Dean Liollio - President of PNGS GP LLC and Director of PNGS GP LLC Greg Armstrong - Chairman of Plains All American GP LLC and Chief Executive Officer of Plains All American GP LLC Roy Lamoreaux - Director of Investor Relations Al Swanson - Chief Financial Officer of Plains All American GP LLC and Executive Vice President of Plains All American GP LLC-GP Harry Pefanis - Vice Chairman of PNGS GP LLC

Brian Zarahn - Barclays Capital John Edwards - Morgan Keegan & Company, Inc. Stephen Maresca - Morgan Stanley Michael Blum - Wells Fargo Securities, LLC Darren Horowitz - Raymond James & Associates, Inc.

Good morning. My name is Roy Lamoreaux, Director of Investor Relations.

We welcome you to Plains All American Pipeline and PAA Natural Gas Storage's Second Quarter Results Conference Call. The slide presentation for today's call is available under the conference call tab at the Investor Relations section of our website at www.paalp.com and www.pnglp.com.

Before we get started with our prepared comments, I would mention that throughout the call, we'll refer to the companies by their respective New York Stock Exchange ticker symbols of PAA and PNG, respectively. As a reminder, Plains All American owns the 2% general partner interest and approximately 62% of the limited partner interest in PNG, which accordingly has been 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 the Safe Harbor precepts that encourage companies to provide this type of information, we direct you to the risks and warnings set forth in our 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 section of our website reconciles 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 selected items. Also for PAA, all references to net income are references to net income attributable to Plain's.

Today's call will be chaired by Greg L. Armstrong, Chairman and CEO of PAA and PNG.

Also participating on the call are Harry Pefanis, President and COO of PAA and Vice Chairman of PNG; 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.

During today's call, we will discuss PAA's second quarter operating and financial results, our 2011 capital program, our financial position, our updated guidance for the third quarter and the remainder of 2011 as well as our overall outlook. We would also address similar information for PNG as well as provide an update on the natural gas storage markets.

Yesterday after market closed, Plains All American announced second quarter adjusted EBITDA of $366 million exceeding the high end of our guidance by $46 million, which is $61 million above the midpoint of the guidance range. As shown on Slide 3, adjusted EBITDA, adjusted net income and adjusted net income per diluted unit for the second quarter of 2011 increased 48%, 87% and 96%, respectively over last year's second quarter and each were favorable compared to guidance.

PAA's results were driven by solid performance in all 3 segments with the Supply and Logistics segment being the largest contributor to overperformance. Notably this overperformance includes the adverse impact of the Rainbow release which Harry and Al will discuss in their part of the call.

As shown on Slide 4, our second quarter results mark the 38th consecutive quarter of delivering results in line with or above guidance. 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 2011 guidance by $89 million.

Additionally, last month, PAA declared a 4.2% year-over-year increase in our run rate distribution to $3.93 per unit on an annualized basis. As for the distribution payable next week, PAA will have increased its distribution in each of the last 8 quarters and 27 out of the last 29 quarters.

As highlighted by our strong results, the energy environment continues to be very favorable for PAA's assets and business model. PAA has executed well in this environment and we are on track to meet or exceed our 2011 goals.

At the end of the day's call, I will provide some additional comments on our distribution outlook for both PAA and PNG, but for now, let me turn the call over to Harry.

Thanks, Greg. During my portion on the call, I'll review our second quarter operating results compared to the midpoint of our guidance issued on May 4, 2011, discuss the operational assumptions used to generate our guidance for the third quarter and discuss our capital program.

Dean will cover the PNG-specific information in a moment. As shown on Slide 5, adjusted segment profit for the Transportation segment was $137 million or $0.49 per barrel which was in line with our midpoint guidance.

Volumes in the segment were a little more than 3 million barrels per day and were also in line with our guidance, with stronger volumes on basin, our Line 63/2000 system and at the Permian Basin area systems partially offsetting lower volumes or lower than forecasted volumes of our refined products systems and the Rainbow Pipeline. As noted in our press releases and our website update, we experienced a release on the Rainbow pipeline on April 29.

The release site has been repaired, clean up efforts are ongoing and we're currently waiting on regulatory approval to place the line back in service. The aggregate second quarter economic impact totaled approximately $23 million net of expected insurance reimbursements.

And Al will provide additional detail on this estimate and the cost during his part of the call. Looking forward, we're cautiously optimistic that we'll receive regulatory approval to place the line back in service in the third quarter.

However, for purposes of our guidance, we've modeled the restart in the fourth quarter of this year. Moving on to the Facilities segment, adjusted segment profit for the facilities segment was $91 million or $0.37 per barrel, which totaled about $5 million above the midpoint of our guidance.

Primary drivers of the overperformance were higher throughput-related fees in certain of our liquid terminal and favorable gas processing margins. Volumes of 82 million barrels for the quarter were in line with our guidance.

Adjusted segment profit for the Supply and Logistics segment was $136 million or approximately $1.82 per barrel. Segment profit was $54 million above the midpoint of our guidance, primarily due to improved lease gathering margins in certain areas with significant drilling and constrained takeaway capacity, as well as favorable differentials and market structure.

The volumes were 818,000 barrels per day compared to our guidance of 850,000 barrels per day. On a sequential quarter basis, our lease gathering volumes were essentially unchanged, but were lower than forecasted for the second quarter.

Weather and its impact on road conditions, particularly in the Rockies as well as various other transportation logistical issues in other areas, negatively impacted our actual volumes during the quarter. The maintenance capital expenditures were $27 million for the quarter, and we're running a little ahead of a forecast on our maintenance capital projects.

And accordingly, we've increased our projected maintenance capital expenditures to a range of $95 million to $105 million for the year. Let me now move on to Slide 6 and review the operational assumptions used to generate third quarter midpoint guidance which was furnished in our Form 8-K last night.

For the Transportation segment, we expect volumes to average approximately 3 million barrels per day, in line with the volumes for the first half of the year. The expected segment profit of $0.52 per barrel is slightly higher than the first half of the year.

Remember, the first half of the year was burdened by the Rainbow Pipeline-related costs and additionally, the second half of the year reflects tariff increases on a number of our systems as a result of the FERC index adjustments. Facilities segment guidance assumes an average capacity of 83 million barrels of oil equivalent with segment profit of $0.37 per barrel.

The segment profit is in line with the second quarter results and the 1 million barrel equivalent capacity increase is primarily due to the completion of a portion of our latest expansion at our Cushing terminal. Supply and Logistics segment guidance volumes are projected to average 830,000 barrels a day for the quarter with a projected midpoint segment profit of $1.15 per barrel.

This volume includes the 2 million barrels of Strategic Petroleum Reserve barrels we purchased from the Department of Energy in the third quarter of this year. We expect margins in this segment to continue to be strong in the third quarter, but not as strong as they were in the second quarter.

We have a number of expansion projects in progress and we are more active than we've ever been. As noted on Slide 7, some of the noteworthy projects that have been completed and placed in service so far this year, include our Mid-Continent expansion project, our Basile gas processing plant near Pine Prairie, approximately 1.5 million barrels of new capacity or tank capacity at Cushing and expansion of our Mesa pipeline system.

Our Mesa pipeline project increased capacity by approximately 100,000 barrels a day and corresponds with Sunoco Logistics' expansion of their West Texas Gulf System and our own expansion of the basin pipeline. During the remainder of the year, we expect to complete our Bone Spring pipeline, the expansions at our Cushing and Bumstead facilities and a partial start up of our Ross terminal in the Bakken area.

Projects expected to be completed in 2012 include our Patoka expansion, the Basin Pipeline expansion, our new Eagle Ford pipeline and our Wascana reversal. And you'll notice that our guidance reflects capital expenditures for what we call Rainbow II pipeline, which we expect to be completed in the first half of 2013, pending the timely receipt of our applicable permits.

We have a number of other projects in progress. Although we expect to finalize our plans in the near term, we will expand our footprint in a number of liquids-based resource plays.

In total, we have increased our guidance for our 2011 capital expenditures by $25 million to $625 million, which is reflected in Slide 8. Actual expenditures to be incurred in 2011 are expected to range between $575 million and $650 million for the year, reflecting the uncertainties related to weather, scope changes and regulatory approvals, as some of these projects could either progress faster than anticipated or experience delays causing costs to slip into the first couple of months of 2012.

As you can see we've been very active and continuing to be very active in our pursuit of incremental growth opportunities, both organic and acquisition. And we look forward to updating you on these activities as they materialize.

I'll now turn the call over to Dean for an update on our Gas Storage activities

Thanks, Harry. In my part of the call, I will review PNG's second quarter operating and financial results and provide an update on operational activities at each of our facilities.

I will also review our updated assessment of the current market conditions with respect to natural gas storage. As shown on Slide 9, PNG announced solid second quarter 2011 results, including adjusted EBITDA of $27.5 million, adjusted net income of $17.1 million and adjusted net income per diluted unit of $0.23, each of which reflects performance above the midpoint of our guidance range.

This overperformance relative to midpoint guidance is primarily due to favorable Hub Services performance as well as lower expenses than forecast. A portion of the higher Hub Services revenue is due to the accelerated realization of certain short-term opportunities that were previously forecast to be recognized in the last half of the year.

This timing adjustment has been factored into the guidance we issued yesterday evening. Let me give you a quick update on activities in each of our storage facilities.

At Pine Prairie, we placed cavern well 4 into storage service during the second quarter with an initial working capacity of over 8 Bcf. Including capacity additions due to fill and dewater activities, Pine Prairie's total working capacity is now over 32 Bcf.

Leaching operations on cavern well 5 at Pine Prairie are fully underway and we remain on track to bring that cavern into storage service during the second quarter of 2012. Through cavern well 5 and opportunistic fill/dewater activities over the next 12 months, we anticipate increasing Pine Prairie's working capacity by an additional 9 Bcf to 10 Bcf, which would further increase the total working capacity of Pine Prairie to over 40 Bcf.

At Bluewater, we completed drilling 2 additional fluid withdrawal wells. Over the long term, these wells will increase our storage capacity as well as provide additional cash flow from oil production.

We also remain on schedule to complete repairs to the gas handling portion of the Bluewater facility prior to the 2011/2012 winter withdrawal season. At Southern Pines, the integration of the back office, commercial activity and operations have been completed.

As noted in the last quarter's conference call, we experienced some delays in space creation due to some operational issues and received financial compensation from the sellers for certain of those matters. We have now adopted many of the same operating practices at Southern Pines that we have developed at Pine Prairie.

We also plan to make modifications to Southern Pines' manifold system and leaching system to improve operating flexibility and position us to cost effectively increase the space creation capability and make up some of the delays. Since our last conference call, we commenced leaching operations on cavern well 4, and we expect to bring this cavern into storage service in the second half of 2012.

We are also conducting solution mining under gas within existing caverns as market conditions permit. In aggregate, our current forecast for 2011 capital expenditures is approximately $100 million, which is $3 million lower than the estimate provided at the beginning of the year.

To accommodate changes in timing, scope, et cetera, we have included in our guidance a range on our projected capital investment of minus 4% to plus 2%. The reduced forecast and potentially lower year end total capital expenditures are attributable to the net effect of some timing adjustments and the fact that we expect our larger projects to end the year slightly below budgeted costs.

Overall, the first 7 months of 2011 have been very active and productive with respect to creating additional capacity integrating the Southern Pines acquisition and fine tuning our organization, and we are pleased with our activities in that regard. So all in all, the controllable or manageable elements of PNG business activities are progressing pretty much according to plan.

However, market conditions for natural gas storage, something that we obviously don't control, have deteriorated beyond what we had forecasted at the beginning of the year. With that in mind, let me spend a few moments addressing the primary factors that are driving the current market environment for Firm and Hub Storage services.

There are a couple of primary market indicators for storage values. First, our seasonal spreads or intrinsic value.

In recent months, these spreads, which were already at a 3-year lows at the beginning of 2011, have continued to tighten significantly. The October to January spreads appear to have settled into a fairly tight range between $0.37 and $0.50 and are now near 5-year lows.

As illustrated on Slide 10, this compares to spreads that range from approximately $1 to $2 less than 21 months ago. The second item is volatility, which is a proxy for extrinsic value.

As indicated on Slide 11, volatility measures are currently running only about 1/3 of the levels experienced 2 years ago and over 30% below the level at the beginning of 2011. We believe the fundamental drivers for the lower spread and reduced volatility levels include the following: First, there's been relatively balanced supply/demand picture.

The rapid increase in shale production combined with a lack of non-weather related demand has been more than offset by record incremental weather-driven consumption over the past 3 seasons. Of a particular note, as illustrated on Slide 12, for the first time in 30 years, we have had 3 consecutive seasons of warmer or colder weather than the 30-year average.

Given the extended heatwave currently impacting the U.S., it appears we may be lining up for a record fourth consecutive above-normal season. Absent the incremental demand from this abnormal weather estimated at 200 to 300 Bcf of additional demand during the summer of 2010, we believe the U.S.

would have certainly tested the upper limits of storage capacity at the end of last injection season. Further contributing to this balanced supply/demand picture, colder than normal weather in Canada reduced supplies that would've otherwise been imported to the U.S.

during the 2010/2011 season by an estimated 130 Bcf. Second, there has been a change in the composition of gas supply with the declining percentage of production coming from the Gulf of Mexico and an increasing percentage of domestic production coming from onshore sources.

The perception is that this change lowers the risk profile of natural gas supply. However, we believe that the combination of freeze off and the significant initial production declines associated with shale gas production present new and different risks related to stability of supply that are not yet fully appreciated by the market.

Finally, there is currently a high level of regional storage on storage competition resulting from both new build capacity and recontracting activity as term contracts on existing capacity expire in a weak market. Although other factors such as lower LNG import have also contributed, the bottom line is that supply and demand remain relatively balanced in the current market environment.

And accordingly, there is a lack of concern or fear about running out of either gas supply or storage capacity. For so long as this attitude prevails in the market, storage conditions will likely remain soft and firm storage rates will continue to be under pressure along with reduced hub service and optimization opportunity.

I should note, however, there are a few positive signs that could lead to a better market and more encouraging storage outlook. Number one, gas demand is expected to rise significantly over the next 5 years led by power generation growth from coal to gas switching, coal plant retirement and gas start capacity addition.

Number two, a number of permitted new build storage facilities and expansions of existing facilities have been canceled or deferred, presumably due to market conditions. And number three, recent actions at the FERC suggests that tightening of processes with respect to permitting both new facilities and expansions of existing facilities.

Nonetheless, these positive long-term fundamental factors are not yet strong enough to cause us to change our near-term outlook, which envisions storage rates, service levels and short-term opportunities that are markedly different from our outlook at the time of PNG's IPO in early 2010 and also less favorable than our revised outlook provided during the first quarter of 2011. In fact, since our Analyst Meeting in June, continued historically low spreads and lack of volatility plus additional data points have led us to conclude that current market conditions are likely to persist for the near term.

On a relative basis, however, PNG's overall contract position is favorable for this environment and provides solid support for our cash flow over the next few years. For the 2011/2012 storage season, approximately 95% of our capacity is subject to third party contract, taking into account that we actively manage any disconnects between when storage is predicted to come on line and when our storage contracts begin.

The majority of the remaining storage capacity for the 2011/2012 storage season is leased to our Commercial Optimization group. I would also note that the remaining tenure of our storage capacity leases to third parties ranges from 1 to 10 years with the remaining weighted average tenure of approximately 3.5 years.

Slide 13 provides a graphical representation of our cumulative contract position for the next several storage seasons. Our percentage capacity under third party contracts for the 2012/2013 season remains high at approximately 80%.

The decrease from 95% to 80% is primarily associated with bringing additional capacity on as opposed to contract expiration. With that description of market conditions and PNG's positioning, let me address our guidance for the balance of 2011.

As shown on Slide 14, we have revised the midpoint of our adjusted EBITDA guidance for the full year of 2011 downward by approximately 2% to $104 million. Notably, this decrease in the midpoint of guidance was driven by decreasing the upper range from $111.5 million to $107 million driven primarily by the fact that we see less upside from Hub Services and optimization-related activity in this environment, as well as downward pressure on rates for uncontracted space.

The lower end of the annual guidance range remain relatively unchanged at $101 million. We are forecasting adjusted EBITDA for the third quarter of 2011 to range between $24 million and $28 million, with the midpoint of $26 million.

The implied midpoint for the fourth quarter of 2011 is approximately $31 million. As I mentioned earlier, our guidance for the second half of the year incorporates the accelerated realization of certain Hub Services activity into the first half of the year that was originally forecasted to occur during the second half of the year.

Included on Slide 15 is a condensed capitalization for PNG at June 30, 2011, PNG ended the second quarter with a debt-to-capitalization ratio of 25% and debt-to-adjusted-EBITDA ratio of 3.8x. Subject to covenant compliance, PNG's committed liquidity was $172 million at June 30.

As a result, PNG is positioned to finance its projected organic growth capital for 2011 and 2012 without the need to access the capital markets. We continue to believe PNG's solid capital structure, attractive contract portfolio and low cost expansion projects position PNG to grow and prosper.

In fact, as a result of our attractive contract portfolio and the construction of additional storage space at very low unit costs, PNG is positioned to generate 15% to 20% growth in EBITDA in 2012 relative to our 2011 guidance midpoint even assuming the current market conditions persist through 2012. However, given the deterioration and market condition and the cloudiness of the near-term outlook, we have reviewed potential impacts to our distribution outlook and in his closing remarks, Greg will cover the scenarios we have considered in the conclusions we reached.

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

Thanks, Dean. During my portion of the call, I will discuss capitalization and liquidity and provide comments on PAA's guidance for the third quarter and full year of 2011, as well as provide a summary of the financial impacts of the Rainbow incident.

As summarized on Slide 16, PAA exited the second quarter 2011 with solid capitalization, approximately $2.2 billion of committed liquidity and credit metrics that are favorable to our targets. At June 30, PAA's adjusted long-term debt-to-capitalization ratio was 44% and our total debt-to-capitalization ratio was 49%.

Our adjusted long-term debt balance was approximately $4.5 billion, which includes $500 million of notes used to fund hedged inventory. The total debt ratio includes $1 billion of adjusted short-term debt that 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, 2011 consisted of approximately 17 million barrels equivalent with an aggregate value of $1.45 billion.

Our adjusted long-term debt to adjusted EBITDA ratio was 3.2x, and our adjusted EBITDA to interest coverage ratio was 5.9x. As shown on Slide 17, PAA's consolidated long-term debt primarily consists of senior unsecured notes and including balances outstanding on the revolving credit facilities, has an average tenure of approximately 9 years.

We have no maturities until September 2012 and approximately 93% of our long-term debt balance is fixed in an average rate of 5.9%. I'll now move on to our guidance.

The high point of our third quarter and annual 2011 guidance are summarized on Slide 18. For a more detailed information, please refer to the 8-K that we furnished last night.

We are forecasting adjusted EBITDA for the third quarter of 2011 to range from $310 million to $340 million with an adjusted net income ranging from $167 million to $207 million or $0.73 to $0.99 per diluted unit. The midpoint of our full year 2011 adjusted EBITDA guidance has increased to approximately $1.38 billion, a total increase of $159 million over our beginning of the year guidance, representing solid execution and strong industry fundamentals.

I would note that a significant portion of the strong performance in the Supply and Logistics segment is from our Lease Gathering business, which is benefiting from strong fundamentals as a result of first, higher volumes due to increased oil production related to the active development of crude oil and liquids-rich resource plays; and two, higher margins as a result of production volumes exceeding existing pipeline takeaway capacity in certain regions and the associated logistic challenges. Since a portion of this stronger performance is the result of these fundamental drivers versus market factors, we believe it is additive to our baseline cash flow.

Slide 19 outlines PAA's 2011 implied distributable cash flow based on the midpoint of our guidance range. Assuming achievement of our 2011 midpoint guidance and distribution growth goal, we expect to generate distribution coverage for the year of approximately 120%, highlighting that we should be in a position to retain approximately $160 million of cash flow in excess of distribution.

Before turning the call back to Greg, I wanted to provide some additional detail regarding the financial impact of the Rainbow Pipeline incident that Harry mentioned earlier. We currently estimate the response, clean up and remediation cost related to the incident will total approximately $72 million.

In our second quarter financials, we have recorded this liability. However, since we maintain insurance for this type of incident, we have accrued a $59 million receivable, net of deductibles, for the portion we expect will be reimbursed by our insurance carriers.

The remaining net $13 million was expensed in the quarter. We estimate the aggregate economic impact on the second quarter's results is $23 million, which includes a net $13 million expense and approximately $10 million in lost revenue associated with the release as well as the downtime associated with unrelated forest fires that occurred in the vicinity during May.

I would mention that our estimates are subject to refinement in the future as we conduct the clean up and remediation operations and collect further information. One final comment, in mid-May just after our first quarter earnings conference call, S&P affirmed PAA's BBB- credit rating and revised our outlook to positive from stable.

We are very pleased with this acknowledgment of our increased size, diversity, solid fee-based cash flow and balance sheet strength. With that, I'll turn the call over to Greg.

Thanks, Al. As highlighted throughout today's call, PAA delivered excellent first half performance, reinforcing our belief that PAA's assets and business model are well positioned for the current environment.

On the strength of this performance and our positive outlook in the second half of the year, we have increased the midpoint of our full year guidance for the second time and are currently targeting adjusted EBITDA for 2011 of $1,384,000,000. This represents a 13% increase over the $1,225,000,000 provided in the beginning of 2011.

We have also increased our quarterly distribution in each of February, May and August and are on track to meet our distribution goal for 2011, which is to pay a distribution in November of 2011 that is 4% to 5% higher than the distribution paid in November 2010. Looking beyond 2011, we believe PAA is well positioned to deliver 3% to 5% distribution growth for the next few years, primarily through the advancement and execution of our large portfolio of organic projects.

Furthermore, we remain very active and disciplined on the acquisition front. Based on our historical experiences, the addition of meaningful acquisitions will further enhance and extend our visibility and capacity for distribution growth over time.

I also want to make a few comments regarding PAA Natural Gas Storage or PNG. On a consolidated basis the Natural Gas Storage business is small relative to PAA as PNG comprises less than 8% of PAA's total adjusted EBITDA.

Accordingly, at this early stage in PNG's growth cycle, even a material variation performance of PNG has a very minor impact on PAA. Nonetheless, PNG is a separate publicly traded entity under PAA's umbrella and our relationships with all of our stakeholders at PAA are very important to us.

As Dean highlighted in his comments, the controllable aspects of PNG's business strategy and business plan are generally on track. Unfortunately, most significant non-controllable factor, which is overall market conditions for natural gas storage, has deteriorated rather dramatically over the last 18 months.

Clearly, markets change from time to time, but developments over the last few months suggest these conditions could be with us for a while. We believe PNG's existing contract portfolio and ability to add storage capacity at very low cost position PNG relatively well with respect to the weak storage markets.

We also believe many of these storage market conditions will correct over time. All that said, however, we are clearly in new territory and the duration of the challenging market conditions is uncertain.

In refining our near-term and intermediate-term distribution outlook for PNG, we have run a number of scenarios that assume a variety of market conditions, including an extended duration of challenging market conditions. We have also considered the unique characteristics of PNG's capital structure, which includes common units, Series A subordinated units and Series B subordinated units.

Plains All American holds all of PNG Series A and Series B subordinated units, as well at $28.2 million or 48% of PNG's outstanding common units, plus the general partner's 2% interest in incentive distribution rights. As you may recall, the Series B subordinated units are noncash paying units that convert to Series A subordinated units upon receiving volumetric performance levels at Pine Prairie and PNG earning and distributing certain targeted distribution levels.

The volumetric performance benchmark for the first tranche of Series B subordinated units has been achieved. The first distribution threshold for those that tranche $1.44 per unit.

Upon meeting the second task, $2.6 million Series B units will convert the Series A subordinated units and thus, begin participating in cash distributions. In connection with the announcement of the Southern Pines acquisition in December 2010, we established a target to exit 2011 with the distribution of $1.45 per unit, which translated into a year-over-year distribution increase of 7.4%.

Based on what at the time appeared to be conservative assumptions with respect to market conditions, we expected to be able to generate sufficient, distributable cash flow to, not only achieve the 2011 targeted increase but also as a result of adding new storage capacity at very low cost, to be able to continue to grow PNG's distribution at mid-single digits for the next several years. In effect, the market rates that existed in December of 2010, the addition of new storage capacity would more than reduce -- offset reduced revenues over the next few years associated with the recontracting of existing storage capacity under higher price contracts.

Given the subsequent further deterioration of market conditions, the uncertain duration of these conditions and unique aspects of PNG's equity capital structure, we have refined our targeted 2011 exit distribution level to PNG. Taking a number of factors into consideration, we believe it's prudent to modify our target distribution level for the November 2011 distribution to $1.43 per unit as opposed to the previously targeted exit rate of $1.45 per unit.

Achievement of this distribution level will still result in PNG growing its distribution by approximately 6% during 2011 versus the 7.4% that was targeted under more favorable market conditions. Notably, as a result of targeting distribution level below the distribution performance threshold for the first tranche of Series B units, PNG will have 2.6 million fewer units to service.

This modification will increase coverage for PNG's common unitholders and secure a higher level of flexibility and financial strength for the PNG. Reducing our target distribution exit rate for 2011 was not what we envisioned at the beginning of the year or even as recently as our June Analyst Meeting.

However, PNG follows the same philosophy and practice as PAA of doing the right thing for the long term even when it may not be the most popular in the near term. Looking beyond 2011, the volumetric growth of PNG storage capacity illustrated on Slide 19 is expected to offset or substantially mitigate the negative impact of any recontracting existing storage capacity at lower storage rates should these market conditions persist for an extended period.

Although the deterioration in market conditions adversely affects our multiyear growth visibility from existing assets, we believe these conditions may well make acquisitions and consolidation more likely. With that in mind, let me address PAA's strategic objectives for PNG.

Plains All American formed PNG to create a growth platform for the Natural Gas Storage business and potentially for natural gas pipelines. Taking into account PAA's GP IDR structure and the substantially fee-based nature of PNG's business, PNG has a lower cost of equity capital than PAA and also provides the potential for like-to-like equity exchanges to assist us in consolidating the natural gas storage sector.

We continue to believe that this will prove a successful endeavor, perhaps even more so in a challenging environment, as we believe PNG is relatively better positioned than several other industry players not only with respect to its quality asset base and solid contract position, but also with a strong sponsorship and alignment of interest with Plains All American. Additionally, should market conditions improve and stabilize, PNG is very well positioned to generate meaningful growth just from operating and developing its existing asset base and PAA will participate in that growth in a meaningful way with its equity holdings and structural leverage provided by its ownership of PNG's incentive distribution rights.

In summary, the first half of 2011 has been a very productive period with solid execution of both PAA's and PNG's business plans as we have delivered solid performance relative to our operating and financial guidance. 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 the third quarter call in early November. Shannon, at this time, we're ready to open the call up for questions.

On PNG, can you discuss a little bit more about your long-term outlook for a distribution growth?

Brian, I can't add much more than what I put in the call. I think as we look out, clearly, as the slide that's still up on the screen, if you're looking at it, it shows we're going to add a lot of low cost storage.

I think part of it just depends on what rates we put on that storage and as it affects recontracting rates. We feel good about $1.43 both because of the structural positioning relative to as it affects Series B, and we feel good about our ability to execute on our plan.

What we just don't know right now is there's just not a lot of visibility in the future on distribution rates. If we had to model here and you can put your inputs into it, we can spit that answer out.

But obviously, we can't control what's going on in the market.

Turning to lease gathering volumes. Can you provide some more detail on the transportation logistic issues you discussed during the call that affected volumes a little bit, but also helped generate high margins?

Some of it was weather related, some of it was just getting the equipment and service that we had some timing delays on delivery of equipment on recent contractors. So a combination of those 3 really drove some of the volume differences.

And we also had some lower margin volumes that we ended up not renewing in the quarter so a couple of components of the logistical issues.

The weather, Brian, we're in the Rockies, Upper Midwest area where you had all the rains. And so if [indiscernible].

And how sustainable do you think these high lease capping margins are?

For the foreseeable future, that is to say the next 6 to 18 months, it varies by region. Part of the reason why you have the higher margins, Brian, is just simply there's an excess of production capacity relative to pipeline takeaway capacity.

So there's -- people are basically pricing in the margins to bring the assets, the movable assets to trucks and rail to those areas. Ultimately, over the long term, pipelines will get built if the volumes are sustainable, and margins will come down.

For companies that have -- that are building the pipelines and also are entering into longer-term contracts for the supply, I think we're going to capture a fair portion of that. And I think that's what Al was referring to when he said we think a lot -- a portion of this is sustainable.

But clearly, a portion of it are market aberrations. You've got really wide differentials right now for other reasons, and I think we all agree that in 2 or 3 years, a lot of those issues are going to go away because pipelines are going to it built out of Cushing, et cetera.

So it really varies region by region by region, wouldn't you say, Harry?

It does, yes.

One question on oil and one question on gas. Where are you seeing most of the bottlenecks, the biggest bottlenecks right now in the oil side?

And as a subset to that, what can you -- what color can you give in terms of Cushing right now in terms of inventory levels or how much has been drawn down or how much of a bottleneck is still there?

It's about 36 million barrels of crude in storage in Cushing. A fair amount of it, some of it's operational.

You're always going to have an operational and just a pipeline hub where clients come in and buy time on the pipes and get distributed out to refineries in smaller volumes. So the volumes have come off the peaks.

As I said, there's still about 36 million barrels of storage sitting in Cushing. As far as -- I think you asked for what some of the logistical issues were...

Where do you see the biggest couple of logistical issues right now?

The Eagle Ford has to be one of the largest. There's a lot drilling going on in the Eagle Ford, a lot of rigs running and very little pipeline infrastructure.

So right now, trucks are moving the vast majority of the excess volumes that came from pipes. There's also some rail facilities that are being placed in service.

We have access to rail facilities starting this month in the Eagle Ford so that will help alleviate some of it. Bakken, another area where we've got transportation strengths.

You're starting to see even a little bit in some areas of Western Oklahoma and West Texas as well.

Stephen, if you recall a couple conference calls, and I caught grief from a few people because I used an analogy of basically it's like trying to shoot a bird in a crossing pattern and the wind's blowing from different directions. What's happening is each area has, again, its own signature.

For example, the Eagle Ford -- as Harry just mentioned -- There's really an absence of a main infrastructure there to move crude oil out, but there's a lot being built. I think there's been 5 projects being announced.

There's a lot of rail solutions coming into play there. The Bakken, that's an immature area, but the solutions are on the way.

The Bakken is a maturing area, but because production continues to ramp up, a lot of the solutions have been put in place, have not been adequate to solve the problem. So you need incrementally more.

So there's still more rail and more pipeline solutions coming up. And so it's -- that's the cross winds I was mentioning earlier.

The bird's not staying in one place. It's flying across.

And weather delays like we had in the second quarter have affected also some of the logistical projects that are being advanced. So really, I think, Harry hit it.

It's the Bakken, the Eagle Ford, West Texas and Oklahoma. But every one of them has a unique set of circumstances that dictate what the bottlenecks are.

And then, in the bigger picture at Cushing, as you referenced, you've got probably, and we've said this publicly, we think there's probably 55,000 to 60,000 barrels a day imbalance of crude coming in versus crude going out. But some of these solutions we talked about, for example, Bakken there's new crude being rerouted away from Cushing.

It's taken some of that pressure off, but at the same time, there's more crude production coming from West Texas and the logical home for that is in Cushing. So it's probably fair to say that for the next 12 to 18 months in general, there's going to be pockets of these imbalances, and there's going to be shorter-terms solutions, and then inevitably there maybe some overkill that goes on with respect to some of the longer-term solutions so we end up with too much pipe coming out of there.

But it's hard to forecast that at this point in time because you don't know which of the many projects that have been announced are actually going to get done.

Let me just add just on the West Texas comment. Really, it's kind of a little different than the other areas because they have an infrastructure in West Texas.

It's mainly access to trucks. So we're sort of looking forward trying to get ahead of the curve.

That was the reason we expanded Mesa. You're not seeing constraints on those export pipelines today.

But the constraint there is really the extensions in some of the areas like the Bone Spring, the Avalon where infrastructure isn't quite out that far, from trucking equipment to bring volumes into the existing infrastructure.

My last question is on the gas side and thanks for all the color on it. Considering PNG is your growth platform, you do have a longer-term view on it.

And the stock is relative to the market bumpiness, held relatively well and some of your other peers have not in terms of the gas storage stocks. Is this indicative of what you think is going to happen in terms of the acquisition market?

Are there going to be -- are seller prices going to come down? Does it benefit you at PNG to get bigger?

Does that help you get into different areas if the opportunity presents itself? Is it something that you're actively looking to do with your currency?

In my view, still bringing very good for you.

We form PNG to be able to have a better currency, as you referenced, to actually to build out that platform. I guess the short answer to your question is do we want to get big in that area?

Absolutely. And that's really why we created PNG.

These market conditions are frustrating with respect to the expectations you have with existing assets. But it actually, I think, could prove favorable for acquisitions and consolidation.

As to whether the acquisition multiples come down, time will tell. But I think we're better positioned than most, and we certainly have a favorable view toward trying to build that platform and we're pretty creative, I think, about how we could attack some of those opportunities.

So I think it's going to take a little bit of time to set in. You may recall, we first announced that we thought the market was started to soften, I believe, in our July or August call of 2010.

And I think we were probably 5 or 6 months ahead of the recognition in the industry in general. Having said that, we still didn't see it coming as severe as it has.

So I don't want to take too much credit for that. But I think it's taken a while for the reality to set in that rates have fallen as far and as fast as they really have.

And we prepared, and I said, we tried to put the contracts in place and we made sure we have the ability to add capacity at low cost. So we've got everything settled in for PNG's existing assets and we're looking to add more.

Greg, I just have one quick question, and it goes back to a point that Harry was just talking about with all the recent announcements around crude oil and condensate volumes ramping out of the Eagle Ford and West Texas and a lot of that being pointed to Cushing and possibly even some down to Corpus [Corpus Christi]. So I was curious, with the competitive landscape changing, that's got to mean more opportunity for you guys.

And in particular, I'm thinking beyond the capacity additions on basin, beyond what you're doing with that Bone Springs project, which I think is going to get about 65,000 more barrels into Cushing. But as you think about getting a lot of those volumes east, those systems in particular are in a great position to continue to leverage off of.

So can you just give us some insight, maybe as it relates to the next 6 to 18 months thought process as you continue to see a lot of those Gulf Coast crude oil logistics change?

I commented on sort of the prepared remarks. I mean, we're seeing an unprecedented number of opportunities in the areas where we have assets; a lot of the build out, a lot of expansions, some new pipeline opportunities.

Not all of them we're able to talk about today and, you know, so we couple those with, alright now, how do you get crude to the right location because it can't all go towards Cushing. And that's why we think rail's going to be an important component of it -- with our Wascana reversal takes crude out of the -- crude that would otherwise move into the Cushing quarter and moves it further east.

We like our Eagle Ford project because it has the capacity to deliver crude to refiners, but also get on the water and move to multiple locations once it's on the water. So I think we've got a backlog of opportunities that we're pursuing.

I'll have to say Darren, we have really 2 primary types of customers in the oil or liquids business. We have customers on the demand-driven side of our business, which are primarily the refineries.

And then we have the customers on the supply-driven side, which are the producers. And our job is to make sure we provide services to both of those.

We would love to be able to be the only transporter of crude in any given area, but the reality is we don't own or control. There's a lot of competition out there.

So for example, in the Mesa pipeline, we work to try, with some logistics, to try and make sure that as production volumes ramp up in West Texas, we work together to make sure we can get them all out of there because it doesn't do us any good to have crude oil stranded. So with the expansion of Mesa, I think it's about 110,000 barrels of oil a day, the expansion of basin and then Sun is working on their West Texas Gulf to increase its capacity and get different markets.

I think it's good for all of us. And it's good for the producers, and we've tried to get ahead of it there.

So it and then there's some competitive areas where as much as we work with Sun Logistics in certain areas, we're also trying to compete with them to capture opportunities. So it's a little bit hard for us to give you much more color than we have without showing our playbook.

And as you know, these conference calls are available to anybody. So I'd be surprised if some of our competitors aren't listening to our comments and I assure you we're going to listen to theirs.

On one point that you made, though, as you're talking to producers, how big of an opportunity do you think it's going to be and not just for the latter Eagle Ford type crude oil, but also the condensates, to leverage that footprint in St. James to get a lot more of their product to the Patoka market, but even beyond Patoka and possibly even get into the Northeast.

I mean, it would seem to me on a go-forward basis, especially with a lot of the Cushing to Gulf Coast projects announced whether or not they all get built, you're going to have a significant regional pricing opportunity leveraging St. James.

Am I thinking about that the right way?

I think you are, except to realize that as soon as you develop a solution for the pricing differentials then they come in very significantly. You've seen it already happened in the gas business.

They used to have big, wide regional differentials for natural gas. Everybody built new pipelines, then it all went away.

So I think some of those are temporal. I think what we are focused in on doing because we're an MLP that distributes cash flow, we want to distribute and have a solid distribution base and we want to be able to increase over time.

We're going to capture some of those low-hanging fruits but they won't be there for an extended period of time. What we're going to do is try to make sure that we permutize a lot of those margins through having the right infrastructure to connect it all together.

And I think you are correct. If your question is the St.

James going to be an important part of that solution? Absolutely, as well Patoka.

I think something that's starting to be recognized in the industry is when you look at what's coming out of Eagle Ford, what's coming out of Bakken, what's -- what could be coming out of areas such as Utica Shale and things like that, these are very light volumes. And so you're talking about probably an aggregate, no matter whose story you believe, at least over 1 million barrels a day, a very light product.

And it's going to change the dynamics in an industry that's been gearing up for heavy or sour product. And I think Patoka, St.

James and Corpus Christi are part of those solutions, as well Cushing, continue to be an important player there. And we're represented all those areas so we sort of like where we're at.

And I'll just add on to what Greg said, just we've got a rail offload facility at Patoka. We're doubling that capacity at St.

James. We're doubling our capacity.

And obviously, as we look at rail infrastructure in some of these basins, we're also looking at alternative markets for the rail as well. Just not far enough along to discuss all the projects we're looking at.

Two quick questions for me. One, really, I guess on the PAA side, given all the recent negative economic data that's been coming out on the U.S.

economy and globally, really, I was just sort of wondering what kind of baseline economic environment is baked into your guidance for the rest of the year at PAA?

Well, at the risk of always sounding like we think the sky is falling in certain areas, I think if you recall a little over a year ago, we came out and shared that we thought it was going to be a tough economy and tough sledding in general, and we still think so. I don't think anything has changed our outlook there.

So we kind of run our numbers off of the near term of GDP growth of sub-3%, which is certainly not an exciting thought. We think interest rates are going to fluctuate quite a bit because there's a combination of international issues that are going on too, that it's just hard to predict where those are going to go.

But we bake in a longer-term cost of debt capital in the 5% to 10%, let's give you 5% to 6% range, versus currently LIBOR's at sub-1%. We just don't view that as permanent capital.

As far as if you were to ask us what we're physically setting up for the demand side of our equation, I mentioned earlier we've got a demand-driven side, we got a supply-driven side. On the demand-driven side, I think here we're running probably kind of an outlook for 19.3 million to 19.5 million barrels a day of petroleum demand in the U.S., which is about where it's running.

It says it doesn't get much better any time soon. A unique aspect that's happened, I'll say unique, an interesting aspect that's happened over the last 4 or 5 years is the refineries are still running at fairly high run rates even though the demand is down almost 9% from 20.7 million barrels to 19.3, the issue that's offset that is the ability of exports and the reduction of refined products imports.

So we've gone from 3.8 million barrels a day of refined products; imports in 2005, we're down to probably in the 2.3 million, 2.4 million barrels a day, refined products imports. We've gone from, in 2005, 1 million barrels a day of refined products exports to today, we're probably 2.3 to 2.5 of exports.

So we're down 1.3 million in imports, and we're up 1.3 million in exports, which is a 2.6 million barrel baseline. Well, that's what allowed these refineries to keep on running.

So our view is even though the 19.3 million to 19.5 million is far down from where the U.S. was running in terms of consumption, the refineries that we service are actually doing fairly well in this environment because of the ability to reduce imports and increase exports.

And so that -- I don't know if I answered you correctly, but that's the kind of environment we built into our model. And then on the supply side of it, with these higher prices and the attractive margins that at least in the core areas of these resource plays are going on, we expect volumes are going to continue to pick up there, which further reduces, by the way, the amount of foreign oil imports we move, right?

So we've had 600,000 barrel a day increase in domestic lower 48 production and we've seen a corresponding decrease in foreign crude oil imports. That's why you see our volumes being down in our foreign cargoes.

I think we're down from 75,000 barrels a day down into the 20s or 30s. Part of that's just simply being that it's being replaced by domestic production.

That's probably a lot more that you wanted to hear, but it's a complex situation. But I think if you look at our map at PAA, we've got all the assets in the right places and our job is to make sure we execute and capture the sustainable margins, and then we're also going to tick off some of the attractive unsustainable ones, but we'll pass on a few of those if we can just make sure we lock in the longer term.

The other question I had was on PNG. So you've sort of recalibrated your expectations around distribution increases there.

I'm curious what your thought is in terms of reevaluating all of the expansions that you have lined up at those facilities, really. And is there a thought to reevaluate that given how if the market persists at this sort of level for a sustained period?

Depending upon which of the scenarios that you wanted to embrace that we run, I mentioned earlier we run several. Even at -- so our capital program in years 2, 3 and 4 from today look different under each one of those just whether we drill more caverns at either in Pine Prairie or Southern Pines.

But what doesn't really vary between any of those scenarios is the ability to capture some incremental volumes at very attractive prices. On, I think, Slide 19, we were showing that we can basically increase our capacity about 50% from where we are right now.

And 75% of that increase is in the high performance basalt [ph] cavern is, excuse me, 75% growth of basalt [ph] is basically a combination of fill/dewaters and snubbing [ph] . And that cost per Bcf is in the $3 million to $4 million range.

So consequently even at these rates, we're still able to generate 20% and 30% rate of return by adding that space. So we're going to do those because we do think these are market conditions that are self-correcting.

You can imagine what the economics look like if we build that out at that cost and then it comes back at a higher level. But we will moderate what I call the significant capital test, drilling a new cavern, putting new pipelines, et cetera because today, even though we think we can do it cheaper than almost anybody else in basalt [ph] , those rate of returns are probably closer to the 11%.

And there's still some risk of some downside pressure there so why take that? But when you run your worst case scenario and you still come up with 20% rate of returns, it's not a bad solution.

I'm just curious, I don't know if you even break it out this way, but in terms of your logistics or I guess what you used to call marketing, I'm just curious in terms of capturing, I guess, the differentials between WTI and LL, Louisiana Light Sweet and Brent, obviously -- I mean, are you getting more of this from truck, rail, barge? I mean, in terms of your assets, you're talking a little bit about trucks.

Is that where you're capturing most of it? And is there any sense you can give us about approximately percentages or is that -- I don't know how much detail you can give.

Let me see if I can answer it this way because I can't give you a direct answer. If you said -- we got 6 floors here and 3 out in the center, and if you get on there, no matter hope who steps on the elevator bank lift, if you ask them if they're busy, they all say, "More than I've ever been."

So the answer is yes to rail, yes to truck, yes to pipeline, yes to the arbitrage opportunities in the market. It's really across the board.

I think what you should take away is we had a stellar second quarter. We guided to a third quarter that's above what we would have given at the beginning of the year, but still below what we've given you for the second quarter.

And so we try not to include in our forecast that which may come, but we really can't be certain about. And so for the visible period, I think the guidance we're giving for the second half as indicated what we think is a combination of baseline plus market opportunities that we would have locked in or highly confident we'll lock in and if the market continues to stay in this type of a volatility and kind of favorable conditions for the reasons you described, I think there is an upward bias to the midpoint of our performance.

And then how much additional capture do you think you can get? I mean, obviously, there's a number of reports out indicating that the spread could widen even further next year on the order of $40 to $50.

How would that roughly translate in terms of upside potential capture?

Our crystal ball is just not that good and anybody that thinks they can predict $40 to $50 spreads out there, I think I shouldn't be telling you, but they ought to be beaten. My bad.

But at least, they're probably selling reports as opposed to putting your money at risk. But I would tell you this, never underestimate the market's ability to solve problems.

And if there's a wide enough differential out there for any extended period of time, somebody's going to build an asset or develop or reversal pipeline to do something to take that away. We just never seen those -- it just doesn't make sense.

So I think part of these -- those are the transient type things and we'll certainly try to participate in, but we're not going to expend a tremendous amount of capital betting that those to stay out there and that we can capture them over an extended period of time.

And then just last question. I mean, with the favorable trade, it looks sustainable at least for the next 6 to 18 months at least, probably on the longer side of that.

Does that change your thinking on your distribution growth outlook at all to bump that up at all? Are you still going to stick with the kind of 3% to 5%?

I think we're going to stick over an extended period of time to 3% to 5% because we believe we have that under our control to the extent that there are opportunities or that these things mature into sustainable margins, et cetera, I think we certainly have an upper class to that. This year, we guided to the upper end of that 3% to 5%.

We said in the 4% to 5% range, and we're certainly on track to achieve very close to, if not near the very top of that range. And I think what most of our investors, over time, really want is if we could raise it, John, and you tell me if we could raise it 7% this year and I had to drop to 3% next year because of things that I can't control, is that better than having two 4.5% raises year-over-year and being able to extend that out?

Our belief is, is that our investors want stability. We think we represent -- we're not government -- we're not excellent on risk.

I'm not sure if I want to be a government risk. But we think we're very low risk because of the way we run our business and the fact that we underpin and really worry about the downside and still have an ability to capture the upside.

And so I think kind of have what I call jack rabbit races where it goes up one year and then comes down the next year. And I can't give you any visibility to what it will be 2 years out.

It's not nearly as valuable as saying buy us, we're going to deliver 3% to 5% growth with an upward bias and that's kind of probably where we'll stay.

Shannon, thank you. Thanks for everybody for participating in the call.

I know it's a very busy day for conference calls. And so for those that are able to participate, thank you very much.

For those that are going to listen to the replay, thank you for dialing into that, too. We'll sign off.

Thanks.