Plains All American Pipeline LP (PAA) 2011 Q4 法說會逐字稿

Welcome to the PAA PNG earnings 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). As a reminder, this conference is being recorded. I would now like to turn the conference over to our host, Mr. Greg Armstrong, please go ahead.

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 fourth quarter and full year 2011 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 the New York Stock Exchange ticker symbols of PAA and PNG respectively. As a reminder, Plains All American owns the 2% general partner interest, all of the incident distribution rights, and approximately 62% of the limited partner interests in PNG, which accordingly is consolidated into PAA's results. In addition to reviewing recent results, we will provide forward-looking comments on the partnership's outlook for the future, in order to avail ourselves of Safe Harbor presets 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 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 effects of these 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 have several other members of our management team present and available for the question and answer session.

With that, I will turn the call over to Greg.

Thanks, Roy. Good morning, and welcome to everyone. Let me start off today's call by briefly recapping PAA's fourth quarter and full year financial results. Yesterday after market close Plains All American announced fourth quarter adjusted EBITDA of $471 million. These results exceeded the midpoint of our guidance range by $61 million, or 15%, and were $46 million above the high end of our guidance range. This performance is in line with the increased expectations we communicated in our December 1 press release. In comparison to last year's fourth quarter, adjusted EBITDA, adjusted net income, and adjusted net income per diluted unit for the fourth quarter of 2011, increased 46%, 72%, and 67% respectively. These results and additional information are summarized on slide three.

PAA's fourth quarter results were driven by solid performance in all three segments, with supply and logistics being the larger contributor to overperformance. As shown on slide four , our fourth quarter results marked the 40th consecutive quarter that PAA has delivered results in line with or above guidance. As reflected on slide five, these results capped off a very strong year for PAA as we delivered year-over-year increases of 44%, 72%, and 73% for adjusted EBITDA, adjusted net income, and adjusted net income per diluted unit respectively. Additionally, last month PAA declared a 7% year-over-year increase in our annualized run rate distribution to $4.10 per common unit.

As shown on slide six, PAA has increased its distribution each of the last ten quarters, and in 29 of the last 31 quarters. As reflected on slide seven, during the remainder of today's call we will discuss our segment performance relative to guidance, our expansion capital program and acquisition activities, and our financial position. Throughout the call we will address the drivers and major assumptions supporting our financial and operating guidance for the first quarter and full year of 2012. The financial and operating guidance for the full year of 2012 includes our estimate of the contribution from the pending acquisition of BP's Canadian-based NGL business, based on an assumed closing date of April 1, 2012. We will make appropriate adjustments to our guidance if the actual closing date varies materially from that assumption.

At the end of the call I will provide a recap of 2011, a review of our goals for 2012, and our outlook for the future. We will also address similar information for PNG, as well as discuss the highlights of the modification in PAA's ownership of PNG. With that I will turn the call over to Harry.

Thanks Greg. During my section of the call, I will review our fourth quarter operating results compared to the midpoint of our guidance issued on November 2, discuss the operational assumptions used to generate our 2012 guidance, and I will discuss our capital program. Following my comments Dean and Al will cover the PNG specific information.

Prior to discussing our results versus guidance I want to point out that our fourth quarter results include the impact of $11 million equity related and cash compensation charge that was not included in our guidance. This charge is primarily associated with the increase in PAA's unit price and a modification in our outlook of the probability of achieving performance thresholds, and outstanding equity awards. And $11 million charge impacts the transportation, facility, and supply and logistics segments by $6 million, $1 million, and $4 million respectively.

As shown on slide eight, adjusted segment profit for the transportation segment was $160 million, which was $3 million, or about 2% above the midpoint of our guidance. Volumes for the segment of a little more than 3.1 million barrels per day were also approximately 2% above our guidance. On a per unit basis adjusted segment profit was $0.56 per barrel.

Adjusted segment profit for the facilities segment was is $107 million, or approximately $10 million above the midpoint of our guidance. Volumes of 86 million barrels were in line with guidance generating adjusted segment profit per barrel of $0.41 which was above the midpoint of our guidance. The primary contributors to financial performance were strong performance of PNG, higher throughput fees. and other ancillary fees at a couple of our terminals, as well as favorable performance of the gas processing assets. Adjusted segment profit for the supply and logistics segment was $200 million. Approximately $45 million above the midpoint of guidance. In total our volumes were 894,000 barrels per day, versus our guidance of 880,000 barrels per day. Adjusted segment profit per barrel was $2.43, or $0.52 per barrel above the midpoint of our guidance. The volume variance is due to higher than forecasted fleet gathering volumes. Our financial over performance in the quarter primarily due to improved lease gathering margins, favorable basis differentials, and stronger than forecasted Iso and propane margins.

Let me move to slide nine and review the operational assumptions used to generate our full year 2012 guidance, which was furnished in our Form 8-K last night. The guidance includes the benefit of the pending BP NGL acquisition with an assumed closing date of April 1, 2012. As we referenced in our acquisition conference call, and described in guidance 8-K, the categorization of revenues from among the segments and assumed volumes are subject to adjustment, as we integrate the assets, and apply our business model to these assets. We will keep you apprised of these changes as needed for modeling purposes as we proceed throughout the year.

With the transportation segment we expect volumes to average approximately 3.4 million barrels per day, which is 11% higher than the volumes in 2011, approximately 60% of the projected annual volume increase is related to the BP and Gardendale gathering system acquisitions. The balance of the increase primarily relates to increased volumes on our Permian base of pipelines, including the Basin and Mesa Pipeline systems. We expect adjusted segment profit per barrel of $0.60. The increase over the level experienced in 2011 is primarily due to an increase in the tariff index. Facilities segment guidance assumes an average capacity of 107 million barrels of oil equivalent, which is an increase of 25 million barrels over the 2011 volumes. The increase includes approximately 17 million barrels from the Yorktown acquisition and BP acquisition. 3 million barrels from a full year of service from expansion of the Cushing that was completed in 2011. And 15 Bcf of increased gas storage capacity.

Adjusted segment profit is expected to be $0.37 per barrel in 2012, slightly less than the $0.39 per barrel generated in 2011. The volumes for both the Yorktown and BP acquisitions include only the proportioned amount of package that we expect to have in service during 2012. Additional volumes will be added in the future, as we make the necessary modifications to place inactive tanks into service. Supply and logistics segment guidance volumes are projected to average 1 million barrels per day for the year, compared compare to 866,000 barrels per day in 2011. About half of the increase is associated with increased volumes from our lease gathering activities, and the balance is attributable to the pending BP NGL acquisition. Projected midpoint adjusted segment profit of $1.17 per barrel is lower than the level generated in 2011, but higher than levels generated prior to 2011. In essence, we still expect to generate favorable margins relative to his historic levels, just not as strong as the 2011 levels.

Let's now move on to our capital program. During 2011 we invested approximately $530 million, which is in line with the updated guidance provided last quarter. As reflected on slide ten, our expansion capital expenditures for 2012 are expected to be approximately $850 million. As is typically the case with our annual capital program this total is comprised primarily of small to medium sized projects. I will touch on a few of the more significant projects. Let me start with our Eagle Ford project. As reflected on slide 11, we expect to have the segment from Gardendale to Three Rivers in service in the third quarter of 2012, and the segment from Three Rivers to Corpus Christi in service by the end of 2012. The costs reflect a 50% interest in this project as we expect the LLC documents with Coke and Chesapeake to be finalized in the near future.

In the Permian Basin, we have a number of projects that extend and expand our systems in the North Sprayberry, South Sprayberry, Avalon Bone Springs area, and southeastern New Mexico. A map of our North and South Sprayberry system expansions, and additional information on our Barstow line which is in the Avalon Bone Springs area, is reflected on slide 12. In total, we will incrementally invest about $175 million in the Permian Basin area projects, of which approximately $110 million is forecast to be incurred in 2012. In addition to these projects we plan to have our Basin pipeline system expansion completed in March of this year. In Oklahoma, we have several projects underway, as reflected on slide 13 the conversion of our Medford pipeline from NGL service to crude oil service was completed last month. By July of this year, we expect to have the capacity on this line expanded to 25,000 barrels per day.

Earlier this week we announced the construction of a new 170 mile pipeline that will service growing Mississippian line production, northern Oklahoma and southern Kansas. The pipeline will be capable of handling approximately 150,000 barrels per day when combined with our Medford to Cushing capacity it will total 175,000 barrels a day. It is expected to be in service by mid-2013. The pipeline is supported by a long-term agreement to purchase SandRidge's production from a multi-county area around the new pipeline system. We plan to extend the line northward into Kansas based on market demand. We are very excited about this project, and believe that it represents a logical extension of our activities in both Oklahoma and Kansas.

As shown on slide 14, in the Bakken, we are still targeting to have our Bakken North Pipeline completed and in service by the end of 2012. At Ross, our rail operations for both crude oil and NGL are in service, and by the end of the year we expect to have capabilities of loading unit trains for crude oils in service. In addition we recently announced plans to construct a 50 million to 75 million cubic feet per day gas processing plant at Ross. These plans are still being finalized, and we will provide updates in future calls. As you can see, we have a full plate of opportunities in all of the major crude oil resource plays, and look forward to updating you as we are able to advance additional projects.

Maintenance capital expenditures for the fourth quarter were $43 million, resulting in a 2011 total of $120 million. Much of the fourth quarter increase was associated with our increased integrity investment on our Canadian pipelines. We expect maintenance capital expenditures for 2012 to range between $130 million and $150 million. And with the recent and pending acquisitions driving the increase over 2011 spending.

Moving on to acquisitions. We closed four bolt-on acquisitions during the fourth quarter of 2011, and executed and agreement to purchase BP's Canadian NGL business. We discussed these acquisitions in the call on December 1, so today I will just provide a very brief update. Integration of the Gardendale system and the assets acquired from Western will be completed in the next 60 days. With respect to the BP transaction, three out of four key regulatory closing conditions have been satisfied. The waiting period for the HSR expired in late January, and we have recently received required letters from the Competition Bureau in Canada, and the Canadian Minister of Transport. We have not yet received Investment Canada approval, but we are targeting an April 1, 2012 closing date, which could flip depending on the timing of that approval. While our Canadian team will be very focused on the integration requirements of the BP transaction, we will still continue to pursue strategic and accretive acquisitions throughout 2012.

And now I will 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 fourth quarter and operating and financial results, provide and update on PNG's operations, and review our first quarter and full year 2012 guidance, and our 2012 partnership goals. Let me begin by discussing the results we released last night. As shown on slide 15, PNG announced solid fourth quarter 2011 results, including adjusted EBITDA of $33.4 million, adjusted net income of $22.8 million,and adjusted net income per diluted unit of $0.31. These adjusted EBITDA results were approximately $3 million above the midpoint of our fourth quarter guidance range.

As shown on slide 16 for the full year PNG delivered adjusted EBITDA of $107.2 million, adjusted net income of $68.2 million,and adjusted net income per diluted unit of $0.97. These full year results were $1.2 million above the high end of our November 2 guidance, and approximately $1.2 million above the midpoint of our beginning of the year adjusted EBITDA guidance. Furthermore, we covered our distributions paid during the year by 109%, retaining approximately $8 million of cash flow in excess of distributions. Distribution coverage for 2011 on a trailing or declared basis was approximately 101%.

We are pleased with PNG's 2011 performance, especially considering these results were generated in market conditions that were much weaker than we forecasted at the beginning of 2011. I want to thank the entire PNG team for their contributions to these results. Operationally, we executed our overall 2011 capital program under budget and on schedule. Our capital expenditures during 2011 totaled $89 million, which was in line with the low end of our updated estimates last quarter. Among other things, these capital expenditures enabled PNG to place approximately 10 Bcf of washing working capacity in service in 2011, and create additional space that will be placed in service in 2012.

Additionally we have completed all as aspects of the repair to the gas handling equipment at Bluewater, and the facility has been operating as expected through the winter withdrawal season. During 2011 we also completed two liquids removal wells at Bluewater that had previously been slated for completion in 2012. We currently expect that our expansion capital expenditures in 2012 will total between $54 million and $60 million, we expect to place a total of approximately 16 Bcf of working storage capacity in service in 2012, for an average of 86 Bcf of working capacity throughout the year. This increase of capacity will consist of a fifth cavern at Pine Prairie that is scheduled to be placed into service in the second quarter, a fourth cavern at Southern Pines that is scheduled to go into service in the third quarter, along with capacity created by incremental leeching activities at both Pine Prairie and Southern Pines.

Let me now address current market conditions for natural gas storage and PNG's 2012 guidance in that environment. With regard to the gas markets in general, there has been considerable weakening of natural gas prices over the past several weeks. While this has created some short-term opportunities associated with an uptick in volatility, the prevailing trend over the last several months has been little change in the summer/winter spreads, and generally low volatility. Slide 17 reflects historical spreads and implied volatility measures, including the most recent increase in volatility associated with the lower price as I mentioned. Absent an increase in natural gas demand due to weather conditions and/or significant fuel switching, we believe that the very strong natural gas supply environment could test the limits of storage capacity this year.

We remain vigilant in pursuit of available commercial opportunities in the current market conditions, and believe that our commercial optimization team is well-positioned to capitalize on these potential opportunities. Nonetheless, we are positioning PNG to manage through a continuation of the challenging conditions we have experienced over the last 18 months. Financially PNG remains well situated as we enter 2012. Included on slide 18 is a condensed capitalization table for PNG at December 31, 2011. PNG ended the year with a long-term debt to capitalization ratio of 26%, a long-term debt to adjusted EBITDA ratio of 3.8 times, and approximately $125 million of committed liquidity. As a result, PNG has the ability to finance its 2012 capital program from existing financial resources, while maintaining a solid capital structure and credit metrics. Our balance sheet also positions us to take advantage of acquisition opportunities that may arise in the current market environment.

Turning to our guidance as shown on slide 19. We are forecasting adjusted EBITDA for 2012 to range between approximately $115 million and $125 million with the midpoint of $120 million. Despite the challenging market conditions, this represents a 12% increase over our 2011 comparable results, primarily due to low cost incremental storage capacity additions. For the first quarter we expect adjusted EBITDA to range from approximately $25 million to $29 million with a midpoint of $27 million.

As depicted by the chart in the upper right of slide 19, we expect relatively steady adjusted EBITDA for the first three quarters of the year with a seasonal increase in the fourth quarter. With respect to distributions for 2012, in early January we announced a quarterly distribution of $1.43 on an annualized basis. This distribution which is payable next week is equal to the distribution that was paid in November of 2011, and equates to a 3.6% increase over the distribution that was paid in February 2011.

As represented on slide 20, achieving the midpoint of our guidance for 2012 provides a solid 105% coverage of our existing distribution level. At the high end of the guidance range the distribution coverage is 110%, and at the low end the calculated coverage is approximately 1 to 1. I would note that similar to 2011 due to seasonality of our business that I mentioned previously we anticipate our strongest quarter will be the fourth quarter, and distribution coverage will vary from quarter to quarter. When considering our coverage, I believe that it is important to take into account the high quality of the cash flow that supports PNG's distributions. As we have highlighted previously, our coverage is solidly underpinned by a diverse portfolio of third-party firm storage contracts, with initial terms ranging from one to ten years in length.

As illustrated on slide 21, we commit a high percentage of our storage capacity to these firm storage contracts. For calendar year 2012 approximately 90% of our average capacity is contracted with third parties. As contracts roll off, the comparable percentages for 2013 and 2014 are approximately 70% and 50% respectively. In each case, without taking into account new contracts that we enter into in the future, but including incremental storage capacity we expect to place into service. Importantly, over 85% of our projected full year 2012 net revenue is expected to be generated from our current portfolio of third-party storage contracts, which consists predominantly of fixed capacity reservation charges. This number increases to approximately 90% when you include already executed contracts, the terms of which begin later this year. We believe the high quality cash flow generated by these contracts provides PNG with a secure and attractive distribution profile, especially in light of current market conditions.

However, given the expected continuation of challenging market conditions and related uncertainties, we are not in a position to provide a targeted distribution growth range for 2012. I can say that as a result of the modification of PAA's ownership in PNG announced yesterday, and which Al will comment on in a moment, we are much better positioned to deliver distribution growth to our unit holders if market conditions improve, or if we deliver sustainable overperformance relative to our guidance. Hopefully this gives you a good overview of our outlook for 2012. Our goals for 2012 which are outlined on slide 22 are to one, deliver operating and financial results in line with guidance. Two, successfully execute our organic growth program, and three, continue to selectively pursue strategic and accretive acquisitions. We look forward to updating you on our execution relative to these goals as the year progresses.

In conclusion, on behalf of PNG and our management team, I thank you for your investment and support. We believe PNG 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. Additionally, we believe these attributes will provide growth opportunities in the form of continued organic and acquisition related activities.

With that, I will turn it over to Al.

Thanks, Dean. Before I address PAA's financial information I want to add some perspective from PAA's vantage point about the modification of PAA's holdings in PNG Series B Subordinated units announced yesterday. I think the press release is fairly self-explanatory, and the details of the modification are included in the Appendix to today's slide presentation.

Summarized on slide 23, this modification was made in recognition of the continued challenging market conditions that are facing the natural gas storage business, and evidences PAA's long-term view for the natural gas storage sector. We believe the modification increases the value of the growth platform represented by PNG. It also benefits PNG's common unit holders by reducing the number of units on which distributions would otherwise be required to be paid in the case of distributions below the annualized level of $1.71 per unit. With fewer units getting distributions, lower aggregate levels of distributable cash flow, or DCF, will be required to increase the distribution up to the $1.71 level.

For example prior to the modification approximately $4.7 million of incremental DCF was required to increase the distribution by one penny per unit from $1.43 to $1.44 per unit. After this modification the amount of DCF required is approximately $840,000, or 83% less. Directionally the same type of relative difference holds true at preamendment Series B conversion benchmark levels of $1.53 per unit and $1.63 per unit as well.

While we can't change the market conditions that PNG faces, by implementing this modification we are alleviating a potential structural impediment to PNG's distribution growth, that enables PNG to translate any sustained improvement in operating results into distribution growth visibility. I want to also point out that we have taken similar steps to modify the equity incentives that were awarded to PNG's dedicated management team to adjust to these challenging market conditions, conform to the modification in PNG's capital structure, and better align management's interest with the common unit holders, while at the same time encouraging long-term retention. For additional information on this modification, please refer to the 8-K that PNG filed yesterday.

I wanted to share four observations from the perspective of PAA. First, natural gas storage is a relatively small portion of PAA's aggregate EBITDA. For 2011, PNG represented less than 7% of PAA's total adjusted EBITDA. Second, PAA has a positive long-term view on natural gas storage, and continues to view PNG as the preferred platform for growing its presence in the natural gas storage sector. Third, although the modifications to the Series B subordinated units owned by PAA defer its potential participation in distribution growth, even excluding the entire ownership represented by the Series B subordinated units, PAA holds approximately 57% of the outstanding common and Series A subordinated units, as well as the general partner interest and incentive distribution rights, and thus will receive the majority of the benefit from any deferred distributions related to the Series B subordinated units. Fourth and finally the modifications made to the Series B subordinated units will still allow PAA to participate in any meaningful recovery in the natural gas market storage conditions between now and 2018, while enabling PNG to be competitive for future acquisitions and consolidation within the natural gas storage market.

Let me now turn your attention to PAA's capitalization, liquidity, recent financing activities, and address PAA's guidance for the first quarter and full year of 2012. As summarized on slide 24, PAA exited 2011 with solid capitalization, $3.6 billion of committed liquidity, and credit metrics that are favorable to our targets. At December 31, 2011 PAA's long-term debt to total capitalization ratio was 43%. Total debt to capitalization ratio was 47%. Long-term debt to adjusted EBITDA ratio was 2.8 times, and our adjusted EBITDA to interest coverage ratio was 7.5 times.

I would note that our total debt ratio includes $679 million 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 December 31, 2011 consisted of approximately 15 million barrels equivalent, with an aggregate value of approximately $1 billion. These amounts do not include approximately 14 million barrels equivalent of line fill and base gas in PAA's and third-party pipelines and terminals, that are classified as long-term asset on our balance sheet with a book value of approximately $700 million, and a market value of over $1 billion. Furthermore, as we covered on our December 1 acquisition conference call, we are financially very well-positioned to close the BP Canadian NGL acquisition which closing is anticipated on April 1, 2012.

As reflected on slide 25, without regard to accessing the capital markets, PAA will maintain solid liquidity and remain well within each of our targeted credit metrics post closing the transaction. The pro forma data we are showing is based on a gross purchase price of the $1.67 billion. Since the effective date of the acquisition is October 1, 2011, we expect our actual net funding obligation at closing will be reduced to the extent of interim cash flow generated by the business, including the liquidation of any of the 10 million barrels of inventory and line fill included in the purchase price, of which approximately 5 million barrels is seasonal inventory. Our committed liquidity as reflected on this slide includes the benefit of the $1.2 billion liquidity facility that closed in December. As we mentioned in our acquisition conference call, and in keeping with our financial growth strategy to maintain a strong capitalization and solid liquidity, we will look to access the debt capital markets to raise longer term capital.

With respect to equity financing as a result of our prefunding activity and our high retention of cash flow in excess of distributions, we have substantially fulfilled our equity requirements with respect to closing the BP acquisition. Additionally, our equity requirements with respect to our 2012 expansion capital program are quite manageable. This conclusion is reinforced by the pro forma information I just discussed. That said, consistent with our financial strategies and past practice, we intend to continue to prefund a prudent amount of our organic and acquisition related capital expenditures.

To that end we plan to file a continuous offering -- operating program that will allow us to raise additional equity capital while minimizing disruption to the market. We believe this continuous equity offering program that will allow us to raise additional equity capital, while minimizing disruption to the market. We believe this continuous equity offering program will allow us to keep pace with equity needs associated with our ongoing expansion capital programs. As we have in the past we will also monitor our internal activities and opportunities to prefund our growth to capitalize on favorable market conditions, and prepare for continued growth. I would also mention that we expect a sizeable component of our ongoing capital needs will be met through generating cash flow in excess of distributions.

As shown on slide 26, over the past seven years we have retained over $950 million of cash flow in excess of distributions. Notably, with approximately 145% coverage of our 2011 distributions, we generated and retained approximately $365 million of excess cash flow during the year. As I will discuss in more detail in a couple of slides, we expect to be able to retain a meaningful amount of excess DCF in 2012. I will now provide an overview of our guidance for the first quarter and full year 2012 the highlights of which are summarized on slide 27. For more detailed information please refer to the 8-K that we furnished last night.

We are forecasting adjusted EBITDA for the first quarter of 2012 to range from $380 million to $420 million, with adjusted net income ranging from $235 million to $283 million, or $1.08 to $1.38 per diluted unit. We are forecasting adjusted EBITDA for the full year of 2012 to range from $1.575 billion to $1.725 billion, with adjusted net income ranging from $887 million to $1.069 billion, or $3.79 to $4.91 per diluted unit.

As Harry mentioned during his section of the call, our guidance incorporated the four bolt-on acquisitions that we closed in late 2011, and includes the projected benefit from the BP acquisition for the last three quarters of the year. I would note that because of the seasonal effects we typically see stronger results in our supply and logistics segment in the first and fourth quarters, with slightly lower results in the second and third quarters. For illustration purposes a representative quarterly profile for our 2012 guidance is included in the inset in the upper right of slide 27.

As represented on slide 28, based on the midpoint of our 2012 guidance for DCF and LP distributions, our distribution coverage is forecast to be approximately 118%, and we would retain approximately $170 million of excess DCF or equity capital. I would note that the effective date of the BP transaction is October 1, 2001, but the closing date has not yet been definitely set. As a result, although closing beyond April 1 would impact the period of time in which these assets contribute to our reported results, PAA will still receive the net economic benefit of the results generated by the BP entity subsequent to the October 1, 2011 effective date by means of a lower ultimate purchase price for the transaction.

With that, I will turn the call over to Greg.

Thanks, Al. PAA delivered record performance for the fourth quarter and full year of 2011, and meaningfully exceeded our public guidance ranges, extending our track record of delivering results in line with guidance to 40 consecutive quarters, or a total of 10 years. These results are a testament to the strength of PAA's business model and strategic asset base and the outstanding execution of PAA's employees during a period of strong fundamentals and favorable market conditions. As this type of performance would imply, PAA met or exceeded all of its 2011 goals. A report card comparing these goals with the performance metrics is provided on slide 29.

In summary we delivered operating and financial results above the midpoint of guidance in all four quarters, delivering a total adjusted EBITDA that was $373 million above beginning of the year guidance. We executed a $530 million capital program on time and within budget, and set the stage to invest $850 million or more in 2012. We completed $1.3 billion of acquisitions during 2011, and entered into a definitive agreement to acquire BP's Canadian-based NGL base for $1.67 billion. We delivered year-over-year distribution growth of 4.7%, while generating distribution coverage of approximately 145%, and retaining approximately $365 million of cash in excess of distributions. Quite a year.

As we look forward we believe industry fundamentals are favorable for PAA's business model and asset base. As represented on slide 30, attractive crude oil and liquids prices, advances in drilling and completion techniques, and application of these techniques to various shale and resource plays, have driven an increase in domestic production in multiple regions. In particular, nearly 50% of the US rig count is directed towards drilling in three areas, the west Texas and New Mexico area, the Rockies, and Eagle Ford in south Texas.

As illustrated on slide 31, PAA has a significant asset presence in all three of these areas, as well as a significant asset presence in a number of other areas that are showing signs of increased activity. As a result, we are enjoying a strong demand for our assets and services, which not only increases the utilization of our existing assets, but also provides multiple opportunities to expand and extend our existing asset base on attractive economic terms. These fundamentally sound conditions provide the underpinning for $850 million expansion of capital program in 2012 which we believe could be expanded throughout the year. During 2011 the solid industry fundamentals were also augmented by favorable market conditions that we were able to capitalize on in our supply and logistics segment. The 2012 guidance that we have provided incorporates these favorable market fundamentals, but does not assume that the market conditions will be as favorable in 2012 as they were in 2011.

Accordingly, if market conditions similar to those experienced during 2011 continue throughout 2012, there is upward bias to our guidance. As a result, we believe PAA is well-positioned to continue to deliver attractive results as we realize the contributions from the $1.9 billion of capital we invested in 2011, and over $2.5 billion that we plan to invest in 2012 through our $850 million expansion capital program and our pending $1.7 billion acquisition of BP's Canadian NGL business.

Importantly, PAA is well-positioned to finance this growth, while maintaining a solid capital structure and a high level of liquidity. As a result of our proactive financing activities and cash generated in excess of distributions, PAA ended the year with a strong balance sheet, $3.6 billion of committed liquidity, and favorably positioned with respect to our targeted credit profile.

With this in mind let me now review our 2012 goals which are highlighted on slide 32 and as are follows. First, deliver operating financial performance in line with guidance. Second, close and integrate the BP Canadian NGL acquisition, and selectively pursue strategic and accretive acquisitions. Third, increase our November 2012 annualized distribution level by approximately 8% to 9% over the November 2011 distribution level, and fourth, successfully execute our 2012 capital program and set the stage for continued growth in 2013 and beyond. We have a solid and experienced management team. A very strong and supportive Board of Directors and general partner, that not only help us achieve our objectives but keep us mindful of the need to not become complacent, and to remain vigilant and prepare for potential negative developments.

Prior to opening the call for questions, I want to mention that we will be holding a joint PAA and PNG 2012 Analyst Meeting on May 30 in Houston, followed by a tour of our PAA Midland-based assets. If you have not received an invitation but would like to attend, please contact our Investor Relation team at 713-646-4489. I also want to reiterate the position we have taken in prior calls we are unable to answer questions regarding PAA's proposal to purchase all of the outstanding shares of [SemGroup] Corporation. Your cooperation and restraint in this regard will be much appreciated. In closing, thank you for participating in today's call, and for your investment in PAA and PNG. We look forward to updating you on the activities during our first quarter results call in May.

At this time, operator, we are ready to open the call up for questions.

Thank you. (Operator Instructions). The first question from the line of Brian Zarahn with Barclays Capital.

Good morning.

Good morning, Brian.

On your 2012 guidance for lease gathering volumes. You have about a 108,000 barrel per day increase. Can you talk about what regions you are seeing that growth? Is it mostly the Eagle Ford?

Eagle Ford Permian Basin, primarily. Western Oklahoma a little bit.

Okay. Is the biggest driver the Eagle Ford that you are assuming?

Pretty well spread out.

The Permian Basin is a good chunk of it, too. Between the Eagle Ford and the Permian Basin, those are the two larger areas.

Okay. And then the new you Mississippian line project. Can you talk a little bit about the costs you are assuming behind that, and is any of that capacity under contract?

There is not any contracted capacity on the line. It is supported an area of dedication with SandRidge. We will actually be the first purchasers of that crude and ship the crude on the line ourselves. We haven't disclosed the expected cost yet, Brian. We are still working on finalizing the laterals, but we have $60 million including our capital program for 2012 on that line.

And are you planning to run this as a proprietary pipeline?

No, it will be a common carrier line.

Common carrier, okay. Turning to distributions at PNG. If market conditions continue, what is your general view of potential increases in 2013? Is there a potential for any modest increase, or would you anticipate being more conservative?

I think as Dean summarized in his comments, Brian, we feel very strongly about where we are positioned certainly on a relative basis, but also an absolute. We are showing at the midpoint of our guidance that we would show a 105% coverage. That basically means that we are basically around $5.5 million of excess coverage, and I think at the high point of our guidance we are right at 110%. So double that and then on the low end, though, we would be right at about 1 to 1.

I think we are going to be cautious, I know we are going to be cautious as we move forward, because again, this is market that has been while we called it early that it would get difficult, I assure you we didn't forecast it to be as difficult as it actually has been, and there are still a lot of unknowns out there. Clearly we could potentially get a benefit if production continues to increase and storage capacity doesn't expand as Dean said, we will probably test the limits of capacity and that creates opportunities. But unfortunately it creates opportunities in a low price environment. What we really need is basically a demand increase ultimately to take some of that excess gas off the market, and you will probably see some discipline. If you decrease gas drilling, and you increase oil drilling with associated gas it is not as dynamic as you might expect.

In closing I would guess I would just say, we tried to remove the structural impediment as Al went through the math, it would have taken almost $5 million to raise it a penny, now it only takes less than $1 million to raise it a penny. So we certainly positioned PNG to be able to have distribution growth. The numbers that we are forecasting would suggest that if we deliver and it is sustainable in the market environment that we see, that we have that capacity we are just not providing any guidance because quite candidly this is a market that is tough to call.

I would hate to turn around and do something that sounds wonderful for everybody, we raised the distribution the first or second quarter and then market conditions deteriorate worse, and your next question on the next phone call is why are you doing below 1 to 1. I think where we are positioned right now is I think everybody should feel very good about our current distribution. They should feel good about the potential for increases, either as the market conditions improve or we generate sustainable results, but I wouldn't want to guide you to a number and then be explaining to you at the end of the year why in the prudent judgment that we used, and that you would probably agree with that we didn't hit a target.

Fair enough. Final one from me, turning to PAA,given your expanding asset base and then the favorable backdrop with the rising crude production, do you think farther out sort of mid-single digits or high-single digits is something that is a reasonable assumption for distribution growth?

We feel real good about where we are at. As you look at the numbers and sustainability of it, again we are going to get the benefit in 2012 and 2013 of the capital we have already spent in 2010 and 2011, and then we have got a lot of capital that we are spending in 2012 that should benefit 2013 and 2014. So what we said last time is we are giving very specific guidance for 2012. We are saying we will grow at 8% to 9%, and still maintain a very high coverage ratio. And what we have said is that you can abandon the 3% to 5% long-term guidance that we have given, but we haven't provided any specific guidance other than to say that you should safely assume it is above 5%.

I think capital market conditions, and clearly we have seen a market that can change rather dynamically. We went from a $27 rent WTI differential to $11 in about, I think it was about 14 days, and so what I would say is we have plenty of cushion going out to sustainably increase the distribution at very attractive levels above 5%, and as we continue to get our projects executed timely, and get more visibility into how much momentum is really in this market we will provide additional guidance as we go through. I will say this,I think we are at least as competitive as the other large caps, if not more so both in terms of coverage and distribution growth potential.

Thanks, Greg.

Thank you. The next question comes from the line of Darren Horowitz with Raymond James.

Congratulations on 2011 results.

Thanks, Darren. I assure you it was a team effort.

I know it was. I have a couple of questions for you on the Bakken. Looking at depressed Bakken crude prices right now, how much of an opportunity does that present for you guys?

We have a rail facility at Ross and we have an unloading facility at St. James, so obviously we try and rail as much crude out of the area as we can. I think the differentials are very favorable for our Bakken North project, which will ultimately be able to bring that crude back in the Patoka area at much lower costs than a rail alternative. So it is definitely a positive for us.

Harry, does it ever make sense to move crude south, possibly down to Fort Laramie, and then even further south? Or when you think about it, it is move to get it to Patoka and the access the northeast market?I guess it would seem to me that as pad to utilization rises, refiners are seemingly forced to bid up Bakken barrels, so that it where you want to be, but I would just love your perspective on that?

Look at all of the growth in Oklahoma and west Texas, we think that Bakken crude is going to have a higher value in Potoka than coming back down into Cushing, if that makes sense.

So in the spirit of being a bit more vertically integrated, looking at your assets kind of being between a competitor's two pipelines, how are you guys thinking about getting long haul transport into that Potoka area, and leveraging your storage footprint and greater optionality to really give producers more market options longer term?

Our Bakken North connects into our Wascana pipeline, which is being reversed, and that connects into Enbridge at Regina. So as part of that project, we have got some modifications with Enbridge. That location at Regina as we come off Enbridge, so now we are going back in. We will go through Enbridge over to Potoka. Is that your question, Darren?

It would just seem to me that longer term you probably wouldn't want to continue doing that.

Darren, I think it is, we are trying to get in a perfect world, five to six years out when we are making our decisions as to not only what is going to take advantage of an opportunity maybe over the next 12 months, but what is going be a sustainable opportunity for a number of years. I think the fact that we took a larger presence on the East Coast with the Yorktown facility, the fact that we have expanded our rail facilities, does probably address directionally your question of do we believe that there are new markets that need to be developed for that crude. When you compound that with, and you have got to look at multiple regions at a time, because it is pretty dynamic. There is a pipeline reversal.

Seaway obviously is going to take some crude out of Cushing and take it into the Houston market, just about the same time that a fairly big amount of crude is going to come out of the Eagle Ford into that area, and all of that crude, or substantially all of it at least that has been talked about certainly out of the Eagle Ford and out of the Bakken, is very light crude, so that limits your ability quite candidly to back out some of the foreign imports. I think there is Harry, 5.3 million barrels of foreign imports into the Gulf of Mexico, but if you total up the light crude, light sweet crude, the condensate, and even the medium sweet, that are candidates to be backed out, Darren, it is only 1 million barrels a day of that 5.3.

Unless you cancel long-term contracts for heavy sour and heavy sweet crude, or you change the refinery configuration, you could end up with too much light sweet crude in the Gulf of Mexico, and quite candidly since you can't export crude out of the United States, it is illegal, you may end up having to move that around to the East Coast on barge, and that sets a different bar if you will, that you need to cover to then make rail competitive going in the back door. I think when you look at our assets you will see we are very aware of the dynamics you are talking about near term, but I think we are also well positioned to take advantage of it long-term as some of these things settle out.

I appreciate the color. Thanks.

Just to expand a little bit on what Greg said about rail. We will have rail unloading at Yorktown. We will also have a rail unloading facility that connects into our California infrastructure, so I think we will have a lot of flexibility with the types of crude that we gather, and we will have access to rail.

I appreciate it, guys.

Thanks, Darren.

The next question comes from the line of Steve Maresca with Morgan Stanley.

Good morning everybody.

Good morning, Steve.

Can you hear me okay?

We can, indeed.

The first question is on the Mississippian Lime. It will be a common carrier line, but initially you don't have commitments right now. What is the plan going forward to get those, timing, and are you guys still moving forward with or without chippers on that I guess?

Well, keep in mind we already have a lot of assets in Oklahoma, and trucks, and everything else. So we are going to be able to basically move certain of the crude we already touch over to our pipeline. We just reversed the Medford pipeline, not reversed it, converted it, and we will have 25,000 barrels a day of capacity there. I think we are full right now you is what we currently have. Because we actually take some of the crude oil from the wellhead, Darren, to the best markets we can put it on the pipeline.

The other thing is I think it is a fair statement that while SandRidge does not have a volumetric commitment, they are committed to the pipeline with their acreage, and they are one of the largest acreage holders up there, and they are drilling like crazy. The volume may vary depending upon the success of those results, but when we run our economics and recall that we used to be in the E&P business, so we kind of understand minimum rates of return and quote breakeven economics are, but we are pretty comfortable if oil stays in the $75 to $100 a barrel range, we will have no problem putting our crude oil on that pipeline. You should know we are committed to building the pipeline, and we are not too worried about the volumes.

And just to expand a little bit on what Greg said with our existing pipes. Our existing pipes in Oklahoma and Kansas are full. We can't take crude today that is available for transportation. This will help debottleneck some of our existing pipes as well.

Okay.

And the advantage that we have with the Medford pipeline is that we are going to, there are other competing projects out there certainly that we have heard of. We can be faster to market for a number of reasons. One, because we have about two-thirds of the right-of-way already would be parallel to our existing line, and then when it gets to Cushing, I will represent to you there is nobody better positioned to handle multiple grades and varieties of crude already there. So as a practical matter, we think we are the transporter of choice. If somebody chooses to go a different way, they have got a different crystal ball than we have.

Thanks. So following up there, what does this mean for Cushing?Obviously you have a line that is in the process of getting reversed to bring things down to the Gulf. What does this mean for Cushing market, whether it is respect to more takeaway potential needed and opportunities or I guess more storage needed?

Storage is a tough call right now. I think there is plenty up there, either construction or under construction. But clearly between the joint venture between enterprise and Enbridge, and the reversal of Seaway they will be able to take a lot of pressure off of Cushing, and I think Cushing becomes again the preferred market, and it is a conduit for different types of crude to go in different directions. There is so much flexibility once you get it to Cushing. I think it will be kind of a breakthrough once we get the Seaway reversed.

It will, there are so many dynamics at work here. You have got pipelines in the Permian Basin that are expanding capacity to the Gulf Coast directly. Greg mentioned we have got Seaway that will provide access to the Gulf Coast. So I certainly don't think there is any more tankage needed at Cushing, due to this pipeline project or the growth in the Mid-Continent. I think most of the pipeline alternatives are in the process of being developed.

I think you will see some additional tankage being built, and some of it already is in the Gulf area, the coastal area. And I think the issue may not be a volume issue when you talk about some of these bottlenecks, it may be a quality issue.

Okay. Do you worry at all about rates becoming pressured at Cushing?

We always worry about everything.

Okay.

Yes, I think there has been a significant number of tanks that were built in Cushing in some cases not necessarily driven by anticipated weight or volumes, but simply Contango possibilities. Some of those leases will come back to market in the next four or five years, and depending upon what the market is when those leases all come up for renewal, it could put pressure on the market.

I do think we take great comfort and I use the word great comfort in the fact that our assets are operationally the best positioned in Cushing, and we are not a Contango play facility. We are a facility that you can do anything you want to including Contango play, and I think that the true users that we like to have as customers understand that. I think we will always have an advantage. If too much tankage is up there will it put pressure on rates,absolutely. Will it hurt us as bad as somebody else? Not a chance.

Okay. Final question. Greg, you talked about 2012 guidance incorporating favorable market fundamentals not as favorable as 2011. How do we think about that in terms of quantifying what that means in terms of what you are thinking? Is it just a margin per barrel. Something you are thinking about from a WTI Brent discount? What is favorable, but not as favorable, if you can quantify? That is it from me.

As you might expect, we don't do this extemporaneously. So I was reading a little bit from my script, and I even screwed that up. There are really two issues. One the favorable market fundamentals and we are talking about the volume that is pushed, driven, supply driven markets, we think that is going to be as favorable or more favorable in 2012 than it was in 2011. That is what I call the fundamentals part of it.

The second part of that issue was in 2011 we had very favorable market conditions, which was a combination of in certain areas, very attractive basis differentials, and early in the year very attractive Contango market opportunities, and those are things that can become very transient. We talked about the WTI Brent differential being $27 at the end of October. They took Ghadaffi out, and then Seaway was announced, and in a very short period of time we went from 27 down to 11. Today we are back to around 18. I don't know how to predict those. We can't put that into our model, and say this forecast it is going to stay 11 or going to stay 18 or going to stay 27. But if itshows a lot of volatility and it shows that range going from 11 to 18, or 11 to 27, we will make more money in 2012 than we are forecasting, but we don't forecast those types of what I call favorable market conditions. We are forecasting and believe in the favorable fundamentals are going to continue throughout 2012, 2013 and 2014. I think I mangled my own script when I tried to describe those two differing conditions.

Got it. Thanks a lot again for the color.

Thank you. The next question from the line of John Edwards with Morgan Keegan.

Good morning, everybody.

Hi, John.

Just following up on Steve's question regarding the margins here going forward. I mean we were wondering, you guided in November $1.91, and then reported $2.43 on the margin. And to your point we were looking at the spreads how they went down quite a bit each month. Now was that volatility, was that what was enabling you to achieve that margin, because we were thinking with the spreads going down, it actually might come in a little bit less but in fact you beat it by quite a bit?Just a little more detail on that would be helpful.

Keep in mind we benefit from volatility when it goes really either direction. We have to allocate our assets right, and again we have got some of the best guys that do that. There are a lot of things that happen in our business model. We talked about the counter cyclically balancing, and things like that in our supply and logistics. I think as Harry mentioned we had very favorable iso butane margins that showed up, and again many times we, what happens in the current month is not as important to the current quarter, as it is probably to the next quarter.

So a lot of that we are going from I think fourth quarter EBITDA was $471 million. We are guiding to a midpoint of $400 million. So I think what you expected to see happen is happening but it is happening out in the January to February/March market, because we are basically transacting multiple months ahead of time. We had probably already locked in the margins in the months that you were expecting to see impacted but there wasn't enough depth of market to take it all of the way through the first quarter.

Okay. And as far as capital spend going forward, you raised it from the last guidance by around $100 million to $150 million. And how much is that, how much of that is BP and how much of that is other things?

Well, I think I can be pretty specific here. Probably less than $50 million of it is, BP and the rest of it is just other projects that have basically come to fruition since that point in time, where clearly we didn't have when we had the call in November we didn't have the Mississippi Lime line to appoint. We just signed that last week, Harry?

Yes.

Over the weekend. And so John, some of it is just simply things is this is back to the portfolio of projects we were talking about when we said look, some are them are going to make it, and some are going to not, but we try to make our best guess as to what we will pull out. We have been lucky to ring the bell on a few, so we just increased basically our budget to be able to accommodate that which we were able to land on the bank.

And we advanced a number of projects in the Permian Basin as well, too.

Okay. And then is that given how it looks like a lot of opportunities are opening up, and I guess to Darren's question, a lot of things up in the Bakken. It would 800 to 900 or so, is that a reasonable run rate here for the next few years do you think?

I don't think we are ready to go much beyond the next year. I think several years ago we made the comment we thought we were very comfortably in the 400 to 600 range, and probably migrated more up to the 500 to 700 range. Probably 600 is a comfortable number. And certainly some of these projects that we are announcing right now are simply going to carry over into 2013. For the next couple of years there is probably a bias of us being upwards of 700-plus. How long these industry fundamentals and what competition does, causes you to get a little bit fuzzier when you get beyond the next couple of years.

Okay. Great. And then Dean was talking about the gas storage limits being tested, and I was just wondering if you could give a little more discussion on really what are the implications if those gas storage limits are tested? I guess what does it mean physically and financially it can go different ways?So maybe if you could talk about that.

Probably heard too much of my voice already so I am going to turn it over to Dean.

What could happen if you get to late summer. I think ultimately storage sales you see the pipelines back up, and should ultimately if the pipelines fill up, you are going to shut in production, and you are going to start, you are going to see the price effects of that financially. You read the same articles out there we do. If you get that train wreck that happens you could see for a time gas fall below the levels that it is right now. So I think physically that is what happens. You are going to see pipelines fill up ultimately because storage is already full, and there is just no place for the gas to go. And you are going to see those wells get shut in, and then financially you are going to see the impact of that in the absolute price of the commodity.

I was actually thinking gas storage rates. How does that impact gas storage rates?

I think on gas storage, I think what you need still as Greg discussed a little bit, is you need demand growth long-term. We haven't been in that environment yet. I think short-term opportunities will prevail, but you just have to see how they manifest themselves in long-term rates, that is really what we look for. And although short-term opportunities are nice, until they embed themselves into the longer term rates and the longer term view, I think it takes demand growth to overcome that prolific supply to get there. We will just have to wait and see. But that is what it is going to take. I don't think that is going to have an impact at least long-term on rates until you see some demand growth.

So upward pressure on short-term rates, but really no impact on long-term rates?

Yes, there will be some Iron impact on long-term rates because the marginal rate will be set by the marketing companies that are trying to trade that volatility, and so if you go back, John, to probably in recent memory and recent is going to be a long time, if you go back to the late 1980s/early 1990s, when we had what ultimately became to be referred to called the gas sausage, call it a bubble but ultimately it became a sausage, you could see gas prices in the $2.00 to $2.50 range in the winter months, but you actually saw a dollar spread between the summer to winter even at low prices.

Clearly that is going to, if you return to that, you could end up with some pressure on term storage rates. What probably happens is the same thing that happened back then too, is when somebody brought gas on in the cash market, that they didn't have a place to sell it to, they had to take big discounts. If there is enough of that then you will influence people's belief as to what the extrinsic value they might be able to pay. Then depending on what the storage is in the markets, they might push rates up on the margin trying to capture some of those opportunities. Again, you are not going to get the same type of market that we saw in 2005, 2006, 2007. $0.20 rates for soft storage was $2.40 a year, as a percentage of a $13.00 gas price, that is 20%. As a percentage of today's gas price that is 100%. You shouldn't be expecting it to go back to that level.

Okay. Great. Thank you very much.

Thank you. The next question comes from the line of Michael Blum with Wells Fargo.

Thanks, good morning. Question on PNG. So on slide 21 where you show the contracted and uncontracted capacity, should we assume that as you roll forward in time, you will contract that uncontracted capacity, so if we rolled the slide forward a year from now you would still be at 90% for the first year, 70% and 50%, or something like that? Or are you thinking you might keep that uncontracted capacity for your own account effectively, and just use that for merchant functions?

Yes, Michael, when you look at as you go forward you would tend to see because of the laddering effect of our contracts a shift in that. So, in other words, in 2013 as we go to sell our storage we would hope to move closer to that 90% as we get to 2013, and then 2014 that 50% number move up to 70%. We are comfortable holding a little bit of merchant depending on the market. I mean I would call it in the 10% to 15% range, but we fully expect as our contracts roll off, that we could kind of have that balance in there. Is what you see.

Michael, if you went back and looked at the same slide last year , I think it showed almost 100% leased for 2011, 80% leased for 2012, and 50% for 2013. In a period where we are still growing volumes, and you look at it today, and now it looks about the same as it did before, actually a little bit better in certain areas. So I think what you are going to see is us continuing to exercise the discipline of taking what the market offers. We have got attractive facilities. People want to contract with us. They might do it at a lesser price than we would like to see long-term, but we going to protect our distribution and protect the potential growth of it.

As Dean said in the 10% to 15% that we manage, we are pretty comfortable with that. If we actually ever get to the position we can call the turn in the market, 15% may grow to 20% but we are not going to get silly and take a huge amount on it. We are an MLP. We are not going to get paid to hit home runs in one year and strike out the next. We will get paid to hit singles and doubles and triples game after game after game.

Great. My second question, just staying on PNG. Just from an M&A perspective as the tough market conditions persist, are you seeing any change in terms of M&A opportunities, where weaker players in the market or private equity backed are more willing to transact, and do you see in the shift in the multiples that may be paid, and I am really asking do you think multiples could come down from where they have been for the last two to three years?

I think for transactions to occur they have to come down. I think it is too early really to say whether people are getting realistic about this new environment, and to some extent depending upon how much flexibility that they have in their capital structure, that will determine how quick they come to reality. I think it takes a while. It usually takes as I shared a quote with somebody the other day, it takes longer for a crisis to crisis to occur that is inevitable, and then when it does happen it happens much faster than you would have thought it could. I think it is coming. It is just not here yet.

Okay.

At PNG what we tried to do at PNG and as a sponsor of PAA is positioned where PNG is the logical consolidator at that level.

Great. Thank you very much.

Thank you. The next question comes from the line of Elvira Scotto with RBC Capital Markets.

Hello?

Hi, can you hear me?

I can.

Okay. Great. My question most of my questions have been answered so I want to ask on the Bakken area gas processing plant is that included in the 2012 CapEx guidance?

No.

That is not included. And then just bigger picture with gas processing, I guess a couple of questions I guess going back to that one project. What is the plan for the liquids? Where would the liquids ultimately go?

We have a rail facility at Ross. That is one of the reasons why we like the location. And we like the location because there is rich gas there as well. Propane and butane will go out on rail. Ethane has a couple of alternatives. One would be connecting to the Vantage pipeline system that would move into Alberta. There is also some of the BP infrastructure that actually could be tied into this facility longer term as well.

Okay, great. And then just I guess bigger picture gas processing, how do you see this business evolving over time? How are you thinking about expanding it longer term?

Well, I think we first entered the business in probably 2005 when we first got into the really iso butane with the processing and fractionation business. We expanded in 2009 with the acquisition of [CDMX], and we said then that we were pursuing a different business model than the typical percentage of proceeds, or keep hold arrangements, and we have been successful Elvira at being able to do that. We have built several smaller plants. These are some bigger plants that we are talking about.

We built one last year at 135 million plant in [Facile]. So I think you would see us continuing to especially in area where we have got a footprint, where there are liquids rich area, you are expecting to see PAA there for both crude oil and the liquids part of it. It is really an adjunct to what we are currently doing, and then I think it has the opportunity from time to time because of the expertise we have in house to be able to step out a little bit, and let maybe it lead us into an area whereas opposed to it just following us into an area through PAA. So whether it ever becomes so big that is its own kind of segment so to speak. Part of that is just a function of how big PAA intends to grow, and we intend to grow quite a bit on the crude oil side, too. They will have trouble catching up to be huge, but again it is very complementary to what we currently do.

Great. Thank you.

Thank you. We will next move to the line of Andrew Fairbanks with Saugatuck Energy.

First on the Mississippian Lime Pipeline, recognizing all you have said about limits around what you could really say I was just hoping you could characterize the ramp-up in volumes there. Do you expect to get to full capacity in three years, five years? Is there any sense you can give us on that? And is there some degree of trucking volumes you can move on to the line immediately?

Well, let me start with our Medford line. That came online 10,000 barrels today. It is full, it will be 25,000 barrels a day by July. That will be full. So there is quite a bit of truck volumes that can be directed to that pipeline once it is in service. The line is probably when you look at the cost versus various sized pipes, it is probably a little on the larger side if you looked at what the current volume, got a lot of expectation that there is going to be quite a bit of drilling, so we tried to position the line very low option value by upsizing the line a little bit to capture the potential growth in the Mississippi. We are not saying there today there are 170,000 barrels that can go on to it, but there is definitely enough to make the line viable.

And I would point out, too, by having two lines there, one of which is obviously larger and has more capacity than the other one we retain a lot of optionality. If later on it turns out that we don't need both lines we can reconvert the Medford line back into a natural gas liquid line, and put the volume that is on it on over to the consolidate it onto one line. So again, we have a lot of flexibility in that particular area.

That is great. That makes sense. My other question was just around the Bakken and the Ross terminal. Doing any crude by rail shipments out of there currently, and when we do get to the end of the year, are you still thinking about that facility as one unit train a day, 65 to 70 Mbd takeout capacity?

Just started loading manifest trains out there. We will have unit train capability by the end of the year but that is in line our thoughts on the unit train volume.

We already rail out of different areas in the Bakken so this is just adding another takeout point.

Right. Right. And have you seen an uptick in demand from producers given the volatility we are seeing in upper Mid-Con crude pricing lately?

We are seeing continual increases of crude coming into our receipt facilities. Those volumes are escalating every month.

That is great.

We are in the process of expanding our Saint James facility. Right now at 65,000 barrels a day.

I think we are taking in 80,000 or 85,000 barrels a day at Saint Jim's right now. Not all for our account. That is what it coming in to the terminal.

And we will be able to go up to 120. So we are expanding our receipt capability on the other end, which should give you a strong signal that we are not worried too much about volume availability on our rail facilities.

That is great. Then the offload terminals in California and Yorktown you mentioned, what size are you thinking for those? Would they be kind of typical refinery 20,000 or 30,000 barrel a day type sites?

Yorktown will probably be closer to a 60,000 barrel a day site. It will have the capacity to do that. I am not saying that we will unload that much immediately. But Yorktown should be in that range. The one in California will probably be a little smaller than that.

Great. Thank you.

Thank you.

Thank you. We will move to the line of Selman Akyol with Stifel Nicolaus.

Thank you. Good morning.

Hi, Selman.

In terms of PNG and in terms of rates just sort of industry-wide, can you guys put brackets in terms of percentages of what you are seeing and how you things are repricing out there? We know it is down, I am just trying to get what is it looking like?

Well, no, not really.

Okay, fair enough.

There are some system, I mean commercial issues at hand there but I will say we have the best facilities that always command a premium rate, and that is not only for you but the customers that are online as well.

Alright. Then, in light of the weak environment can you guys discuss have your expansion plans changed at all, in terms of adding additional capacity as you look beyond what you have got set for 2012?

In this market environment we continue to bring on our low cost expansion. We have no plans right now to drill new wells, but we continue through smugging and our fill to water to bring on those low costs as we have mentioned in previous calls, that is about in the $3 million to $4 million all-in per Bcf, and even in this environment those are good decisions to make. I will say if the market does turn we certainly are prepared, and can bring a new cavern on in the 14 to 18-month time frame, so we are well prepared in either direction if the market does change, but our plan for the next few years is through smugging and fill the water, the low cost capacity increases through that method.

Okay. Thanks. Greg, in your closing comments you gave a nod to your Board and specifically one of the values that they added was being on the outlook I guess for potential negative developments. Could you expand on that and maybe a little color on what they are focusing on?

I think it is just a fair statement they have been through a lot of cycles as have we, and it is always nice to make sure that we realize the difference between brains and a bull market. I think we have got a Board that is very engaged, understands the business, and can serve as a reminder from time to time that says guys, it is not going to be up and to the right forever. It caused us to basically think in some cases how can we make an offensive move, but have a defensive fallback. I just think we have got a great Board, and a very supportive general partner that takes a long-term view that lets us do that. I don't think that is prevalent throughout the MLP space. I think sometimes it is driven by agendas that are different, and they are sometimes a little bit more focused in on what will the market offer up over the next 12 to 18 months, not what should we be doing for the next five to ten years, and I think that makes us and a few others of the large cap MLPs different. We are here to build a business and we have chosen to build that business in an MLP structure, as opposed to I think in some cases we compete from time to time against people whose business is to be an MLP, and they are trying to figure out what they can stuff in it.

Alright. Thank you very much.

Thank you. Seeing no additional questions at this time.

Thanks, everybody, for participating in the call, and for your very insightful questions, and we look forward to updating you on the next call.

Thank you. Ladies and gentlemen, that does conclude our conference for today. Thank you for your participation and using AT&T Executive Teleconference. You may now disconnect.