ups, mostly on TGP, offset by some downs, overall up 2%. The next 4 slides speak to our progress on the expansion front. As you know, completing these projects is our primary focus this year.

Slide 13 shows that we've now completed 3 of the 5 projects planned for in service this year. And since our last call, the second phase of the SNG expansion for Southern Company was completed under budget -- nearly 20% under budget. And of course, Ruby, completed last week. And more on Ruby on the next slide. But before going there, when we finished the 2 other projects this year, we would've substantially completed the original $8 billion growth backlog. In total, during the last 5 years, we will have completed 19 projects within 7% to 8% of budget, a track record significantly better than our industry peers. And x Ruby, the other 18 projects are right on budget in total. Importantly, these projects are approximately 90% subscribed with long-term contracts, so they will generate highly predicable cash flow.

On Ruby, we're in service and flowing gas for customers. In these first few days of August, Ruby has been flowing between 400 and 480 a day. Our results on Ruby construction, it was completed 4 months later than we original planned back in 2008. And it will be 23% over budget at our projected completion cost of approximately $3.65 billion. The general reasons for this have been well-documented: significant permanent challenges; building through a wet winter; and dealing with various fishing game habitat or nesting issues.

But I owe it to our project team to take a minute to give a little bit more flavor for the scale and complexity of this construction project. Ruby is the largest U.S. natural gas pipeline project since the REX Pipeline, at $6.8 billion, it was completed in 2009. And here are a few stats for you on Ruby. Before beginning construction, it took a whole 2.5 years to move Ruby through the review process with BLM, FERC and the various federal state local state and local agencies. At peak construction, nearly 5,300 people were working on Ruby. Pipe was produced in India, Arkansas, the Gulf Coast and France. It was moved west in 110-unit trains, each up to 1 mile long. Ruby was constructed at elevations up to 8,800 feet and at grave slopes up to 14%. Oregon rainfall was 50% greater than normal, February through April of this year. At one point, we had over 200 archaeologists in the field. We avoided impacts to over 100 safe grass lacks [ph] 1,600 migratory birds' nests, and there was no taking of any threatened or endangered species. We crossed and restored over 1,100 wetlands and streams, all in accordance with government reqs. Along the way, 8 lawsuits were filed to stop Ruby construction. So we're over budget, no excuses. At the same time, our team dealt with several obstacles professionally and for the most part successfully to bring Ruby to completion. We also learned a lot to use on future projects. So to the Ruby team, I want to say a very big thank you.

Looking forward, much of the long-term macro for Ruby remains in place. The Rockies represents a huge resource base that needs to get to market, and the West Coast markets pre-Ruby are heavily dependent on Canadian gas. And Canadian exports to the U.S. are declining, down another 700 a day this year-to-date versus last.

While Rockies production growth may be slower than would like to see, as we've said before, Ruby is a long-term strategic asset for El Paso, for Rockies producers and for supplied diversity on the West Coast.

On Slide 15. Our next project to go in service will be Gulf LNG, our jointly owned rig gas facility in Pascagoula. It's on time and on budget. We took in 2 LNG cargoes in June to start the cool down process, and this is a major milestone toward in service. It's important to remember that this project is fully subscribed with long-term contracts, and these contracts are demand-chartered based so that our profits here are not dependent on the utilization of the facility.

Finally on Slide 16. In June, some of you visited our TGP line 300 expansion in New Jersey. Construction is in full swing across both Pennsylvania and New Jersey. It's on budget and on time for completion this November. We're using 4 spreads, the right-of-ways about 90% cleared now, and we're nearly 50% welded up. A very long directional drill over a mile has just been completed. It took about 9 months as planned. And our compression work at 9 different stations is coming along very well. This project will provide 350 a day of additional forward hull capacity out of the Appalachians and Marcellus and is fully contracted long term.

So in summary, we're focused on completing the remainder of the backlog this year. And then with the backlog complete, the pipes' transition from cash user to a significant cash provider. And given our pipelines' footprints in the very best markets and supply basins, we have excellent opportunities for more growth. And now I'll turn it over to Brent.

Brent Smolik

Thanks, Jim. Good morning, everyone. It's been just a little over 2 months since our Investor and Analyst Meeting, and since then we've continued to make good progress in E&P on a number of fronts.

I'll begin to update on this morning on Slide 19. As J.R. noted, we had a very good quarter with a 7% increase in adjusted EBITDA, again primarily driven by higher production, higher oil prices. Production was up 4% from last year's second quarter, even though we had to deal with the impact for some third-party downstream disruptions that I'll cover more in a moment. And in spite of those disruptions, our 2011 production target's still very much on track. Well, I can say volumes were up 5% for the quarter and they'll continue to ramp up significantly in the second half of the year. And we've included a chart that shows our Eagle Ford program, how our Eagle Ford program will contribute to that growth.

Unit cash costs were down again, $1.75 versus $1.77 in Q2 of '10. Lower is always better in this metric, but I'm especially pleased considering the cost inflation and our shift to more oil volumes.

Maybe the biggest E&P highlight for the quarter was flowing back our first 7,000 foot ladder in the Wolfcamp, which looks like a very nice well. We're right on track in our Eagle Ford program. And we've drilled another 14 wells since our May Analyst Meeting, all in the central area. And our productive capacity is increasing, and our infrastructure build-out is going very well. In aggregate, we continue to minimize our service and our supply cost inflation with efficiency gains, and our $1.6 billion capital program remains on track.

As Slide 20 shows, our second quarter production came in at 823 million a day. That's up 4% from a year ago. The most significant gains came from our Haynesville and our Eagle Ford programs, just as they have in recent quarters.

We also experienced a couple of notable production constraints in the quarter. In the Gulf of Mexico, a Coast Guard dredging operation contacted an in-bridge line in the West Cameron area, and the resulting shut-in impacted the quarter by about 12 million a day. And unfortunately, those repairs are not scheduled to be complete until early in the fourth quarter.

In the northwest part -- northeast part of our Haynesville area, we sell some gas through a third-party plant that experienced extended unplanned downtime during the quarter, which impacted our quarter volumes by about 5 million a day. And the message I want to leave you with those is that our underlying production assets and our capital programs are performing very well. And absent these third-party disruptions, our second quarter volumes would've been up closer to 7%.

On Page 21, there's a summary of our current divestiture program. As J.R. mentioned, back in May, we announced that we'd raise our capital budget from $1.3 billion to $1.6 billion largely to cover our incremental net interest in the Eagle Ford or incremental oil activity, and that we'd fund that increase through non-core asset sales. We now believe that the divestiture -- the proceeds will be well above the $300 million capital increase. All the assets that we're selling are non-core and it's very consistent with the type of portfolio high-grading that we've done over the last few years. We've already closed $122 million of divestitures, and we have 2 others that we expect to get done either late in the third quarter or early fourth.

The sales included about 200 Bcfe of proved reserves and about 35 to 40 million a day of current production, but the full year impact of that production will be more like 15 million a day. And the size and the timing of the divestitures and the timing of these downstream repairs will impact where we end up in the range, but we still expect to be within our guiding range of 830 to 860 million a day. Now we've included a quick update of our drilling plans for the remainder of the year on Slide 22.

Now, we'll operate around 12 to 14 rigs for the rest of the year, which is fewer than we expected at the beginning of the year, but for the right reasons. Because of the drilling efficiencies, we're getting more footage and more wells drilled with fewer rigs. So for example, back in May, I said, that we may need one less rig to accomplish our planned Eagle Ford program and that will be the case. We'll likely stay at 3 rigs for the second half of the year. We'll run 2, 3 rigs in the Altamont field, a couple of rigs in the Wolfcamp program, and we'll keep 4 rigs running in the Haynesville. And then we could add a rig or 2 late in the year, depending on how capital goes and then step up further in 2012.

And unless something in the macro environment changes dramatically, expect any of the incremental 2012 activity to again be oil-focused. So the punch line is that our drilling team continues to outperform our expectations in our core programs, and we're right on track for our total $1.6 billion capital program.

So let's focus in on the Wolfcamp program beginning on Slide 23. Now, this is an update of the map that we showed back in May, our record shown in orange. And so if you look back at that prior versions, you'll see quite a contrast from -- between then and now. For starters, we're now drilling our 10th and 11th wells. And also back in May, there were only 4 total rigs working in the area, and today there's almost 30. Many of these are drilling longer laterals generally greater than 7,000 feet, and we continue to see a few operators doing vertical wells. And we also plan to drill 1 or 2 vertical wells this year. And we still believe that long laterals is going to be the way to go. But remember, we have a very thick Wolfcamp section, up to 700 feet thick, so we want to gather data on the entire section and test the potential of vertical wells on our acreage, before we fully commit to horizontal development.

I mentioned that we had very good results in our first long lateral Wolfcamp well, and we've included the test results on Slide 24. That's the well shown in the bottom row. The university 43 19-1 horizontal was drilled with a 7,100-foot lateral and is completed with 24 stages. The 660 barrel per day equivalent test rate is right in line with our predictions. We're now completing our second 7,000-foot lateral well, and we're optimistic about the results of that well based on what we've seen so far in the completion. So we're spending more for well than the 4,000-foot laterals, hoping for better production and better value, which is summarized better on Slide 25, where we show you our current view of the economics for the 7,000 to 8,000-foot lateral length wells. And we still expect initial production to be around -- to be the same, around 25 to 30 barrels per day per frac stage with the initial test rates approaching about 700 barrels per day on the high end of the range. And note that the return shown here assumed $80 and $4 flat pricing. But again, compared to our previous type well, the completed cost here will be higher but the initial production, reserves and project returns will all be improved.

I also want to update you on the Eagle Ford program this morning, and we've included a map on Slide 26. Now this isn't the same base map again that we used in May, but we've been pretty busy since then. The numbers on the table include 14 more wells drilled, 12 more wells completed and 15 more wells online and producing since May. We're also making great strides in our backlog of completions, and for a period in time in the quarter, we had 3 frac crews working in the field, including moving our Haynesville crew down to the Eagle Ford. And we currently only have 9 wells waiting on completions in fracs. And market has Midstream team continue to make dear progress in installing a gas gathering and a new oil gathering system in the field. In a moment, I'll show you that infrastructure timing will shape the production profile in the second half of the year.

Slide 27 includes an updated chart showing the IP rates for all of our Eagle Ford central wells. The point is about 10 of the wells or about 40% of the total have IP rates greater than 800 barrels per day equivalent. And as we continue to delineate the central area, our wells are consistently producing at or above our type oil. So we're quite happy with the outlook for this program. And remember, this area has -- this central area has between 600 to 800 remaining drilling locations depending on the ultimate well spacing.

Turning to Slide 28. We've updated our Eagle Ford production outlook for the rest of the year. The blue bar shows shut-in volumes, which are shut-in waiting on facilities, which will not be an issue by the fourth quarter. At that point, our gross production could to be up to 20,000 barrels a day equivalent, that's the far right bar in the graph. And we had previously projected that to be around 16,000 barrels a day at our meeting in May. Today, our net E&P productive capacity is about 7,700 barrels and 23 million a day, and it's growing rapidly.

So I'll wrap up today on Slide 29. There's a lot of excitement in the E&P Company. We're currently hitting our stride. Our teams are executing well, which shows up in the results of our core programs. Our oil volumes show terrific growth in the second half of the year, with the addition of the new Eagle Ford volumes. And as always, we continue to work hard to improve capital efficiencies. Service cost pressures haven't let up, so we keep pushing on every aspect of our business to maintain the efficiency of our capital programs.

Looking forward, we remain excited about our future opportunities. And although we have a healthy respect for our competitors, we think that post-spinoff, our performance is going to compete well with the best E&P companies. We've got a great drilling inventory, more than 10 years. It's very high-quality, very reputable and increasingly more oily. We'll be meeting frequently with investors and analysts in the coming months, and we hope to see many of you at our E&P and analyst meeting in New York on November 8 for a full update as we prepare for the separation.

I'll now turn it back to Doug for closing comments.

Douglas Foshee

Thanks, Brent. I hope we've left you with the impression that our businesses are running well as we deliver on our commitments to you for 2011. In addition, we continue to make material progress on the balance sheet. All this means that we're on track to not only get the spin done on time but also to create 2 well capitalized, well-positioned companies, each with a very good trajectory and each contributing to the creation of significant value for our shareholders. So with that, we're happy to open it up your questions this morning.

Question-and-Answer Session

Operator

[Operator Instructions] Your first question comes from Stephen Maresca.

Stephen Maresca - Morgan Stanley

One question on the drop-down strategy, and then one on the Northeast pipeline. So at what point do you guys start to eat into that NOL position that you have? How much longer can that last when you're thinking about years? Is that something where we should think about this as being there permanently or if you just drop down, you start to eat materially into that NOL position that you have?

John Sult

Steve, this is J.R. I think you should think of the NOL as still being a valuable asset to us for years. But there's no doubt that each time we do a transaction, it does generate an amount of taxable income that does eaten into our NOL. But I think you should think of the NOL as benefiting the corporation still for years to come.

Stephen Maresca - Morgan Stanley

Okay. And then my second one on the Pipeline side. Your feature growth in the Northeast, and Marcellus and certainly Utica is coming into focus from a bigger picture standpoint. What opportunities do you see potentially in the Utica with your assets going forward?

James Yardley

Yes, as a general statement, I think you saw of some of the Marcellus is getting early very fortunate. And that our pipeline effectively runs right through the middle of the Marcellus in Northeast, Pennsylvania. And so we're getting -- we have been getting about of 2/3 of all the volumes there. But likewise, into Utica, if you look at the map of Eastern Ohio, and try to plot out of that where the liquids-rich area is. On the Pipeline side, we couldn't what be in a better position. Our pipeline runs right through that area. So we expect to see if the Utica does pick up that we're going to be a primary beneficiary there. I think you're aware that we have -- and this is just on the Pipeline side, before getting to Mark's Midstream side, we have a significant access capacity through to Utica that we can -- so we can transport and pick up revenues with very little capital required.

Operator

Your next question comes from Carl Kirst.

Carl Kirst - BMO Capital Markets U.S.

Brent, this is actually just a clarification as far as the completion right now of the Wolfcamp that you mentioned, drilling 1 or 2 verticals. Is this really just the cost benefit of the vertical versus horizontal? Or is this aimed more at testing the lower Wolfcamp? Or those 2 not mutually exclusive?

Brent Smolik

Yes, primarily, Carl, data collection on the entire section. Remember we're drilling the horizontals in the upper Wolfcamp, and this is primarily about log core reservoir information on the whole section in the Wolfcamp and the shallower sections that we see out there, right? So there's upside potential. But ultimately, today we look at it, we think the 8,000 -- 7,000, 8,000 foot laterals look very appealing to us. But we want to make sure we get that right long-term. So we'll watch all the other vertical development out there, and if it makes more sense, we'll go that route. But today our preference is -- our lean is toward longer laterals.

Carl Kirst - BMO Capital Markets U.S.

Great. And then maybe one question, and this might be for either J.R. or Jim. But with respect to the Ruby, there was a comment made about I guess the $1.5 billion in the contingent test sort of going off in the next 60 to 90 days. Does that mean, say for instance, we might be getting third quarter results and Ruby is still consolidated, and I guess what I want to get to at the heart is just making sure our models are right as we inflect from AFUDC in the second quarter to actual earnings and cash results in the third quarter, recognizing that we have maybe a bit of a slow ramp right now. So I just want to make sure I've got that dynamic correct.

John Sult

Carl, this is J.R. You're absolute right. I mean, that's the way to think about it. With the commercial in-service state of Ruby, AFUDC, from the equity side and the debt side, ceases. As a result of the fact that we will not meet the conditions in the financing agreement for another 60 to 90 days, we will consolidate Ruby, continue to consolidate Ruby through the third quarter, and depending on when we actually meet those conditions, maybe for another month beyond that. It's once we meet those conditions that we will actually then de-consolidate Ruby. It will be reflective as an equity method investment, quite similar to the way we reflect Citrus. And so what that means from a Pipeline EBIT standpoint is that the -- both the interest expense attributable to Ruby as well as the return -- the preferred return attributable to bar [ph] partner will all be reflected as part of Pipeline EBIT going forward from de-consolidation on.

Carl Kirst - BMO Capital Markets U.S.

J.R., can you quantify what the AFUDC impact was for the second quarter?

John Sult

I think if you look at and you will see it, Carl, we've been disclosing consistently in our public filings the components of other income for the Pipeline Group, and in total, on a consolidated basis. It's reflected below operating income. I want to say, Carl, that the least that what they -- remember, I can remember off the top of my head is the increase quarter-over-quarter in AFUDC, this quarter is about $20 million, substantially most of which was related to AFUDC. But you'll be able to see that in the public filing.

Operator

Your next question comes from Craig Shere.

Craig Shere - Tuohy Brothers Investment Research, Inc.

A couple of quick questions. The benefit from BG opting not to expand re-gas capacity at Elba, how much was that benefit?

John Sult

Craig, it's J.R, on a net basis, it was about $14 million.

Craig Shere - Tuohy Brothers Investment Research, Inc.

Okay, great. And J.R., while I got you, I just want to understand, are you targeting sub-25% GAAP taxes? And is the trend in lower taxes simply an issue of consolidated EPB while the EPB public holders don't pay tax?

John Sult

That's the primary driver of it. And I know it's fair to say that you can think about the effective tax rate is less than 25%. It's heavily driven by the consolidation of EPB as a result of a noncontrolling interest. And this year, as I mentioned in my comments, both in the first quarter as we disclosed, as well as the second quarter, we had some favorable resolution of certain tax matters that benefited our effective tax rate.

Craig Shere - Tuohy Brothers Investment Research, Inc.

Great. And Brent, can you define where the divestitures are specifically being made? And based on regional production figures, it kind of looks like Altamont was flat sequentially, and well, of course, there's a bottleneck on the off tick from the Eagle Ford temporarily. And also look that region was down a little. Can you comment on either of those?

Brent Smolik

Don't read anything into the Altamont production. We've just had some -- we got some swept behind in our recompletion work over kind of program as a consequence of closing it in for office and relocating those teams here. But we're on that in this quarter, and we'll see that recover. Eagle Ford, you know the story there, that the production charts that we've updated reflect that we've been completing wells, but we can't always get them all the way to sales. And we've shown you those numbers, but we think that's remedied now through the end of the year and will be completely gone by the end of the year, most of the fourth quarter. And so those volumes, we can see ramping up just like we're giving in the chart. And then divestiture, we didn't give you a lot of detail because we've got one of those closed. And we've got 2 of them that are in progress. And I don't want any triangulating between valuations on all that. But think of them as noncore, the kinds of things that we're not spending capital on later in life, higher costs, lower inventory, things that we've done in the past.

Carl Kirst - BMO Capital Markets U.S.

Okay, basically gas?

Brent Smolik

No, no. There may be some oil in it, but it will be again, while we're not investing in it.

Craig Shere - Tuohy Brothers Investment Research, Inc.

Okay. And last question, I don't know if J.R., Doug or Jim want to chime in. But any thoughts on if it became available, depending on who acquires Southern Union, on buying in the other half of the Citrus-FGT JV and the implications that, that might have for the drop-down strategy.

Douglas Foshee

Yes, this is Doug. We've owned our interest in our half of Florida Gas Transmission, I think, since the mid-80s. And we've seen it go through several parties since then. But it's pretty consistently been an important part of our business. In fact, lots of growth potential as we demonstrated recently with the completion of Phase VIII. And we think it's well positioned to serve additional low growth in Florida in the future. With regard to the various proposals to acquire or merge with SUG, how that impacts us, it's probably not appropriate for us to comment on that today. But, except to say, we love our half of FGT, and we haven't been shy about saying it for the -- since the mid-80s. We love the other half of it, too. But we're not happy about all that.

Craig Shere - Tuohy Brothers Investment Research, Inc.

So just to be clear, I mean, let's just say for argument's sake, you were given the opportunity and decide to acquire the other half of that, before you could start dropping it down, you probably wanted to change the tax treatment or structure, which will create a taxable event on the portion you already owned. But then you could start dropping down as quickly as the market kind of absorb that. Is that a fair description?

Douglas Foshee

Yes, I'm really not going to comment on hypotheticals around transactions we might or might not have the opportunity to do.

Operator

Your next question is from Ted Durbin.

Theodore Durbin - Goldman Sachs Group Inc.

First question is, the CIG rate case, is there any financial impact that we should be modeling from that?

James Yardley

Well, in the CIG rate case settlement, essentially no change in rates, so in the base business, very little change in revenues. But I think, Ted, you're also aware that separately, there have been a significant expansions in CIG both the Raton Expansion as well as the High Plains Expansion. So yes, those expansions speak for themselves.

Douglas Foshee

But there's nothing about the rate case that changes any of our guidance.

Theodore Durbin - Goldman Sachs Group Inc.

Right, okay. That's what I was asking. That's great. And then same with the pipes on Ruby. We appreciate the early read as like 400 a day. Are those mostly -- I'm assuming those are all firm, or do you have any interruptible on there? And then can you just remind us what the tariff difference is between the firm and interruptible you have on Ruby?

James Yardley

Yes. Essentially all the gas is flowing within FT, so we're relatively unsensitive on the revenue sides. But how much flows today, interruptible tariff rates are significantly higher than the negotiated rates. But as you can expect, for us to attract interruptible backload revenues, we're going to have to dig to discuss that.

Theodore Durbin - Goldman Sachs Group Inc.

Right. Okay, great. And then last one for me, just maybe you could talk a little bit more about your MEPS project, kind of what you're hearing in the open season, the timing you might think about of getting some firm commitments from shippers?

Mark Leland

Yes, this is Mark Leland. And as you know, we had an open season. It closed last week. We had a very successful open season. We had more request for capacity that we had capacity, almost by a half. And we've extended the open season to September 15, so that we can negotiate with our customers final precedent agreements both customers -- producer oriented customers and petrochemicals. So we're confident of where we sit with MEPS today, but it's a highly competitive situation.

Operator

Your next question is from Becca Followil.

Rebecca Followill - Howard Weil

Can you update us on the other 2 rate cases?

James Yardley

Sure. So Becca, a major rate case is on TGP, as well as EPNG. Not a lot of news on the settlement front. As you're aware, actually the issues on the 2 are very different. In the case of TPG, we have significantly increase in throughput but changes in flows. So all the issues around cost allocation and the movement to more emphasis on the demand charge to bring it in line with other pipes. Those are the issues on TGP. On EPNG, I think as you're aware, we're dealing with declining throughput, which makes that rate case more difficult. But I think as a general comment, settlement discussions are in a very early stage. As the result of that, we continue down with the litigation path on EPNG. We filed our testimony. The customers have filed their testimony. We filed rebuttal testimony, I think, in September. And then we'll go to trial after that. TGP is probably a step or so behind that. We filed our testimony. The customers, I think, they're up in September to do theirs. The litigation is not a bad thing. We've got a good reason people on our side and a reason people on the other side. And sometimes you need an umpire to rationalize the situation. But regardless of whether where we go through litigation or settlement, we feel very good that we're with respect to our expectations and plans.

Rebecca Followill - Howard Weil

Great, thank you. That's very helpful. And then just clarifying the gain that you had from BG on Elba, about $14 million net, is that after-tax?

Douglas Foshee

It's pretax.

Operator

Next question is from Bradley Olsen.

Brad Olsen - Tudor, Pickering, Holt & Co. Securities, Inc.

A quick question on the bottlenecks that you guys mentioned in the Eagle Ford. Is there any product, gas, NGL or crude that was disproportionately affected by those bottlenecks?

Douglas Foshee

No. It's really is much as us as downstream. We had a little bit of downstream interruption in the quarter on gas on one of the gathers, but it's mostly us building out all of that swing of lease level facilities that we're building out in the E&P side and a gathering system for oil and gas that Mark's building out in the Midstream side. So that's really the bulk of that shut-in, and that we showed as the blue edge in the chart that will go away by the end of the year. And then we think we've got enough one line kind of take away capacity and trucking capacity to get the product moved away from the field.

Brad Olsen - Tudor, Pickering, Holt & Co. Securities, Inc.

Okay. And as far as the trucking capacity goes, we've heard from some other producers this quarter that trucking costs in some areas of Texas have gone up pretty dramatically. Have you guys seen those cost pressures?

John Sult

No, it's in our oil price netback, but it's not much difference than we've been. It more of us hand-to-hand combat to get the equipment, which is generally, on our market to do that. They're bringing trucks to us. But we just got to stay way ahead of it. And then we got to make sure we got enough storage capacity in the field in case we do get -- weekend bottleneck in trucking. We've been able to stay ahead of it so far. And then longer term, the solution will be get some of it off trucks and on and hard pipe. And we've got equity capacity.

Brad Olsen - Tudor, Pickering, Holt & Co. Securities, Inc.

Okay, great. And on the Pipeline side, just a couple of questions. I've heard from producers that there are issues basically, anybody who doesn't have reserve capacity in Northeast Pennsylvania on a long-haul takeaway is having trouble getting their gas to market. And it sounds like, considering the fact that the Line 300 expansion is going to start up fully contracted, it sounds like despite the capital, you guys have put to work that there's still a lot of demand for long-haul takeaway in Pennsylvania. Has there been anything that has maybe gotten you guys thinking about another project on TGP going forward?

James Yardley

Oh, yes. I mean, there's no question. I think we have a lot of opportunity to continue to expand, and we're in active discussions with some right now for further expansion. So I think it's -- and I think it's just going to keep coming.

Brad Olsen - Tudor, Pickering, Holt & Co. Securities, Inc.

Okay, great. And Florida Gas, I guess, I'll just kind of take the inverse of Craig's question. Given the fact that there's been an announcement made about a potential drop-down of Florida Gas with evaluation of over 20x free cash flow for the other 50% of FGT, is that evaluation that's -- I know you guys like the asset, but at a certain price, are you guys thinking that you might be willing to part ways with FGT if you were offered something in the range of 22x free cash flow?

Douglas Foshee

Yes. As you know, we don't typically speculate too much on what we might or might not do with stuff that we own. But we constantly evaluate the market, and I would say, the fact that we now have at least the appearance of a transaction where assets in some cases similar to our own are being valued very highly, we think does nothing but highlight the value of our own Pipeline franchise, and especially in a post-spin world where we will be more to 2 relative pure plays, we think that gets translated into value for our shareholders.

Brad Olsen - Tudor, Pickering, Holt & Co. Securities, Inc.

Okay, great. And then just the last question on Gulf LNG. You guys mentioned that it's a fully contracted asset. Would you guys mind providing any color around the length of those contracts? Or if there's any variable component or is it pretty much all fixed kind of like you have on Elba?

James Yardley

Essentially all fixed in 20 years.

Operator

And now at this time, there are no further questions. I would like to turn the call back over to Bruce Connery for any closing remarks.

Bruce Connery

Thanks for joining our call. We look forward to giving you additional progress as we go through the year. Thank you.

Operator

Thank you for your participation. This concludes today's conference call. You may now disconnect.

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