Plains All American Pipeline LP (PAA) 2012 Q2 法說會逐字稿

Ladies and gentlemen, thank you for standing by, and welcome to the PAA and PNG second-quarter results conference call. At this time, all participants are in a listen-only mode. Later, we will conduct a Question-and-Answer session, and instructions will be given at that time.

(Operator Instructions)

Also, as a reminder, today's teleconference is being recorded. Now, at this time, I will turn the conference call over to your host, Director of Investor Relations, Mr. Roy Lamoreaux. Please go ahead, sir.

Good morning. We welcome you to Plains All American Pipeline's and PA Natural Gas Storage's second-quarter 2012 results conference call. The slide presentation for today's call is available under the conference call tab of the Investor Relations section of our website at www.paalp.com and www.pnglp.com.

I would mention that throughout the call we will refer to the Companies by their New York Stock Exchange ticker symbols of PAA and PNG, respectively. As a reminder, Plains All American owns the 2% general partner interest and all the incentive distribution rights, and approximately 62% in the limited partner interest in PNG, which accordingly is consolidated into PAA's results.

In addition to reviewing recent results, we'll provide forward-looking comments on the Partnership's outlook for the future. In order to avail ourselves of Safe Harbor precepts that encourage companies to provide this type of information, we direct you to the risks and warnings set forth in the Partnership's most recent and future filings with the Securities and Exchange Commission.

Today's presentation will also include references to certain non-GAAP financial measures, such as EBIT and EBITDA. The non-GAAP reconciliation sections of our website reconcile certain non-GAAP financial measures to the most directly comparable GAAP financial measures, and provides a table of selected items that impact comparability of the Partnership's reported financial information. References to adjusted financial metrics exclude the effect of these and selected items. Also, for PAA, all references to net income are references to net income attributable to Plains.

Today's call will be chaired by Greg L. Armstrong, Chairman and CEO of PAA and PNG. Also participating in the call are Harry Pefanis, President and COO of PAA; Dean Liollio, President of PNG; and Al Swanson, Executive Vice President and CFO of PAA and PNG. In addition to these gentlemen and myself, we'll have several other members of our management team present and available for the Question-and-Answer session.

With that, I'll turn the call over to Greg.

Thanks, Roy. Good morning, and welcome to everyone. Continuing a multi-quarter trend, PAA delivered strong second-quarter results underpinned by solid fundamental performance and enhanced by favorable market conditions. Yesterday after market close, Plains All American announced second-quarter adjusted EBITDA of $522 million. These results exceeded the midpoint of our guidance range by $62 million, or 13%, and were $42 million above the high end of our guidance range. These results are also consistent with the updated estimate of expected second-quarter performance that we provided in a press release issued on May 30, despite the impact of an $11 million charge associated with the Rangeland pipeline release we experienced later in June.

Current-year results compared very favorably to last year's second-quarter, as adjusted EBITDA, adjusted net income, and adjusted net income per diluted unit for the second quarter of 2012 increased 43%, 53%, and 46%, respectively. Highlights of PAA's second-quarter performance are reflected on Slide 3, which also illustrates that PAA's [distribution in the] second quarter of 2012 was approximately 165%.

PAA's second-quarter results were driven by a solid performance in all three segments, with the Supply and Logistics segment being the largest contributor to over-performance. These second-quarter results mark the 42nd consecutive quarter that PAA has delivered results in line with, or above, guidance.

In July, PAA declared an 8.4% year-over-year increase in our annualized run rate distribution to $4.26 per common unit. As shown on Slide 4, PAA increased its distribution each of the last 12 quarters, and in 31 of the last 33 quarters. Over the last 11.5 years, PAA has grown its distribution at a compound annual growth rate of approximately 7.5%.

Yesterday evening, we furnished financial and operating guidance for the third quarter and the balance of the year, increasing the midpoint of our full-year 2012 adjusted EBITDA guidance by $80 million. This represents an approximate 4% increase over the full-year guidance provided on May 7, 2012, and a 14% increase over the full-year guidance we provided at the beginning of the year. PAA is executing well in this environment, and we are on track to meet or exceed our 2012 goals.

Additionally, yesterday we announced several new capital projects or expansions of existing projects that we expect to implement over the next 12 to 24 months, and are expected to yield attractive financial returns.

During the remainder of today's call, we will discuss our segment performance relative to guidance, our expansion capital program, our acquisition and integration activities, and our financial position. We will also address the drivers and major assumptions supporting our financial and operating guidance for the third quarter of 2012. We will address similar information for PNG. And at the end of the call, I'll provide a rate recap, as well as some comments regarding our outlook for the future.

With that, I'll turn the call over to Harry.

Thanks, Greg. And during my section of the call, I'll review our second-quarter operating results compared to the midpoint of our guidance issued on May 7. I'll discuss the operational assumptions used to generate our third-quarter guidance, and I'll also discuss our 2012 capital program and acquisition activities.

As shown on Slide 5, adjusted segment profit for the Transportation segment was $180 million, and that was $4 million above the midpoint of our guidance. Volumes for the segment were 3,560,000 barrels per day, and were in line with guidance, as was adjusted segment profit of $0.56 per barrel. As Greg mentioned, the quarter's results included the impact of an $11 million charge related to the previously announced crude oil release on the Rangeland pipeline system. And that charge is net of expected insurance reimbursements. The cause of the incident is under investigation, and our clean-up efforts are ongoing, and this segment of the line remains out of service.

Adjusted segment profit for the Facility segment was $119 million, or $4 million above the midpoint of our guidance. Volumes of 109 million barrels were in line with guidance, and adjusted segment profit of $0.36 per barrel was slightly above the midpoint of our guidance. The primary contributors to the financial over-performance were increased fee-based activities at our St. James and Cushing Terminals, and then stronger than forecasted results from our Natural Gas Storage activities.

Adjusted segment profit for the Supply and Logistics segment was $221 million, and that's $53 million above the midpoint of our guidance. Our total volumes were 971,000 barrels per day, and included 814,000 barrels per day of lease-gathering volumes and 153,000 barrels per day of NGL sales volume. The lease-gathering volumes were slightly below our guidance, primarily due to the timing of connections to our gathering system in South Texas. And our NGL sales volumes exceeded our guidance, primarily due to the timing of propane sales associated with the acquisition of the BP NGL assets.

Adjusted segment profit per barrel was $2.50, or $0.54 a barrel above the midpoint of our guidance. That's primarily due to strong lease-gathering margins and a wide Midland-Cushing differential. However, our NGL margins were weaker than forecasted, and that was primarily due to the impact of inventory cost accounting in a declining price environment.

Let me now move to Slide 6 and review the operational assumptions used to generate our third-quarter 2012 guidance, which was furnished in our Form 8-K last night. This slide has been reformatted from prior conference calls to present the midpoint of our third-quarter guidance compared to actual results for each segment in the same quarter of the prior year and for the immediately preceding quarter.

Let me start with the Transportation segment. We expect volumes to average approximately 3.59 million barrels per day, adjusted segment profit to be $0.57 per barrel, and adjusted segment profit to be $188 million. All these values are generally in line with our second-quarter results.

The Facility segment guidance assumes an average capacity of 112 million barrels of oil equivalent. The 3-million barrel increase is primarily related to additional natural gas storage capacity placed into service in the second quarter, as well as capacity expected to be brought into service in the third quarter. Adjusted segment profit is expected to be $150 million, or $0.34 per barrel in the third quarter.

Logistic segment volumes are projected to average 945,000 barrels per day in the third quarter of 2012. The projected midpoint for adjusted segment profit is $106 million, or $1.22 per barrel for the third quarter. The third-quarter guidance is lower than the second-quarter actual results primarily due to a combination of a lower Midland-Cushing differential and then lower NGL sales prices. While the lower NGL prices negatively impact margins in the third quarter, this was largely a timing issue associated with the impact of inventory cost accounting, and higher margins are expected later in the NGL season, most likely in the first quarter of 2013.

Now, let me move over to our capital program. We have a number of new capital projects, as summarized on Slide 7. We are increasing our forecast for 2012 to a range of $1.1 billion to $1.25 billion. I'll provide an update on some of our existing projects, and also touch on a couple of our recently announced projects.

First, let me start with our Eagle Ford project. An announcement we made last night that we have formed a joint venture with Enterprise Products, in which we have combined portions of our crude oil infrastructure projects in this area. Our original project will be expanded to include a 20-inch pipeline segment from Three Rivers to Lyssy, which is the origination station for the Enterprise pipeline from the Eagle Ford area to Houston.

The joint venture pipeline system is the red pipeline on Slide 8. The pipeline is supported by long-term shipper agreements covering approximately 210,000 barrels a day, or roughly 60% of available capacity. We believe the joint venture system will provide producers with more flexibility than any other pipeline in the Eagle Ford area, and we believe our $1.25 tariff for uncommitted shippers will be the most competitive tariff in the area.

Slide 8 also highlights the expansion of our Gardendale Gathering system that we also announced yesterday. The project will include 90 miles of new gathering lines. Those gathering lines are shown in green on the map, as well as a new condensate stabilization facility being constructed adjacent to the Gardendale terminal. The gathering system expansion and the stabilizer are underpinned by producer agreements.

Yesterday morning we announced a new 40-mile, 24-inch pipeline to be constructed from our Ten Mile facility in Alabama. This project is underpinned by a long-term agreement with the shipper, and is expected to be in service by the fourth quarter of 2013.

Also yesterday morning we announced that we're constructing a new crude oil rail loading facility at Tampa, Colorado, and expanding our rail offloading facility at our Yorktown terminal. The Tampa facility will be capable of loading a unit train, and is underpinned by producer commitments. The Yorktown facility currently has manifest train unloading capacity, but will be expanded to have capacity to unload two unit trains a day. We are also making a number of other modifications to the dock and related infrastructure at Yorktown. Both projects, which are discussed on Slide 9, are expected to be in service by the third quarter of 2013.

As discussed in our press release yesterday, we have completed or are nearing completion of a number of pipeline expansion projects putting over 145 miles in a nine-county area in the Permian Basin. These projects, which are designed to provide a total of 200,000 barrels a day of additional gathering capacity to the Bone Spring, Spraberry and Wolfberry producing areas, will be connected to our Basin pipeline system, as well as the Longhorn and the Mesa Flatfoot Texas Gulf systems. Our Bakken North project is on target to be completed by the end of 2012. However, the connections with Enbridge at Regina in Canada will likely slip to 2013.

We recently started construction of our Rainbow II pipeline project. It's a 10-inch pipeline that twins the Rainbow pipeline system, and [will move diluent] north from Edmonton to Nipisi. The line will have initial capacity of approximately 35,000 barrels per day, and will supply producers with diluent needed to move an increasing supply of heavy oil production from the Peace River area. We expect the line to be in service by mid-2013.

Our maintenance capital expenditures for the second quarter were $40 million. We continue to expect maintenance capital expenditures for 2012 to be in the range of $140 million to $160 million.

On the acquisition front, we're actively reviewing and evaluating a number of strategic and accretive opportunities. But as you can imagine for competitive reasons and confidentiality restrictions, we're unable to discuss the specifics with respect to any of those activities. However, with respect to our integration efforts, I'll note that as reflected on Slide 10, we are on target with the major integration milestones we established for the BP NGL acquisition, and have substantially completed the integration of the acquisitions that we made in 2011.

With that, I'll turn the call over to Dean to discuss PNG's operating and financial results.

Thanks, Harry. In my part of the call, I will review PNG's second-quarter operating and financial results, and our financial position as of June 30, 2012; provide an update on PNG's operation and capital program; and review our second-quarter and full-year 2012 guidance.

Let me begin by discussing the results we released last night. As shown on Slide 11, PNG delivered second-quarter 2012 results in line with the guidance we provided in May. Adjusted EBITDA for the second quarter of 2012 totaled $29.7 million, resulting in adjusted net income of $18.6 million and adjusted net income per diluted unit of $0.25.

A portion of the over-performance relative to the midpoint of our guidance is timing related, as we were able to realize certain profitability for storage capacity that we manage for our own account sooner than originally forecasted. The remaining portion of the over-performance is due to lower expenses and incremental revenue resulting from market volatility during the quarter. This is partially offset by lower liquid volumes at Bluewater due to lower than expected storage withdrawals during the second quarter.

In comparison to last year's second-quarter results, adjusted EBITDA, adjusted net income, and adjusted net income per diluted unit for the second quarter of 2012 increased 8%, 9%, and 9%, respectively. As reflected on Slide 12, PNG's second-quarter results mark the eighth consecutive quarter of delivering results in line with guidance.

Financially, PNG continues to be well positioned. Including on Slide 13 is a condensed capitalization table for PNG June 30, 2012. Highlighting PNG's long-term-debt-to-capitalization ratio of 28%, a long-term-debt-to-adjusted-EBITDA ratio of 3.8 times, and $187 million of committed liquidity that reflects the benefit of the $100 million increase we recently completed to our revolving credit facility. Additionally, effective June 1, 2012, we amended our $200 million note with PAA to reduce the interest rate to 4% from 5.25%, and extend the maturity to June 2015.

Operationally, we are on track to complete our 2012 capital program on time and on budget. Our 2012 expansion capital plan calls for expenditures to range between $56 million and $60 million. We expect to have a total of approximately 16 Bcf of working storage capacity in service in 2012, increasing our average working capacity for 2012 to 84 Bcf, representing an 18% increase over our 71 Bcf average working capacity in 2011. In June, we placed our fifth cavern at Pine Prairie into service. And we have received the necessary regulatory approvals and plan to place our fourth cavern at Southern Pines into service by September 1.

Additionally, throughout the year we have been and expect to continue to create additional capacity through our incremental leeching activities at both Pine Prairie and Southern Pine. Overall, we expect to exit 2012 with aggregate capacity of approximately 92 Bcf, a 21% increase over the 76 Bcf of capacity that we had entering into 2012.

Moving on to the market, conditions for Natural Gas Storage remain challenging, and we continue to position PNG to manage through a continuation of the conditions we have experienced over the last 18 months. With that outlook in mind, and as represented on Slide 14, our annual guidance for 2012 is essentially unchanged, with our adjusted EBITDA forecast for 2012 estimated to range between $116 million and $124 million, with a midpoint of $120 million. This guidance represents a 12% increase over our 2011 comparable results.

For the third quarter, we expect adjusted EBITDA to range from $25 million to $29 million, with a midpoint of $27 million. As depicted by the chart in the upper right of Slide 14, adjusted EBITDA for the first three quarters of the year is expected to remain fairly consistent with the seasonal increase forecasted for the fourth quarter.

With respect to distributions, in early July we announced a quarterly distribution of $1.43 per unit on an annualized basis. This distribution, which is payable next week, is equal to the distribution that was paid in May 2012, and equates to a 3.6% increase over the distribution that was paid in August 2011. Our distribution coverage for the second quarter was 104%. Achieving the midpoint of our guidance for 2012 also provides 105% coverage of our existing distribution level.

As we have noted in previous calls, an important component of our business strategy is to commit a high percentage of our storage capacity to firm storage contracts. As a result, PNG's distribution is underpinned by a diverse portfolio of third-party firm storage contracts with initial terms ranging from 1 to 10 years in length.

As illustrated on Slide 15, for calendar-year 2012 approximately 95% of our average capacity is contracted with third parties. As contracts roll off and we add incremental storage capacity, this percentage changes. The comparable percentages for 2013 and 2014 are approximately 70% and 50%, respectively, in each case without taking into account new contracts that we intend to enter into in the future, but including incremental storage capacity we expect to place into service.

In conclusion, although we continue to face challenging market conditions, we believe PNG's strategically located and operationally flexible assets, supportive parent, attractive contract portfolio, solid capital structure, and low cost expansion projects position PNG very well relative to its peers.

With that, I'll turn it over to Al.

Thanks, Dean. Our financing activity since the last conference call consisted of our continuous equity offering program, and the renewal and extension of certain of our credit facilities. We implemented the continuous equity offering program in May. Through June 30, 2012, we raised approximately $114 million of equity capital, including the general partner's matching contribution, by selling approximately 1.4 million common units.

Additionally, in late June we amended our hedged inventory facility, increasing the size from $850 million to $1.4 billion, and extending the maturity to August 2014. This expansion more than replaces the $500 million of three-year senior notes maturing in September 2012 that we issued in 2009 to supplement our hedged inventory facility. Furthermore, the increased size and amended terms of the facility will also serve to support our expanded Canadian NGL activities related to the BP NGL acquisition, and enhance our ability to utilize our storage and related assets capitalized on the market opportunities in the crude oil sector.

As illustrated on Slide 16, PAA ended the second quarter of 2012 with strong capitalization, credit metrics that are favorable to our targets, and approximately $2.8 billion of committed liquidity. At June 30, 2012, PAA's long-term-debt-to-total-capitalization ratio was 47%. Total-debt-to-capitalization ratio was 51%. Long-term-debt-to-adjusted-EBITDA ratio was 3.1 times. And our adjusted-EBITDA-to-interest-coverage ratio was 7 times.

Our total-debt ratio includes $1 billion of short-term debt that primarily supports our hedged inventory. This debt is essentially self-liquidating from the cash proceeds when we sell the inventory. For reference, our short-term hedged inventory at June 30 consisted of approximately 23 million barrels equivalent with an aggregate value of approximately $1.16 billion. These amounts do not include approximately 19 million barrels equivalent of [lime] fill and base gas in PAA's and third parties' pipelines and terminals that are classified as a long-term asset on our balance sheet, with a book value of approximately $900 million and a market value of over $1.1 billion.

Moving on to PAA's guidance for the third quarter and full year of 2012, the high points of which are summarized on Slide 17. For more detailed information, please refer to our guidance 8-K that we furnished last night. We are forecasting midpoint adjusted EBITDA, adjusted net income, and adjusted net income per diluted unit for the third quarter of 2012 of $412 million, $240 million, and $0.99, respectively. Including the benefit of the second-quarter 2012 over-performance, in our updated forecast for the second half of the year we are forecasting 2012 midpoint adjusted EBITDA, adjusted net income, and adjusted net income per diluted unit of $1.88 billion, $1.19 billion, and $5.42, respectively.

Our updated second-half guidance is 2% higher than the second-half guidance we provided in May. It reflects an expectation for less favorable crude oil market conditions than those experienced during the first half of the year, and less favorable NGL market conditions than we previously forecast. As you would expect, our full-year guidance includes some refinement with respect to segment contributions and timing as a result of recent acquisitions, particularly the BP NGL acquisition.

As represented on Slide 18, PAA has continued to deliver solid distribution growth and coverage, giving effect to our recent financing activities based on the midpoint of our 2012 guidance for distributable cash flow, or DCF, and our targeted LP distributions. Our distribution coverage is forecast to be approximately 140%, and we would retain approximately $385 million of excesses DCF or equity capital.

Before I turn the call over to Greg, I wanted to make a few comments related to our credit rating. For a number of years, our financial growth strategy has targeted an objective of achieving and maintaining mid- to high-BBB credit rating. We were very pleased to receive an upgrade from S&P on May 30 from BBB minus to BBB. Our credit rating with Moody's is comparable at Baa2, and the outlook at both agencies is stable. We remain committed to continued improvement in our credit ratings, and intend to continue to prudently manage our capital structure and credit profile to achieve this important objective.

With that, I'll turn the call over to Greg.

Thanks, Al. The second quarter was clearly a very productive period for the Partnership. As recapped on Slide 19, PAA delivered very strong performance for the second quarter of 2012, increased its guidance for the full year of 2012, and added several attractive projects to our capital program. We believe we are well positioned to continue to perform well throughout the balance of the year, and to accomplish our 2012 goals, including delivering year-over-year distribution growth of 8% to 9%.

It's worth noting that since our last conference call in early May, crude oil prices fell by over 20% to $77 a barrel before recovering to their current level of around $90 per barrel, and NGL prices also weakened materially both in absolute and relative terms. Our guidance for the third and fourth quarters of 2012 incorporates our view of how these lower prices will impact PAA during the second half of 2012, including our view that market conditions may not be as favorable during the second half of 2012 as they were in the first half.

As a business builder with a long-term view, we don't have to be spot-on in the short term, just right about the long-term fundamentals. With that thought in mind, our long-term outlook is for a continuation of strong industry fundamentals with regard to drilling activities and production growth both in the US and Canada. We believe our assets are strategically positioned relative to this outlook.

However, in order to remain prepared for fluctuations in industry conditions, we will continue to maintain significant financial flexibility, and reasonable distribution growth and coverage. Doing so will allow us to continue to be patient and yet deliberate in our pursuit of strategic opportunities. For those reasons, we believe PAA is well positioned to continue to deliver attractive results. Specifically, over the next several years we expect to continue to realize the contributions from the $1.9 billion of capital we invested in 2011, and the $2.8 billion that we have already invested or currently expect to invest in 2012 and beyond. As always, we will remain focused on prudently financing our growth while maintaining a solid capital structure and a high level of liquidity.

Before opening the call up for questions, I would mention that PAA and PNG held an analyst and investor meeting on May 30, 2012. The meeting was well attended, with over 200 investors or analysts participating in the meeting in Houston or over the internet. For those that did not participate, a copy of the slide deck and webcast for the analyst meeting are available on our website at www.paalp.com, under the investor relations and the partnership presentations tab. Once again, thank you for participating in today's call, and for your investment in PAA and PNG. We look forward to updating you on our activities during our third-quarter results call in November.

Operator, at this point we're ready to open the call up for questions.

(Operator Instructions)

Darren Horowitz; Raymond James.

Greg, two quick questions from me. The first, as it relates to the Permian, just wanted to get an update on your thoughts regarding production growth versus pipeline take-away capacity, specifically in light of some recent pipeline announcements that we've heard. And I'm more focused on if we think that the Permian could have another 800,000 or almost 1 million barrels of production growth over the next couple years. Do you think that a 200,000-barrel a day gathering expansion that you talked about feeding Mesa the LongHorn line ramping up and the potential for that new BridgeTex line? Do you think that's enough to keep the market balanced?

Darren, I think what's going on in the Permian's going to be more of a marathon than a sprint. It's going to take several years for some of these production profiles and also the take-away capacity to develop. I think, candidly, we're going to go through periods where we have excess production relative to take-away capacity. We'll run through periods where we have excess take-away capacity relative to production as these new midstream projects come on stream. Ultimately, we may shift back into a shortage of take-away capacity, just depending on how the next generation of pipelines and take-away capacity is developed.

In the Permian, just to put it in perspective. I think we hit a low in the Permian -- I'm talking about both New Mexico and Texas, of probably around 750,000 barrels a day not too many years ago. Currently, we're probably running about 1.1 million barrels to 1.2 million barrels.

Correct.

Our forecast for 2016 to '17 time period, Darren, probably has us fairly comfortably going into the 1.6 million barrels to 1.7 million barrels. There certainly are numbers that are forecast to be higher and if I take your 800,000 barrels and add to current, that push up close to 2 million barrels. I don't think there's enough on the drawing board today to support the 2 million barrels. I do think there's probably enough on the drawing board today to support roughly the 1.6 million barrels to 1.7 million barrels but we still have about three to four years to go to get there. We may go through periods of over supply and under supply with respect to take-away capacity during the next three or four years and then it's a little bit fuzzy when you get farther out. Harry, do you want to add anything?

When you look at the gathering capacity, we've got a line in New Mexico that we recently acquired that's connecting into the Basin system at Jal. That is going to add some capacity. We've got a couple other projects where as production develops we think we've got infrastructure and right of way in place, where we can expand gathering capacity. And as you can imagine, we're looking at take-away capacity out of the Basin as well.

I think it's fair, Darren, in addition to the announced projects you might assume there's probably some shadow projects out there still that are basically positioning to address the longer term issues that you've identified.

Yes. I appreciate the color. And then last question, Greg. With regard to the second half of this year's guidance reflecting as you quoted less favorable marketing conditions, if we back out the conservative outlook on natural gas liquids within the S&L segment, is it more a function of tighter regional pricing arbitrage opportunities like that Midland to Cushing differential that Harry mentioned? Or is it more narrowing of grade quality differentials?

Midland to Cushing. If you look at sort of a run rate that we expected at the beginning of the year, the Midland to Cushing differential is probably the big blow out for the quarter. The other differentials, you see a lot of volatility. There could be some upside in some of the grades but there might be a little down side as well. But I'd say the Midland to Cushing differential that we experienced in the late first quarter and then through the second quarter is probably the largest driver for the over performance first half of the year.

Yes. And then I'd add to that as always, Darren, is that weather patterns in the fourth quarter versus the first quarter of next year will cause NGL deliveries to vary. So, if we have high withdrawals from inventory in the fourth quarter, there's probably a little bit of upside to the forecast. But if we don't have it, it really just shifts over to the first quarter of next year. That's really not so much a swing in the outlook. Just trying to project the timing. I think the biggest contributor to second quarter versus our outlook for the second half of the year was the Mid-Cush differential.

Brian Zarahn; Barclays.

Can you give a little more color on the Eagle Ford JV with Enterprise. You generally don't do a lot of JVs with other MLPs. Is this something that you -- I guess first, when did you begin discussions on this project? And do you see more opportunities with Enterprise in the crude oil business?

We've been in discussion with Enterprise for probably three or four months on this. Clearly, any time there's such a wave of new construction in an area that's developing this fast, part of the challenge between both the producers and the midstream companies is to calibrate the actual midstream capacity necessary to meet the needs. In this particular case, we discovered that there probably was an oversupply of pipelines being built to the Eagle Ford. And issues come up about not only excess take-away capacity but what's the right rate to charge.

By joining with Enterprise, we both found a better use for both of our capital to basically optimize the return and still meet all the needs of the different producers that we have and the commitments on that. So to answer your question, it's been three or four months.

You're right, we don't do a lot of joint ventures but Enterprise is clearly one of the top contenders for anything we might think about doing in a JV. So we found it to be very good to deal with. We're interested in exploring other opportunities. Again, we probably prefer to do it all ourselves, always. But in areas where it makes sense, we certainly would open up to joint ventures as we did here.

Just to give you an idea, if you look at that Gardendale area. Enterprise had a project to go from Gardendale to Lyssy. If you were to layer their project on top of the other pipeline projects being developed out of the same area, you would have been 1.1 million a day in total. I don't think anyone has an expectation of being anywhere close to that type of volume coming out of that portion of the Eagle Ford. On a consolidated basis, we still have over 800,000 barrels a day of capacity from that portion of the Eagle Ford into the Three Rivers area. We can split up and go north to the pipelines going to Houston and south to the pipelines going to the Corpus Christi area.

By consolidating that part of the project and the economies of scale that go along with it, we think we were able to have probably, as Harry mentioned in his comments, the most competitive transportation rate for that incremental barrel coming out of Gardendale.

In terms of the remaining capacity, do you expect to have that contracted or are you going to leave that open for spot shippers?

We're pretty flexible. I mean, we certainly have a lot of gathering activities as you know in the Velocity. The assets we bought from Velocity, what we now call the Gardendale Gathering system expansion. We expect to be able to feed a lot of our own pipeline there.

I think what's happened is there's still more capacity coming out of Gardendale than there is production. That might not always be the case but certainly is today. So it's a lot harder to get commitments once the pipelines are built. So you've got enough pipeline capacity being developed, we would love to have commitments but just harder to get commitments after the pipeline's already in service or committed to be developed.

Last question from me. As we get closer to year end, do you think 2013 organic spending could be similar to 2012 levels?

You know, we've been saying for a while that we think it has an upward bias to what we were previously announcing around $650 million to $800 million. We continue to have that same upward bias and the short answer to your question is likely probably going to approach $800 million to $1 billion range.

Ted Durbin; Goldman Sachs.

Thanks. Wondering if you can give us an update, a little more detail on the BP assets that you bought? What you're seeing on volumes and margins? I think you mentioned some refinements you made to the forecast, kind of some of the changes there? How are you doing on getting third-party volumes? Can you go through those assets?

Ted, we're pretty much, as Harry's slide indicated, on track with respect to the integration part of it. The two aspects that will take a number of years are the realization of all the commercial synergies, and then some of the IT systems will continue to stretch into next year just because it takes longer for those things. Overall, we're pretty much on track with what we thought to be. I'd say our volumes are pretty much in line with what we would have expected at this point in time.

The one issue, Harry mentioned in his comments, because of the difference between when you put NGL into inventory, when you take it out, there's some inventory costing time issues and that's what I mentioned earlier. If we see a big draw on inventory in the fourth quarter, then we'll probably have some upside to our bias, but we refined that a little bit to allow for some of those draws to carry into the first quarter of next year just because it's weather related.

As far as changing the business strategy from solely merchant to a business that is more a fee-based business, the NGL season is like natural gas where it's April 1 to March 31 of the following year. So don't expect to convert much of that to a fee-base this season. A lot of the positions were put on by BP as they were. They owned the assets through the first quarter of 2012. That's a dynamic that will change as we look at the next season from 2013, '14.

What we have done, Ted, as we indicated, we pretty much unlike BP which may keep inventory and not have it sold. We've hedged our inventory position so we're not exposed to the price fluctuations that we have now. But as Harry said, if you go back in our conference call comments, we said it would take us about three years to totally convert their system into the way we would like to manage it. That's not only the business model conversion but also part of the challenge is trying to take assets that were storage assets in Canada that were existing storage but not in service, and try to put it back in service.

We're getting permission to create brine ponds so we can actually use the caverns that we have available. We're pretty excited about what that long-term view looks like especially in the Sarnia area, as well as others for converting those caverns into active use, whether it be for crude oil for NGL.

That's actually very helpful. Thank you. The other one from me was just how you're thinking about the Yorktown facility here? It was unclear to me if you actually have contracts on the terminal you're building there and maybe extending that sounds like we may not be shutting down as much East Coast refinery capacity as we assumed. Wondering how you think about that impact on some of the assets on the East Coast for you?

Yorktown, we do have part of the facility leased right now. We've got a lot of work going on to refurbish tanks, get the docks in place, get the rail facility where we want so it's not totally utilized right now. We expect long-term that a lot of the assets will be used on a fee basis and we think we'll move some of the product into Yorktown -- some of the crude into Yorktown as well. It's used both for crude and products.

We think the higher utilization of refining capacity in the East Coast helps Yorktown. We're set up to move two unit trains in a day of crude. We think the East Coast and the West Coast are natural locations for the extra light sweet crude that's being developed in the US.

I think it's fair to say, Ted, part of what we're doing and I think Sunoco and others are doing is you're basically bringing attractive crude from domestic sources to the East Coast that will probably cause the refiners to be able to stay in business longer.

(Operator Instructions)

Michael Blum; Wells Fargo.

Just one follow-up on the BP assets. I guess just to clarify, given the reduction in NGL prices that we've seen, do you still expect to be within that EBITDA range that you provided when you bought the asset?

We provided in the neighborhood roughly of about $200 million. Michael, we had anticipated when we ran our numbers, obviously strong and weak price forecasts. Overall, even if we stayed in this lower price forecast for the future, with the activation of the other assets, we still feel pretty good about our $200 million neighborhood.

And if I rolled forward two years and after you converted more of this business to fee based, how would that number change? Would that go up or down or stay the same, assuming the same price environment?

I'd probably say it's going to be in the same neighborhood, maybe a little bit better than where it is right now. We may not be above or below that $200 million. Right on that $200 million all the time. But nothing's changed in terms of how we value the acquisition meaningfully at all. If anything, we're probably more excited about the upside. It's just hard to have a crystal ball to say what's the market going to be three years from now and what it's going to do to demand for services. If you could tell me what it is going to do to drilling in the Marcellus area and some of the Utica shale I could probably answer your question. We still feel good about the neighborhood of EBITDA that we use to base our price forecast on, with upside to that.

Ross Payne; Wells Fargo.

I've had my questions answered. Thank you guys.

Thanks, Ross.

Selman Akyol; Stifel Nicolaus.

Just a quick question on natural gas. I guess somebody should ask a question. In terms of the Caverns Four and Five, can you talk about how those are leasing up? And where they are and what rate environment you're seeing?

Well, as far as leased out, at Southern Pines we're sold out. So, Cavern Four is completely committed. Cavern Five at Pine Prairie, for 2012, most of that capacity as we showed is done and the little bit that was left we took and are managing ourselves. As you shape up and look forward into 2013, we're currently working on with customers to sell the space in 2013 as we would at this time of the year and as we move forward in the year.

So from a rates, I'll take the usual stance. We don't comment on those. But the environment, as far as market conditions, haven't changed from what they were earlier in the year, as far as long-term rates. I think we're still very close to in my opinion bouncing off the bottom. I think there's upside from this point on, but fairly consistent with what we've seen in recent contracting periods.

As Dean commented during his part of the call, we're preparing ourselves to see ourselves quote bounce off bottom for the next two to three years. It's just hard to say there's going to be a dramatic recovery near term. If it happens, we're well positioned for it. If not, we're pretty well positioned as well.

At this time, there are no additional questions in queue. Please continue.

If there are no additional questions, we'll go ahead and conclude the call. Again, we want to thank everybody for dialing in and for your investment and trust in PAA and PNG. We look forward to updating you on our call in November.

Thank you, very much. Ladies and gentlemen, that does conclude your conference for today. We do thank you for your participation and for using AT&T's Executive TeleConference. You may now disconnect.