Plains All American Pipeline LP (PAA) 2010 Q4 法說會逐字稿

Ladies and Gentlemen, thank you for standing by, and welcome to the Plains All American Pipeline and PAA Natural Gas fourth-quarter earnings call. (Operator Instructions) Also, I would to welcome you to the Plains All American Pipeline and PAA Natural Gas Storage fourth-quarter and year-end 2010 results conference call. During today's call, in addition to reviewing the results of the prior period, the participants will provide forward-looking comments on the Partnership's outlook for future, which may include words such as believes, estimates, expects, anticipates, or other words that indicate a forward view.

The Partnership intends to avail themselves of the Safe Harbor precepts that encourage companies to provide this type of information and directs you to the risks and warnings set forth in Plains All American Pipeline and PAA Natural Gas Storage most recently filed prospectus, 10-K, 10-Q, 8-K, as applicable, and other current and future filings with the Securities and Exchange Commission. Throughout the call, participants may reference the Companies by their respective New York Stock Exchange Ticker Symbol PAA for Plains All American Pipeline and PNG for PAA Natural Gas Storage. In addition, the Partnership encourage you to visit their website at www.paalp.com and www.pnglp.com.

And, in particular, the sections entitled non-GAAP reconciliations, which present certain commonly used non-GAAP financial measures, such as EBIT and EBITDA, which may be used here in the prepared remarks or in a Q&A session. This section of the website also reconciles the non-GAAP financial measures to the most directly comparable Partnership's reported financial information. Any reference during today's call such as to EBITDA, adjusted net income, and the like is a reference to the financial measures excluding the effects of select items impacting comparability. Also, for PAA, all references to net income are references to net income attributable to Plains.

Today's conference 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 and Vice Chairman of PNG; Dean Liollio, President of PNG; and Al Swanson, CFO at PAA and PNG. I will now turn the conference over to your host, Greg Armstrong. Please go ahead.

Thank you, Carolyn. Good morning and welcome to everyone. In addition to Harry, Dean, and Al, we also have several other members of our management team available for the question and answer session, including Roy Lamoreaux, Director of Investor Relations.

This is the first full year that we will have both PAA and PNG as public entities. I wanted to take the opportunity to let you know that Dan Bach will be joining our Investor Relations effort as Manager of Investor Relations, reporting to Roy. Dan has been with PAA since 2004 and he's very familiar with each of our segments and the drivers behind PAA's and PNG's results as his primary role has been planning and forecasting. As a reminder, the slide presentation we will be referring to in this call is available on our websites at www.paalp.com and www.pnglp.com.

We have a lot of information to cover today with respect to PAA's fourth-quarter results, our overall performance for the full year of 2010, and our guidance for the full year and first quarter of 2011. We will also cover similar information for PAA Natural Gas Storage, or PNG as we will refer to it, which is a majority-owned and controlled subsidiary of PAA. On balance, I think you will find the information for both entities very much on the positive side, both with respect to fourth-quarter performance and 2011 outlook.

Plains All American closed out 2010 with very strong performance, exceeding the high end of PAA's fourth quarter adjusted EBITDA guidance by $22 million, or $35 million above the midpoint of the guidance range. Combined with the solid performance delivered in the first nine months of the year, PAA's full-year performance also exceeded the high end of the guidance we provided on February 10th 2010, by approximately $41 million, and that's about $66 million above the high end of the guidance range. Our 2010 acquisitions were weighted towards the end of the year, and thus contributed less than $5 million to this over performance. So overall, it was a very solid -- year of blocking and tackling.

As shown on slide three, the fourth quarter of 2010, PAA reported EBITDA of $277 million and net income of $142 million, or $0.67 per diluted unit. Excluding the selected items impacting comparability which are included in the table at the bottom of the slide, our adjusted EBITDA for the fourth quarter of 2010 was $322 million and adjusted net income was $187 million or $0.99 per diluted unit. In comparison to the same metrics of last year, those metrics are up 17%, 26%, and 24% respectively.

PAA's fourth-quarter results were driven by in-line performance in the Transportation Segment and over performance in the Facilities and the Supply and Logistics Segments. Slide four graphically represents this quarter's aggregate performance versus guidance, highlighting the fact that we have now delivered 36 consecutive quarters where results were in line with guidance throughout a variety of energy market conditions. Keeping pace with the parent, PAA Natural Gas Storage also reported fourth-quarter performance that was at the high end of its guidance range. And Dean will cover those results later in the call.

As shown on slide five, for the full year of 2010, we reported adjusted EBITDA of $1.1 billion and adjusted net income of $594 million. These results represent increases of 8% and 7% respectively over the same measures for 2009. Adjusted net income for diluted unit in 2010 was $3.03, and that compares to $3.14 per unit in 2009. Last month, PAA declared a 3.2% year-over-year increase on our run rate distribution to $3.83 per unit on an annualized basis. As of the distribution payable next week, PAA will have increased its distribution in 25 out of the last 27 quarters.

Yesterday evening, we also furnished financial and operating guidance for 2011 that illustrates PAA's strong performance and is expected to continue throughout the coming year, as the midpoint of our guidance range for adjusted EBITDA in 2011 is projected to be approximately 11% above 2010. Additionally, we believe our ongoing expansion capital program which totals $550 million for 2011, positions PAA for continued growth in 2012 and beyond.

During the remainder of the call today, Harry, Dean, and Al will discuss the details of our fourth-quarter performance relative to guidance, review our capital projects and acquisition activities, provide an overview of capitalization liquidity, and also the primary drivers and information that supports our 2011 guidance. Following their presentations, I will wrap up with a few brief comments and discuss PAA's 2011 distribution guidance. With that, I will turn the call over to Harry.

Thanks, Greg. I will now review our fourth-quarter operating results compared to midpoint of our guidance issued on November 3rd, 2010, discuss the operational assumptions used to generate our guidance for 2011, and discuss our expansion capital program and acquisition activities. Dean will cover the PNG-specific information in a moment.

As shown on slide six, adjusted segment profit of $322 million for our fourth-quarter compared favorably to the midpoint of our guidance. Adjusted segment profit for the Transportation Segment was $138 million or $0.50 per barrel. The segment profit was a little below the $141 million of guidance midpoint, but was within the guidance range that we provided in November. Volumes for the segment were 2,995,000 barrels per day, just slightly lower than the 3,025,000 barrels per day in our guidance.

Adjusted segment profit for the Facilities Segment was $75 million or $0.35 per barrel, which total was about $4 million above the midpoint of our guidance. Primary drivers for the over performance were lower operating expenses and favorable performance at PNG, which Dean will discuss in a few minutes. Segment capacity was 72 million barrels per month, which was in line with our guidance.

Adjusted segment profits for the Supply and Logistics Segment was $109 million, or approximately $1.49 per barrel. The segment profit was about $33 million above the midpoint of our guidance. The over performance in this segment is largely attributable to a combination of one, increased crude oil arbitrage opportunities captured during the quarter. And then, secondly, higher than forecasted LPG margins, which were primarily due to inventory costing and weather related opportunities.

With respect to our buy-ins, crude oil lease gathering purchases and water borne foreign crude oil imports were a little above our guidance, while LPG volumes were a little lower than forecasted in guidance, primarily due to lower demand. I might point out that beginning in the fourth quarter, we will no longer report volumes associated with our refined products wholesale activities. We don't believe that these volumes are a driver for this segment's performance. To maintain comparability, unit metrics for our prior periods have also been recast to exclude these volumes.

Maintenance capital expenditures were $30 million for the fourth quarter resulting in a total of $93 million for the full year, which is $3 million more than the high-end of our estimate. Let me now move to slide seven and review the operational assumptions used to generate our full-year 2011 guidance which was furnished in our Form 8-K issued last night. My references to segment profits per barrel will be based on the midpoint of our guidance range.

For the Transportation Segment, we expect volumes to average slightly over 3 million barrels per day and segment profit of $0.53 per barrel. This volume expectation reflects an approximate 2% increase over 2010 average volumes. The more significant changes that we expect to see in 2011 include increasing volumes on basin and the Permian Basin Area Systems. I will note that we previously referred to this area as our West Texas, New Mexico Systems. And the full benefit of a full year impact of the Robinson Lake and White Cliffs Pipeline Systems acquired in 2010. The increases will be partially offset by our forecast of lower volumes on our Capline Systems and our Rainbow System.

The lower volume on Capline System has been expected to increase in capacity from Canadian pipelines into Wood River and Patoka. The lower volumes on the Rainbow System have also been expected and were considered in our acquisition economics in 2008 as a couple of our shippers made early commitments to a competing pipeline project in the area. Over the next few years, however, we expect to see volumes on the Rainbow System increase as production for the region increases.

Facility Segment guidance assumes an average total capacity of 80 million barrels of oil equivalent, with segment profit per barrel of $0.37. Projected capacity for 2011 is up about 15% over 2010 average levels, reflecting the impact of our capital projects in the acquisition of Southern Pines Gas Storage Facility. Capital projects are expected to increase capacity by an average of 5.1 million barrels at our Cushing Facility and by approximately 800,000 barrels at our Patoka Facility when compared to our average capacity in 2010.

As Dean will discuss in his section, average gas storage capacity in 2011 is expected to increase approximately 50% over 2010's average capacity of 47 Bcf. The majority of this increase will occur in the first half of 2011 as a result of the acquisition of Southern Pines Facility and ongoing expansion activities at both Pine Prairie and Southern Pines.

Supply and Logistics Segment guidance volumes are projected to average 875,000 barrels per day for 2011 with a projected midpoint segment of profit of $0.85 per barrel. The increase over 2010 levels is expected to come from increases in our crude oil lease gathering volumes and our LPG sales volumes, slightly offset by lower water borne foreign crude imports. Increases in our crude oil lease gathering volumes are expected to be in the Rocky Mountain region, primarily due to our Nexen acquisition, as well as in the Permian Basin and Canada. The lower volumes of waterborne foreign imports is based on expectation that we will continue to see market conditions that are not favorable to the movement of such crude to the US.

Moving on to our capital programs. Excluding acquisitions, we invested approximately $355 million in 2010, including approximately $10 million for base gas of PNG. It's about $5 million under the $360 million capital program we announced at the beginning of 2010, and is approximately $25 million below our updated forecast from last quarter. Weather delays and delays of materials deliveries have shifted this capital investment from 2010 into 2011. That said, we do not expect any material impact to our anticipated in-service dates.

As Greg mentioned, we've established a $550 million expansion capital program for 2011 representing $195 million increase over our 2010 capital program. Slide eight outlines a larger project included in this 2011 capital program. We have approximately $103 million of capital attributable to PNG projects that are primarily related to capital expansion that Dean will cover.

At Cushing, we have three projects in process that total -- weigh out approximately 4.3 million barrels of storage capacity to our facility by the end of 2011. I will note our Keystone connection was recently completed, and we received the first batch of Canadian crude from the Keystone Pipeline this month. Except for minor weather delays, Cushing projects are all progressing on-time and on budget.

Earlier this week, we announced our Shafter Expansion Project. This is a 15-mile LPG pipeline system that will bring volumes from Occidental Petroleum's Elk Hills gas plant to our Shafter LPG processing facility near Bakersfield, California. The system, which is supported by a five-year transportation agreement with Occi, will have an initial design capacity of over 10,000 barrels a day of LPG. It will involve making storage and rail enhancements to our Shafter facilities. The project is expected to be placed into service in the third quarter 2012 and anticipated investment of approximately $50 million. We expect to invest approximately $30 million in 2011.

This year we will be constructing a new 150 million cubic feet per day processing plant in Acadia Parish, Louisiana. The plant will have an interconnect with our Pine Prairie gas storage facility and is expected to be in service by the end of the second quarter 2011. We estimate our 2011 investment will be $36 million.

We are also moving forward with construction of an LPG rail storage and transloading facility to be located near Stanley, North Dakota. Total capital cost is approximately $25 million. It is targeted for service beginning in the second half of this year. Our 2011 capital program is very well diversified, as the 17 largest projects make up approximately 70% of the capital program and no single project exceeds 11% of the total. A directional indication of the in service timing of several of our larger projects is represented on slide nine. In addition to these announced projects, we are in various stages of development on several pipeline projects that are not included in our 2011 capital program.

A few of these projects are fairly large projects. While we are not in position to discuss much about these projects, as you can see from our slide -- on slide 10, our assets are well-positioned relative to the more significant oil resources plays developing in North America. Thus, we are working hard to expand our 2011 capital program beyond our current $550 million. Lastly, with respect to our acquisition activities, we closed on the acquisition of Nexen's Bakken related assets on December 30, 2010. And closed on Southern Pines acquisition yesterday. The integration of the Nexen related assets is expected to be completed in the second quarter.

Dean will update you on PNG's acquisition, Southern Pines Facility in just a few moments. In total, we completed six acquisitions during 2010 for aggregate consideration of approximately $410 million. Overall, we believe we are well-positioned to continue to generate growth from a combination of organic expansion opportunities as well as strategic and asset acquisitions. I will 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 address PAA Natural Gas Storage's fourth-quarter operating and financial results, provide an update on PNG's expansion and acquisition activities, and share a few comments about PNG's guidance for 2011 in the first quarter of 2011. Yesterday we reported fourth-quarter adjusted EBITDA and adjusted net income of $15.9 million and $11.3 million respectively. Such results came in above the high end of our guidance due primarily to better than forecasted hub services performance and higher fuel and oil sales revenue. These results are summarized on slide 11.

I'm also pleased to report that PNG 2010 capital program was completed on time and under budget. Importantly, delivering the targeted working gas capacity on schedule. Overall, our capital program came in approximately 10% under budget due to lower expenditures on base gas as well as some execution efficiencies and timing refinements. At Pine Prairie, leaching operations continue at Cavern Well 4 and we currently estimate we have created approximately 6.8 Bcf of working gas capacity. We remain on track to bring Cavern Well 4 into service in the second quarter of 2011 at approximately 7 to 7.5 Bcf of working gas capacity.

Leaching operations on Cavern Well 5 are ongoing and including opportunistic fill and dewater activities, we expect to bring approximately 10 Bcf of working gas capacity into service in the second quarter of 2012.

Just a few more comments about Pine Prairie. In January 2011, the CME Group, owner of the New York Mercantile Exchange, or NYMEX, announced the introduction of three new natural gas futures contracts for physical delivery at Pine Prairie. The contracts began trading in February on the NYMEX floor and electronically through CME Globex and will be available for clearing services through CME ClearPort. While it may take time for these contracts to develop, we are very excited to be chosen as the designated NYMEX delivery point. And believe it is an appropriate recognition of the fact that Pine Prairie is very well located and equipped to be a major market hub for natural gas.

Lastly, Pine Prairie's operating capabilities were on display during the cold snap that passed through much of the US last week. During that period, we set new records for daily withdraws delivering as much as 1.3 Bcf on certain days. Throughout the severe weather, we have been able to meet all of our customers' contractual nominations, including service requests in excess of our contractual commitments.

Let me now move on to Bluewater. As many of you have seen from our press release and 8-K in January, we had an incident and related fire at our Bluewater Storage Facility in Michigan. Fortunately, there were no serious injuries. We did have one employee who suffered minor burns, but he was examined and released to resume normal activities that day.

Facility damage was limited to the portion of the gas handling facility that strips the liquids from gas that is withdrawn from the larger of our two storage reservoirs before such gas is delivered into pipelines for transportation. As a result, the amount of gas we can withdraw from that storage reservoir has been temporary limited. However, we are still able to withdraw gas from our other storage reservoir and our ability to inject gas into either storage reservoir should not be impacted.

Through the utilization of these capabilities, PNG's lease storage in the market area and other operational and commercial alternatives, we have been able to meet all of our customers' contractual requirements to date. Based on our current expected customer demand, we expect to be able to continue to meet our obligations throughout the remainder of the withdrawal season, which typically ends March 31st. Because this incident does not impact our injection capabilities, we believe we will be able to satisfy our customer obligations once the injection season commences.

Subject to receiving the necessary regulatory clearances and permits, we are currently targeting to have the damaged portion of the facility back in service by October, which should return Bluewater to fully-functional operations for the balance of the 2011/2012 storage season. We currently estimate the total cost of reconstruction will be about $4 million to $5 million. Although, we are still working through the claims and adjustment process, we expect a majority of this cost will be covered by insurance less our $500,000 deductible.

As a result of this incident, we have had to defer our planned capital program for Bluewater, with respect to the drilling of two additional liquid withdrawal wells until early 2012. We expect that combination of the commercial and operating impacts, the deferred capital program, and the insurance deductible will result in the non-recurring reduction of PNG's 2011 adjusted EBITDA by approximately $5 million. This impact has been incorporated into PNG 's 2011 guidance.

This was clearly an unexpected and unfortunate incident. However, we are pleased that our safety systems operated as planned, and we are very proud of our employees response, both to the incident itself and operationally and commercially in terms of their ability to fully meet all of our customers' needs, especially given the very demanding conditions caused by the recent extreme cold weather.

Turning to other matters. On December 28, 2010, we issued a press release announcing the planned acquisition of Southern Pines and held a conference call to discuss the acquisition and its strategic fit with PNG. I won't repeat those discussions here today, but I do want to mention that we closed the transaction yesterday.

The only notable change to the transaction terms we discussed on a prior conference call is a $4 million purchase price reduction for estimated costs to replace an existing wellhead seal and make other modifications and upgrades to the wellhead assembly of Cabin Well #3 after closing. These modifications are similar to modifications we made last year on Cabin Well 3 Pine Prairie.

Overall, the integration and ownership transition process is well underway. Although PNG is a relatively new entity, as a part of the broader PAA organization, we have access to significant resources to help us through this process. Since going public over 12 years ago, PAA has made over 65 different acquisitions, and their experiences and resources have been very valuable as we have positioned PNG to integrate Southern Pines into our organization and execute our plans for this asset. Al will address the financing for this transaction in his part of the call.

Let me now discuss PNG's guidance for the first quarter and full-year of 2011. Yesterday we furnished an 8-K, in which we provided operating and financial guidance for the first quarter and full-year 2011. Selected portions of this guidance are summarized on slide 12.

Our guidance for 2011 forecast a range for adjusted EBITDA of $101 million to $111 million, with the midpoint of $106 million, essentially, double the reported level for 2010. The primary source of the growth and adjusted EBITDA is one; the addition of Southern Pines; two, the full year realization in 2011 of capacity at Pine Prairie brought online in the second quarter of 2010; and three, the incremental Pine Prairie capacity to be brought online in the second quarter of 2011. Collectively, PNG's average gas storage capacity for calendar year 2011 is expected to increase to 71 Bcf, approximately 50% over 2010's average capacity of 47 Bcf.

The projected capacity at year end 2011 of about 75 Bcf is also 50% higher than 2010's year-end capacity of 50 Bcf. These volume estimates exclude storage capacity we lease from third parties. Adjusted EBITDA for the first quarter of 2011 is expected to be between $14 million and $18 million. This guidance incorporates a partial period contribution from Southern Pines. But also reflects our estimate of the negative impacts of the Bluewater incident, which we expect to be largely confined to the first quarter of 2011.

With respect to PNG's 2011 capital program, we currently anticipate our organic capital investment will be $103 million, including capitalized interest. Approximately $70 million of this capital is related to Pine Prairie and includes the installation of compression, leaching activities on Cabin Wells 4 and 5, the conversion of Cabin Well 4 to storage service, and various fill and de water activities. Approximately $30 million is related to Southern Pines and includes the completion of the drilling operation on Cabin Well 4 and ongoing space creation in Cabin Wells 1, 2, and 3 through primary leaching activities, fill and dewater activities, and solution mining under gas or SMUGing.

Capital activities at Bluewater include reconstruction of our JT unit and other miscellaneous activities and are expected to total $3 million net of insurance. Maintenance capital for PNG is expected to be approximately $800,000 for 2011. I want to point out that the major economic inputs for PNG's 2011 guidance are consistent with our view that storage conditions will remain challenging for the near future with respect to both term storage arrangements and hub services. With respect to leasing capacity that will be available later in 2011, our customer discussions and negotiations are ongoing. However, for competitive reasons, we will not comment on specific pricing levels or contracted volumes prior to their effective date.

That said, we believe PNG's solid contract portfolio and low-cost expansion projects position PNG to grow and prosper even if the market remains challenging for natural gas storage. This solid positioning is illustrated on slide 14, which highlights both our existing contract portfolio and projected growth and working capacity through the 2013/2014 storage season. On the strength of this outlook and subject to continued operational execution, PNG increased its annualized distribution for the February 2011 distribution to $1.38 per unit, and is targeting to exit 2011 at an annualized run rate of $1.45 per unit. Such exit rate would represent an approximate 7.4% increase over PNG's 2010 annualized exit rate of $1.35 per unit.

While distribution coverage will vary from quarter to quarter as shown on slide 15, based on the midpoint of our annual guidance, we anticipate distribution coverage for 2011 will total approximately 104%. Before I turn the call over to Al, I want to share with you PNG's 2011 goals, which are highlighted on slide 16 and include two. Number one, deliver baseline operating and financial performance in line with our guidance. Two, close, integrate, and execute the Southern Pines acquisition. Three, successfully execute our 2011 capital program, achieve targeted working capacity, and set the stage for continued growth in 2012 and beyond. And as I just discussed, increase our annualized distribution level to $1.45 per unit by November 2011.

We are very excited about this robust set of organic growth opportunities before us, and the benefits that will be realized by our equity holders from simply executing the growth we have outlined. Because of our need to focus intensely on the integration of Southern Pines and the execution of our capital program, we have not made completing acquisitions a primary goal for 2011. That said, we intend to remain active on the acquisition front but will continue to be very selective. With that, I will turn the call over to Al.

Thanks, Dean. During my portion of the call, I will discuss the capitalization, liquidity levels, and recent financing activities for both PAA and PNG, and also provide comments on PAA's guidance for the full year and first quarter of 2011. As summarized on slide 17, PAA exited the year and is beginning 2011 with solid capitalization, approximately $1.4 billion of committed liquidity, and credit metrics in line with our target. In recognition of both an upward shift in acquisition multiples and longer lead times for realization of synergies and commencement of cash flow from expansion projects, we have refined PAA's financial growth strategy slightly. As refined, our credit metrics now reflect a debt to EBITDA ratio that will average within an approximate target range of approximately 3.5 to 4.0 times.

Previously, we were targeting a 3.5 times based on current debt and forward EBITDA. We have also increased our target to fund at least 55% of our growth capital with equity or retain cash flow. This was previously 50%. The committed liquidity, I mentioned, includes approximately $140 million of availability under the PNG revolver, as well as the full $500 million of available liquidity under PAA's 364 day revolving credit facility that we entered into during January 2011. At December 31, PAA's adjusted long-term debt to capitalization ratio was 48%, and our adjusted total debt to capitalization ratio was 57%.

Excluding the $466 million of notes used to fund inventory, our adjusted long-term debt balance was approximately $4.2 billion. The total debt ratio includes $1.8 billion of debt that supports our hedged inventory, associated accounts receivable, and associated margin. This debt is essentially self liquidating from the cash proceeds when we sell the inventory and collect the receivable. For reference, our short-term hedged inventory at December 31, 2010 was comprised of approximately 21 million barrels equivalent with an aggregate value of $1.5 billion. The remaining $300 million was attributable to accounts receivable from inventory sold during December and margin posted on the NYMEX and ICE exchanges.

In addition to these inventory volumes and values carried as a current asset, we have approximately 13 million barrels equivalent of line fill and base gas carried as a long-term asset that has a historical book cost of approximately $670 million. For 2010, our adjusted long-term debt to adjusted EBITDA ratio was 3.8 times and our adjusted EBITDA to interest coverage ratio was five times.

With respect to PNG's capitalization, PNG exited the year with a debt to capitalization ratio of 26%, adjusted EBITDA to interest coverage of 20.3 times and debt to adjusted EBITDA ratio of 4.2 times. Subject to covenant compliance, PNG committed liquidity with $140 million at December 31. Since the third quarter earnings call, both PAA and PNG conducted a few financing activities. Let me first address PAA.

In mid-November, PAA completed a $4.8 million common unit offering including the December exercise of the underwriters' overallotment option. It totaled net proceeds of $296 million, which includes the general partners proportionate contribution. In early January, PAA entered into a $500 million 364-day revolving credit facility which remains undrawn. And later, in mid-January, PAA completed a $600 million senior note offering for net proceeds of $592 million.

Proceeds or liquidity from these three financing total $1.4 billion. Of the approximate $900 million of cash proceeds from the equity in senior note offerings, $230 million was used in connection with the acquisition of Nexen's Bakken related assets that closed on December 30. $222 million was used to redeem PAA's $200 million 7.75% senior notes that were maturing in 2012, and $430 million was used to fund PAA's obligations to PNG in connection with its acquisition of Southern Pines.

The remaining cash proceeds and the flexibility provided by the $500 million revolving credit facility will be used to maintain solid liquidity as we execute our $550 million 2011 expansion capital program and pursue accretive acquisitions. As shown on slide 18, and as adjusted for these financing activities, PNG's consolidated -- 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 proximally 10 years. We have no maturities until September 2012 and 90% of our long-term debt is fixed. We have an average rate of 5.9%.

PNG was also quite active in its financing activities in connection with its acquisition of Southern Pines, PNG entered into a three-year 5.25% unsecured term loan with PAA and issued $27.6 million common units in a private placement raising $600 million. Approximately 17.4 million common units were purchased by institutions and other large investors and the remaining 10.2 million common units were acquired by PAA on substantially similar terms. Proceeds to PNG totaled $800 million which funded the $750 million purchase price and associated transaction costs. The excess proceeds will ultimately be used to fund the next 18 months or so of expansion capital at Southern Pines, but were initially used to pay down the balance on PNG's revolving credit facility.

Included on slide 19 is a condensed capitalization for PNG, as reported at December 31, 2010, and as adjusted to give effect to the Southern Pines acquisition and PNG's financing activities completed yesterday.

Before I move on to guidance, I want to point out that PAA's fourth-quarter and full-year reported results include a $35 million equity compensation expense associated with our year end determination that a $4 annualized distribution is now probable. The potential for this expense was discussed in our November 3, 2010 guidance 8-K, but was not included in the tabular guidance forecast since we have not yet reached a probability determination for the $4 distribution level.

When PAA's general partner grants equity awards, the vesting requirements include both a minimum service period as well as a performance threshold associated with future distribution levels. As required by GAAP, we accrue compensation expense only for awards that contain performance thresholds that are that are considered to be probable of occurring. When we increase our probability assessment regarding future distribution levels, we are required to accrue an expense for the completed portion of the service period. The current period charge is larger than normal, as most of these grants date back to 2006 and 2007 and the value of PAA's units have increased approximately 30% from when the grants were made.

Of the $35 million equity compensation expense related to the $4 performance threshold, approximately $25 million is associated with equity-based awards, and we expect that the majority will be settled with PAA common units or class B units in our general partner. As a result, this amount which excludes the portion attributable to our cash plan, is added back to adjusted EBITDA and adjusted net income, as a selected item impacting comparability. Approximately $18 million of this amount is represented by PAA common units. Once the performance threshold is achieved, the applicable -- PAA common units are included in the determination of fully diluted units outstanding. The remaining $7 million of the $25 million expense associated -- is associated with our class B units and our general partner, for which PAA bears none of the cost. But is required to be pushed down to expense in PAA's income statement.

The remaining $10 million expense relates to equity awards that will settle in cash and, therefore, do reduce adjusted EBITDA and adjusted net income for the fourth quarter and full year of 2010. The high points of our 2011 guidance, which exclude selected items impacting comparability between periods, are summarized on slide 20. For more detailed information, please refer to the 8-K that we furnished last night. For the full year of 2011, we are forecasting adjusted EBITDA to range from $1.19 billion to $1.26 billion with adjusted net income attributable to claims ranging from $645 million to $737 million or $3.06 to $3.70 per diluted unit. Our full year 2011 guidance reflects an estimated 77% percent contribution from our fee-based segments.

First-quarter adjusted EBITDA is expected to range from $280 million to $310 million for a midpoint of $295 million. 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 of our 2011 guidance is included in the inset in the upper right side of slide 20.

The midpoint of the 2011 guidance furnished yesterday is approximately $80 million above the preliminary 2011 guidance we provided in November 2010. The majority of this increase is attributable to the impact of the Nexen and Southern Pines acquisitions that were announced and closed after we provided this preliminary guidance. The remainder is attributable to a slightly more positive outlook for the fundamentals that impact PAA's business as well as the typical refinements in the refining process.

In general, our 2011 guidance embraces the positive impacts of the domestic crude oil supply side response to crude oil prices and increasing oil resource development in many of the regions in which we have a strong presence. Additionally, we would characterize our views on the demand side as less negative than our views three months ago.

Although consumption levels are still much lower than the levels experienced in 2005 to 2007, we do believe that consumption declines have bottomed out and there are some signs that consumption may, in fact, be on the uptick. Given the strong production gains in the US, we anticipate suppressed waterborne imports of foreign crude oil and that foreign quality differentials will remain in a tight range. We are also modeling a relatively weak market structure for crude oil that will provide only limited optimization opportunities which are included in the first part of 2011. Additionally, our guidance excludes the impact of potential acquisitions on our results and our capital structure.

Finally, I just want to comment that we did complete the tax restructuring with respect to our Canadian entities at the end of 2010, and the estimated impact of all of our Canadian entities being taxable in 2011 is included in our guidance. Importantly, effective for the 2011 tax year, PAA's unit holders will no longer be required to file a tax return in Canada. And a portion of the tax that PAA pays in Canada will result in a tax credit to PAA's unit holders and general partner. If you would like more information on this topic, I would direct you to our website for a copy of the November 4, 2010 conference call script in which we discussed this topic in more detail. With that, I will turn the call back over to Greg.

Thanks Al. We are very pleased with PAA's performance in 2010. At the beginning of last year, PAA publicly established four goals for the year. Specifically, these goals were to delivered baseline operating and financial performance in line with guidance, successfully execute our 2010 capital program and set the stage for growth in 2011 and beyond, continue to pursue strategic and accretive acquisitions, and lastly, increase our annualized distribution level to $3.80 per unit by November 2010. As covered throughout today's discussion and summarized on slide 21, PAA met or exceeded each of these four goals delivering performance above the high end of the guidance, executing the 2010 capital program on time and on or under budget, successfully making strategic and accretive acquisitions, and increasing the distribution to $3.80 per unit on an annual basis.

During 2010, we increased our distributions paid by 3.7% over distributions paid in 2009, while generating a healthy distribution coverage ratio of 111%. Slide 22 summarizes our public goals for 2011, which are very similar to our 2010 goals. These goals include deliver baseline operating financial performance in line with our 2011 guidance, successfully execute our 2011 capital program, and set the stage for continued growth in 2012 and beyond, continue to pursue strategic and accretive acquisitions, and lastly, increase our November 2011 annualized distribution level by approximately 4% to 5% over the November 2010 distribution level.

Longer-term, we continue to target to achieve average annual distribution growth within the 3% to 5% range. The foundation of our growth outlook for the next several years is a fairly extensive inventory of organic growth projects, which will be augmented by our acquisition activities. Our distribution growth goal for 2011 is clearly in the middle to upper end of that long-term range. Slide 23 provides a recap of PAA's 2011 implied distributable cash flow based on the midpoint of the guidance range that Al just discussed. Assuming achievement of our 2011 distribution goal, we would expect to generate distribution coverage for the year of 2011 of around 107%.

Similar to 2010, the quarterly coverage level can vary quite a bit as the second and third quarters are typically the weakest quarters, and distribution coverage can dip below one-to-one even though annual guidance supports a level above one-to-one for the whole year. As a result, we typically look at several quarters of expected performance in related coverage for establishing our distribution growth objectives.

Looking beyond 2011, we anticipate that the $355 million of capital we invested in 2010 and the $550 million of capital program we have slated for 2011 will extend our visibility of distribution growth over the next few years. And we continue to work diligently to expand that inventory of organic growth projects even further. Additionally, we remain disciplined but also very active on the acquisition front and hope to be able to make a positive impact on 2011 and future years as a result of these activities.

Let me close by sharing a couple observations with respect to why we think PAA represents an attractive investment opportunity that combines a low risk business profile and attractive total return. Over the last several years, PAA has faced a number of extreme real-life macro and micro stress tests. These have included severe commodity price swings, a major recession, a near collapse of the financial markets, instability of our competitors and customers, and a 10% reduction in total US petroleum consumption.

Throughout this period of time, PAA illustrated the durability and versatility of its business model, asset base, and related cash flow streams as it navigated all of those elements by still executing the business plan, delivering on its public guidance, and achieving its annual goals. Specifically, with respect to 2010, PAA's performance highlighted its ability to perform even during shifts between demand driven markets and supply driven markets. Throughout all of these periods, PAA has achieved or exceeded its goals for each year, maintained its low risk business profile, and demonstrated its commitment to maintain a solid capital structure and strong liquidity that has an investment grade profile.

We believe the combination of PAA's tested and proven low brisk business profile, attractive current yield, invisible source of current and future distribution growth, provide PAA's current and potential investors with a very attractive total return proposition that can be further enhanced from time to time with large strategic acquisitions.

We appreciate your participation in the call today. We thank you for your investment in PAA and PNG and for the trust that you have placed with us. We look forward to updating you on our activities during our first quarter call in early May. At this time, we would open the call up for questions.

(Operator Instructions) Our first question comes from the line of Michael Blum; Wells Fargo.

Hi. Good morning, everybody. A few questions. Number one, you sort of touched on this, but can you talk a little bit more about how the current spread between WTI and brent is impacting your business? Or is expected to impact your business either to the positive or negative?

I think the impact would be less foreign crude moves into the US Gulf Coast. We've got that segment of our business we have got offsetting factors that are offset by more production in the US that feeds through our US-based pipeline system terminals.

Michael, I think Al touched on it when he talked about the guidance for next year. We have actually forecasted lower foreign volumes in 2011 because of that.

Okay. Second question. Now, there is sort of an upswing here now in organic expansion around some of these new oil shale plays. Are you seeing any upward pricing pressure, as it relates to materials, or getting crews, or anything of that nature? Do you expect to see that?

The answer is yes and yes. I think it's probably regional right now in terms of the pressures, but, Michael, it's always happened every time you have a boom service company costs go up. It gets hard to find more and more labor that has the skill sets. Therefore, you end up paying a premium for those that do, and they kind of pull up the whole wage scale. So, the answer is, yes, we do expect to see that happen.

Have you already sort of baked that expectation into your CapEx budget?

Pretty much. I mean, you certainly can't forecast all of those dynamics as you put together a capital program over a 12 month to 18 month period, but certainly we have tried to.

We have somewhat taken care of it, a little bit not so much in the capital forecast, but in our return expectations. I think we've got built in there that there is room for some slippage so that we make sure we make a good return.

Okay. Got it. And then just last question I guess for Al really. Can you walk through -- maybe I missed this but can you walk through the thought process of now targeting a 55% equity financing versus 50%?

Yes. And, a little bit, when you look at kind of what we are seeing with acquisition multiples being one, that 50/50 technically works when you're closer to a seven or eight times. So we are looking at, and I always have looked at a target, but then we really look at the actual cash flow from the asset we are requiring and try to balance it to it. And what we are finding is that we really need to be at that 55%. Again, sort of how we view is at least that much. So, really, what we have done is kind of changed our target to equal what our practice has been.

Okay.

Michael, I mean, effectively what has happened when we set our goals several years, when we set our metrics, a lot of our capital projects we might start in January or February and they are kicking in cash flow by the second half of the year. A lot of our projects right now, they still have what I call short lead times relative to the multi-year, multi-billion-dollar projects. But we look at, for example, 2011. I think if we took out all the capital programs that we plan on spending $550 million, I think the impact on 2011 was less than 2% or 3% of EBITDA.

So what that means is you've just got a longer lead time on your balance sheet for some of these calls, so I think it is prudent for us to do two things. One, was to adjust the amount of equity and cash flow we are going to use to fund that so that we keep the right profile from a credit standpoint. And then the other metric that Al mentioned that we are moving to is widening that banned out for 3.5% to 4% which is really an acknowledgment of reality. We have been running about 3.8%. If you stop spending, we will go back down to about a 3.5% pretty quick. But we don't think we are going to stop spending. If anything, we think our projects are having a little bit longer lead time, so it's just a recognition of the reality of the market.

Okay. Got it. Thank you very much.

And if the rate agents are listening I just want to make sure they know we are doing all of the prudent things.

Our next question comes from the line of Darren Horowitz from Raymond James.

Good Morning, guys and congratulations on the good quarterly results.

Good morning, and thank you.

Greg, a quick question for you as it relates to what's going on in West Texas. With a lot of the producers there moving crude to St. James and obviously, the large differential between WTI and Louisiana Sweet. How do you all think about expanding St. James' storage and take away capacity to get a lot more of that product to Patoka? As you mentioned, it seems like the wide price differentials by grade are probably going to remain. It would appear to me that that would be an excellent supply and logistics opportunity to capitalize on that regional arbitrage.

I don't think you could move West Texas crude to St. James, not unless you put it on a barge.

Physically, it is not really moving in any volume in that direction. You have got rail or barge I guess is the only way to get it there.

So, is it then most of the crude that is the foreign import crude? Or any opportunity for some of the Cushing crude since it is so full on a capacity basis coming down?

Well, I think what's going to happen is, we haven't talked about all the pipeline projects that we have on the drawing board. But, something is going to have to happen to move more crude into an area supplied by LLS.

Okay. How do you guys--

I'm sorry for being so (inaudible) here Darren. The pipeline infrastructure coming out of West Texas, the only pipeline that can source crude out of West Texas and get it into a market that competes with LLS and Mid Valley Pipeline and that pipeline has been full for quite some time.

Sure.

You can't actually move from West Texas that way. You could also come up Basin, get into Ozark, bring it over into the Wood River area. But the Ozark has some limitations as well. So, I mean, that's really what a lot of, what a lot of sort of the thoughts are is, how do you get crude that used to move up different corridors into an area that can source LLS type crudes.

Sure. Along the same lines, how are you thinking about Eagle Ford crude getting over to St. James?

Let me say it this way, we have a $550 million capital program that does not include solutions to that. We are working really hard to make that $550 million bigger.

I think rail is going to be the short answer. If you look to short term, there will probably be some rail to move it from Eagle Ford to St. James. But, I don't think that is really--

Doesn't seem like the long term solution?

Yes.

Switching gears, Dean, over to you. A quick comment on the spread environment between a lot of the hub cash prices in the futures curve. I fully appreciate that you don't want to comment on specific cabin pricing, but how do you think about from the big picture perspective, balancing the duration of contracts versus price, as you look to our new contracts rolling over, I recognize it is only 10% or 15% of capacity that's exposed in the near term, so it's really more of question for your 2012 outlook when you have about 25% of the capacity rolling off.

That's a good question, Darren. I will try to be as specific as I can for you. I mean, when we talk to customers, depending on the type of customer, they each have their model and they are looking at their prices. I think what we see right now spread is one component of it, but it is really how much flexibility do they want? How many turns? We are seeing a little bit -- a lot of the customers wanting to go a little bit less on term, and a little bit less on the flexibility or the number of turns. So the volume is there, as we talk to them, it really gets down to what each particular customer desires. Generally, as a trend, that is what we are seeing out there right now.

Okay. And then last question for me, Dean. Just a big picture question, this kind of builds off your comments about the potential for Pine Prairie to be a major marketing hub. As you think about integrating the Southern Pines assets, and the Basil Gas Processing plant, how do you think longer term about leveraging that footprint to capture more value across the entire natural gas supply chain?

Well, I think you hit all the components. The key to Pine Prairie and what makes it attractive to do the things you alluded to, is the huge interconnects that we have going across it, and the flexibility of moving the supply all over. To that aspect, I mean, big picture, clearly, Southern Pines is a great asset. A great asset particularly to market demand in the Southeast. Pine Prairie, where it sits, has market demand but great access to really all the supply components of the industry right now. And then as we look out, we certainly have our eye on storage in other market areas that we are currently are not in. So from a big picture, when you put it all together and as we go forward, yes, we will look at leveraging those together just on the points you mention.

I appreciate the color. Thanks, you guys.

Your next question comes from the line of Brian Zarahn from Barclays Capital. Please go ahead.

Good morning.

Good morning Brian.

I guess picking up on an earlier question. You're expanding your basin pipe. Can you talk about what you are seeing in the Permian and if it's possible to give a little bit more color on what opportunities you see to increase take away capacity in the region?

Yes, a little bit. There's a lot of activity, as you certainly know, in the Permian basin. We currently have -- take away capacity on basin. Basin is not full, but we are looking forward. As we see increasing production, we are trying to get out ahead of the curve and make sure the basin has enough take away capacity. So the basin project has 50,000 barrels a day. Like I said, basin is currently not at full capacity. We also have another pipeline system, Mesa Pipeline. We move about 120,000 barrels a day on our -- 100,000 to 120,000 barrels a day on our share of Mesa, and it has capacity. We are looking at alternatives at sort of de-bottleneck the Mesa's connecting carriers to increase movement out of Permian basin as well.

We've got a number of projects we are looking at in West Texas to expand pipelines to connect to our existing infrastructure. We think we are very well situated. We have a vast asset presence in the Permian basin and, certainly, expect to spend a fair amount of capital they are this year.

And turning to your recently announced Shafter Expansion Project, do you see other near-term opportunities with Occi?

We think our opportunities to expand relationships, or opportunities with Occi, yes.

Clearly, Brian, we get the question probably every other quarter at least. We are having good dialogue. Obviously, they made a bigger vote of confidence here recently by increasing their interest. But when you stand back and look at their footprint in California and you look at our footprint in West Texas and now in the Rockies, and in the Bakken area, I think there are opportunities as we go forward for us to do what we would do normally with the entire producing community. But perhaps be able to also accommodate a very large player that, clearly, has a significant amount of financial firepower and is shown to be a very savvy investor. Hopefully, this is the first of many opportunities yet to come.

And the final question is, given the incident at Blue Water and the recent incident of the competitor facility in Mont Belvieu, just rolling that in together with others sort of high media attention and energy incidents for pipelines and other spills, can you talk about what you are doing to review all of your integrity of your assets and any broader impacts on costs going forward and will this increase -- these recent events, increase regulatory scrutiny?

Well, the question of regulatory scrutiny or increased regulatory scrutiny is not a question. It's just a fact. It's there and it's going to be there. I don't know that we quote do anything different, because we have been for several years, and we've been disclosing in our 10-K and other areas that we have been well ahead of what I think of what we think industry or regulatory demands are going to be, whether they are required by jurisdictional [pies] or non-jurisdictional. Do we basically-- we were trying really hard before. Do we try even harder? I think the answer is, absolutely. It's not an major step change for us because we were already pretty intense on that. I think we had estimated -- we spend-- everybody looks at maintenance capital, we expense a tremendous amount through our P&L activity we spend on routine maintenance and upgrades and integrity management. I mean, I believe it's in the well over $100 million I believe. Brian, we are pretty aggressive in that area to try to be ahead of the curve. If you take each incident and you try to relate them, you can't really, but as you say, if it starts happening enough, you just get tremendous increase and focus, and that's just not a question. That's an answer.

Thanks, Greg.

Our next question comes from the line of Jeremy Tonet from UBS.

Congratulations on the strong quarter. I just wanted to touch on some of the earlier questions, I guess. In regards to the gas processing project that you guys spoke of, do you see other opportunities to do similar types of projects around your current asset base in the future?

I think there is, certainly, some. I think what we have right now, when we bought CDM Max what was it, here two years ago?

Yes.

What we got is, is a crew of people that really, really know processing inside and out and efficiency. I think there is a tremendous opportunity with all of the drilling that is going on in some remote areas to, basically, find ways to optimize the extraction of value from the whole value chain by building very quick, efficient plants. I think this plant that we are building there is -- what, $120 million a day?

$150 million a day.

$150 million a day. Its efficiency is almost unparalleled. With the liquids differential relative to gas today and what is likely to continue to happen, I think there would be significant number of opportunities there. Within our organization, what we refer to as the CDM Max, which is the subsidiary, they see a lot of opportunities to be able to take on multiple projects. If they were out on their own, which they were at one point in time, it was all project financing stuff. We certainly hope to see an increase velocity over that over time.

Great. That's helpful. Thanks. In regards to 2011 guidance, it seems with the LPG volumes in facility segments, it appears to be decreasing year in year, while the supply and logistics -- in the supply and logistics segment, the LPG volumes looked to be increasing. Could you give a little color on what is driving this?

Yes, just a second. On LPG, part of it is just a function of trying to predict what you think weather is going to be. In some cases, Jeremy, from year-to-year, we will back out volumes we think our low-margin. So, if the margins improve, you may see the volumes come back. Part of the way we communicate with the market is we tell people we are not making enough money and there's a negotiation and sometimes they actually have to pull back to realize that they need you. I don't think there's any particular trend there in LPG that would let you think we are de-emphasizing that. And on the supply and logistics, I think the overall volume increase you are seeing is the amount of activity that is going out there in drilling.

The processing on the facility side is primarily the asset out in Bakersfield, and it does have a component as it relates to kind of the whole refining sector out in California. But it's a very small part of the overall LPG business.

Great. Thank you.

Your next question comes from the line of Gabe Moreen from Bank of America.

A lot of questions have been asked, and I hate to harp on California again. But I will do it and see if I can fish for some volume guidance on line 63/ line 2000. It seems like that has troughed, but you are not expecting much credits in 2011. Is that just kind of a question of timing, or is that something where I guess the volume growth that everyone expects out there in California could be going elsewhere?

Well, I don't know exactly how much volume growth that California has experienced. It's been a little, but there's also been declining offshore volumes too, so you have to look at sort of the increasing onshore volumes with declining offshore volumes when you look at what's being moved on the pipeline from Bakersfield north to San Francisco or South to L.A. I think our view is that probably volumes south into L.A. are going to be kind of at the same level that they are at right now. Not expecting a lot of increase or decrease.

Okay. And I guess moving on to Michael's earlier question about capital cost inflation, and the indication that you are considering several large capital projects on the pipeline side. Historically, you have talked about having a bunch of discrete projects, capital costs overruns on any one of those won't really blow up your budget per se since it's all a bunch of discrete projects. Can you talk about managing risks around larger projects and whether you are going to see the need to JV with people or just in terms of laying off the risk on shippers?

I think you'd see a combination of all of the above. I think joint ventures are very difficult to do. There are a few limited companies out there that we would probably consider doing joint ventures with. Certainly, there have been some preliminary discussions in areas that people evaluate all potential alternatives to try to come up with the best answer. With respect to, when we talk about larger pipeline projects, again, we are not talking about multi-billion dollar, multi-year projects. We're probably talking about more things that are in the, $300 million, maybe as much as $400 million range and stuff that would probably take probably, 18 --

18 months to 24 months.

So there's some exposure there, Gabe, but not of the magnitude perhaps that we have seen on some of these other projects where you had two and three-year construction periods, and a couple billion dollar numbers that turned into a couple billion dollar plus numbers. I don't think we are facing that. And in almost all the cases where we are talking about something big enough, we are talking about some participation protection in our execution risk on that. You can't lay off 100% of it, but you want to make sure you don't fix your revenues and have all your costs float and end up having your margin eroded.

JVs are probably more in the context of opportunities where they are just synergistic. They make sense as opposed to trying to lay off some of our -- some of our capital exposure or risk.

Okay, great. And then just last question. In terms of the guidance on profit per barrel and supply and logistics for the first quarter, being, I think $0.98 versus $1.49, you realize in the fourth quarter given that if anything differentials and cantangos seem even better in the first quarter thus far in the fourth quarter, is it LPG opportunities, or is it just that it is not March 31 yet?

Well, we had some unique opportunities in the fourth quarter. Obviously, if we would have known they were going to transpire, our guidance would've been higher. They were sort of non-repeating. Where you were able to put some crude into inventory because differentials blew out. Look at what happened in Canada, differentials got wide, came in, got wide again. So we saw some velocity in some of the buy in that we had in tankage, both in US and Canada, it isn't necessarily repetitive. When you put that gain against, the metrics in the volume category, it adds a lot of margin. Like I said, it isn't necessarily repeatable, but we definitely try to capture those opportunities when they arise.

Great. Thanks, everyone.

Under promise, over perform.

Understood.

Thanks, Gabe.

Our next question comes from the line of Ross Payne from Wells Fargo.

My only question is on this new leverage range that you put out there. Is it safe to say, too though that if you do a large acquisition of some sort that it can't go above that range but that is your long term range -- goal to get back to range, correct?

Yes, Ross. Clearly, if we would tip above 4, our intent would be to bring it back down in a fairly quick timeframe. Again, we aren't trying to set an absolute ceiling. Our intent will be to run within that range, and like Greg mentioned earlier, if we stop growing, we probably gravitate toward the lower end of it. But when we are in a growth mode, we would be more in the midpoint, which is what we have been running.

Ross, we run our models -- again, part of this is trying to make sure that we communicate what we are going to do and then do it and not have a metric out there that we are constantly not getting to and have people think that it is not real. If we quit spending our growth capital tomorrow, we quit making acquisitions, we will be at 3.5% and go sub 3.5% pretty quick. What we have seen now is we have kind of institutionalized an aggregate level in of acquisitions that is probably in the $300 million to $500 million a year range, and our capital program building up, and that comes with tremendous economics, but it is always on a delayed basis.

We felt like it was appropriate to boost the amount of equity that we are funding those projects with, and then also to recognize that as you pointed out, as we do those it's going to put us at the, closer to 3.8%, 3.9% possibly even a 4% number. We recognize that as the range and the wording that we have used for our policy is that we will average within that range. Clearly, if we go outside of it, you are going to see us hustling pretty quick. We don't want to jeopardize the upward momentum we have on our rating. We think we are at least one click if not two clicks below where we need to be, and this is, basically, a way of acknowledging that we are still going to maintain discipline even as we continue to build the company, so I am hopeful that this is viewed very much as a positive recognition where we see some of our peers or other competitors, they may have a target, but they are never there. It seems to us you ought to have one that is basically, realistic.

Absolutely. Thanks for the clarification, guys.

Your next question is from the line of John Edwards from Morgan Keegan & Company.

Yes, good morning everybody. Just a quick question. With all the unusually cold weather we've been having, I'm just curious what impacts you are seeing on natural gas storage pricing, if any.

Yes, John. At least when you look at it right now, I think today it is supposed to be the coldest day across the nation on average. Next week you are going to have the warmest day this winter on the nation. I think when you look out there, you are not seeing the front end move up. Actually, it is moving in the opposite direction. So as far as the pricing you are seeing, it seems to be going -- people are anticipating I guess supply to be strong. As far as right now what is going on, a lot is coming out of storage, but as far as pricing, it's kind of holding where you can look at the screen and see it is in the low $4 range.

John, I might just comment. It kind of goes back to Darren Horowitz's question too, is, when we look at our leasing decisions, I think we have given ourselves with our profile, the leases that we have, relative to total capacity, a lot of time to be patient. I think time is on our side for the following reason. I think as we have seen these cold snaps come through here, any facility can operate probably in a milk toast kind of market. But what we are seeing right now, we have had draws of up to 1.3 Bcf a day for several days. That's really hard on a facility, and our goal if you recall from a couple conference calls about is to be in a position to never have to tell our customers no. Yes is the answer we want to give them. We think we are seeing in some of the competing facilities where they may have perhaps established a nameplate that may be above their actual physical capacity. So I think when it comes time for renewals, one of the things that's going to happen in the next 24 months is that people are going to say, you may tell me I can do that, but if you force majure, or you have some operating limitation on me, it doesn't do me any good to have this horsepower and not be able to use it. Ultimately, right now our goal is to try to make sure we never have to tell our customers no and that we meet our obligations.

We've done that at Pine Prairie, we intended to do the same philosophy at Southern Pines has had to try to make sure we do that. And then even with Blue Water, as we have had the challenges we have had there, clearly, we didn't expect that, but we have been able to meet all of those obligations. We want to continue to do that. I think, ultimately, just like we have in Cushing, we have the most versatile, the most high-performance facility up there. I think if you gave anybody equal pricing, they would say, I want to be at Plains Cushing terminal. I think, ultimately, what we want to do is have the ability to have unequal pricing in the markets that are more challenging.

That's all I have. Thank you.

Thanks, John.

Your next question comes from the line of Barrett Blaschke from RBC Capital Markets. Please go ahead.

Hey, guys. Just kind of a quick question. You sort of see the Bakken continue to play, to build up and Keystone and then eventually Keystone XL to come on. How does that affect your ability to adjust your prices at Cushing and just sort of how does that affect your growth plans?

Our storage terminals?

Yes.

I think Keystone and Keystone XL are both positives. We're connected to Keystone with the only terminal connected to Keystone. The more volume that comes down to Keystone, means more volume through our terminal. So, whether it is Canadian or Bakken type of crude, at our terminal Cushing, I think it's beneficial.

Really I think everything else I had, has been asked, so thanks, guys. Thanks.

Your next question comes from the line of Michael Cerasoli from Goldman Sachs. Please go ahead.

All right. Thanks for taking my question. Can you perhaps define your Bakken opportunity set? The only reason I ask is, correct me if I'm wrong, I didn't see any identified projects from you guys in the region. Maybe just an update on your potential Bakken pipeline project.

We have a couple things going on in Bakken. Nexen had a pipeline that was -- the [Robinson like] pipeline, there's a little expansion of that pipeline going on. It should be completed first quarter. We've got our Bakken project that we announced. We are still pushing forward on it. We are just not at a stage where we are ready to say, here's the capital committed. We've got all the pieces put together. There are some moving parts to that. Certainly, something that we expect to deploy some capital in that area.

Yes, Michael, I guess if your question is, is it in the budget. The answer is, no, it is not. It is one that we hope to, with additional clarity on some of the discussion we're having and some commitments, I would hope by the time we get done with 2011, we are not talking about a $550 million capital program but something north of $650 million, $700 million, $750 million kind of range, which would reflect either the Bakken or some other projects that we are working on.

These are just ones we have real high confidence level that we are going to execute and can give our investors enough comfort that we are going to take a great 2010 as a very solid if not great 2011 and set up 2012 . If we start to add these other projects to it, we are going to, basically, be reinforcing 2012 and pushing it into '13 which is what every MLPs dream is, is to have visibility to control of your destiny through distribution growth, without having to rely on somebody else selling you an asset. If you take those all and stack it up and put acquisitions on top of it, we feel pretty compelled. It's a pretty compelling story.

That's helpful, is the obstacle of securing these projects, there's just a lot of other infrastructure projects out there right now with the trans Canada, the Enbridge or is it more just kind of making sure everything kind of gets in place? I guess it's more of a negotiating thing at this point.

There's always a bid and ask. Then there's always some chatter about what, is this project as good or better, or is it slightly inferior to other projects. So, I would say you are correct. It is a little bit of everything. There's a bid and ask, and then there's also, other projects that may come about. But if they don't come about, then ours looks like it is really a great certainty. One of the things about our projects that we really like is by the time to pull the trigger to the time it's in service, it's a very definable period. It's not going to be the total solution. I think our total volume capacity is in the 50,000 to 70,000 barrels a day. But if somebody waits three months too late, they'll be wishing that they'd committed earlier because those differentials will blow way the heck out.

Right okay. That's also helpful. And in my final question is on asset acquisitions. Is the expectation that you'll stay in your comfort zone? Could we see you guys move up and down the chain in any sort of way, both on the gas side and on the oil side?

I can make a couple definitive statements. You will not see us on the refinery. And then on the gas side, I think, right now we've got so much on our plate. All we have to do right now to achieve success is just execute. But we will look at acquisitions and be very selective.

Our focus right now, Michael, is on incremental storage opportunities. I think if you asked me in 10 years from now and we look back what does P&G look like, I think we are probably going to own some long shipping pipelines. But you really can't force those opportunities. You have to be able to react to it.

We've put ourselves in position with a pure gas vehicle and with what we think are going to be the premier storage facilities in the US. And therefore, should have a low-risk growth and a low cost of capital to be able to compete for those pipeline opportunities when they do come up. Where as we could not have at PAA without having taken the steps simply because we wouldn't have the synergies and we wouldn't have the cost of capital. So if you're asking me about the next 12 to 18 months, I'd probably say you might be disappointed if you expect us to make a pipeline acquisition in that. If you ask me if we don't make one in the next 10 years, I'm going to be disappointed.

That's also helpful. Thanks again.

Thank you.

Your next question comes from the line of Selman Akyol from Stifel Nicolaus.

Congratulations on a nice quarter. A couple quick questions. As it relates to the segment profit per barrel in facilities in your guidance there, can you talk a little bit about the pricing environment you are seeing there?

Yes, it is trending up a little bit. Part of it is asset mix. As we bring on, we are converting, obviously, some of our gas storage into BOE equivalent and it's transferring pretty positively. Part of it is, we do have some leases that are being renewed at higher rates. And part of it is, just some of the new construction we have done. We have tried to tie it to a rate of return and it's attractive there as well. So it's not any one element. It's just a combination of things. But they are all pretty solid fundamental.

Got you. And then when you see people renewing, are they wanting to renew for longer terms as well?

We've been pushing for longer-term renewals. We certainly think there is some risk in certain areas of an overbuild. It's just our business is no different than anybody else's. Inevitably, it goes in cycles. So we've been pushing. I think at Cushing we are longer-term. We've got probably 90% leased up there. Anywhere from three to seven-year leases, or maybe a little bit longer in a couple areas.

Great. Turning to PNG, if you can just help me understand the dynamics on the storage related costs. It looks like they are coming down in 2011, despite having, certainly, more capacity.

Yes. What we have right now and we mentioned it a little bit in the script, the expansion we are getting, our caverns are down, they are down to drill. We are in the leaching mode, very efficient. Greg has talked about it previously with the leaching facility at Pine Prairie, and then through smugging over at Southern Pine. We will be able to add that incremental capacity at a very low cost, so that is what is driving those numbers down. The drilling exposure, those costs are really all done. It's more about just leaching out the caverns now.

And what I think Dean was addressing, our operated assets, our owned assets, when he's referring to that, if you're referring to the storage related costs that are on the P&L, storage related costs, those are third-party costs. Part of that is a function of, we lease at Blue Water, for example, I think we actually have less volume that we are leasing there. Part of that is, simply the decrease there. Part of that is, when we really are active using those facilities, we pay incremental or ancillary costs, just like people pay us when they use ours, so we don't always forecast those because those are really market opportunities. When you incur those costs, you have incremental margins. It's a combination of less third-party leases at the facilities we don't own, and then just a lower projected level of activity, because we don't know what is actually going to happen until we get there.

Got you. And that's very helpful. And then the last part of this. You got 100% of your capacity leased for first quarter, and then as you look out, you still have 10% to 15%. Is that what we should think in terms of the opportunity for the optimization group?

The answer is, yes, that's the inventory that we had to work with today. Part of that is a function of back to the bid ask. If the answer is, the bids that we get to lease that are not what we think we can make on our own, then we are going to keep that. If the answer is somebody comes in and makes us an attractive offer and we say, look, we will just build more. And that's exactly what we have done in Cushing. We have been chasing that animal for a while trying to get [John Bomberg] and his group back some more lease because we leased it at an attractive rate. Every time we get something else built, they lease it. We would hope to get into that situation at Pine Prairie and Southern Pines and in other areas.

But right now, that's the total inventory we have to work with. I think we are actually targeting to have, ultimately, we would like to have somewhere in the neighborhood of three Bcf in their hands, and that can move a little bit up or down. But it's going to be a function of market factors.

Thank you very much.

Thanks, Selman.

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All right. Thanks, again, to everybody for joining us on the call. Again, we truly do appreciate your support and trust and investing in PAA and PNG. Thank you.

That does conclude our conference for today. Thank you for your participation and for using the AT&T Executive Teleconference Service.