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Executives

Dean Liollio - President of PNGS GP LLC and Director of PNGS GP LLC

Greg Armstrong - Chairman of Plains All American GP LLC and Chief Executive Officer of Plains All American GP LLC

Al Swanson - Chief Financial Officer of Plains All American GP LLC and Senior Vice President of Plains All American GP LLC

Harry Pefanis - Vice Chairman of PNGS GP LLC

Analysts

S. Ross Payne

Jeremy Tonet - UBS Investment Bank

Brian Zarahn - Barclays Capital

Darren Horowitz - Raymond James & Associates

Michael Cerasoli - Goldman Sachs Group Inc.

John Edwards - Morgan Keegan & Company, Inc.

Gabriel Moreen - BofA Merrill Lynch

Barrett Blaschke - RBC Capital Markets, LLC

Michael Blum - Wells Fargo Securities, LLC

Selman Akyol - Stifel, Nicolaus & Co., Inc.

Plains All American Pipeline, L.P. (PAA) Q4 2010 Earnings Call February 10, 2011 11:00 AM ET

Operator

Ladies and gentlemen, thank you for standing by, and welcome to the Plains All American and PAA Natural Gas Fourth Quarter Earnings Call. [Operator Instructions] Also, I would like to welcome 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 partnerships, outlook for future, which may include words such as believe, estimate, expect, anticipate or other words that indicate a forward view.

The partnership intends to avail themselves of a Safe Harbor precept 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 company's 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 partnerships encourage you to visit their website at www.paalp.com and www.pnglp.com and in particular, the section entitled non-GAAP Reconciliation, which presents certain commonly used non-GAAP financial measures such as EBIT and EBITDA, which may be used here in the prepared remarks or in the Q&A session. This section of the website also reconciles the non-GAAP financial measures to the most directly comparable partnership reported financial information. Any reference during today's call to adjusted EBITDA, adjusted net income and the like is a reference to the financial measures, excluding the effect of selected items impacting comparability. Also, for PAA, all references to net income are reference 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 of PAA and PNG.

I will now turn the conference over to your host, Greg Armstrong. Please go ahead.

Greg Armstrong

Thank you, Caroline. 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, and I wanted to take the opportunity to let you know that Dan Bach will be joining our Investor Relations effort as Manager, Investor Relations reporting to Roy. Dan has been with PAA since 2004 and he is 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 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 10, 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 overperformance. So overall, it was a very solid year of blocking and tackling.

As shown on Slide 3 for 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 in last year, those metrics were up 17%, 26% and 24%, respectively. PAA's fourth quarter results were driven by in-line performance in the Transportation segment and overperformance in the Facilities and the Supply and Logistics segments.

Slide 4 graphically represent this quarter's aggregate performance versus guidance highlighting the fact that we have now delivered 36 consecutive quarters where results 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 5, 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 per 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 in 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'll wrap up with a few brief comments and discuss PAA's 2011 distribution guidance.

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

Harry Pefanis

Thanks, Greg. I'll now review our fourth quarter operating results compared to the midpoint of our guidance issued on November 3, 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 6, 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 $141 million guidance midpoint, but was within the guidance range 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 overperformance 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 profit 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 overperformance 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 volumes, crude oil lease gathering purchases and waterborne 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 estimates.

Let me now move to Slide 7 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 profit 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'll note that we previously referred to this area in 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 system 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 earlier commitments to a competing pipeline project in the area. Over the next few years, we expect to see volumes on the Rainbow system increase as production from the region increases.

Facilities 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 and 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 for 2011 is expected to increase at 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 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 waterborne foreign crude imports. Increases in our crude oil lease gathering segment -- or 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 expectations that we will continue to see market conditions that are not favorable to the movement of such crude to the U.S.

Moving onto our capital program, excluding acquisitions, we invested approximately $355 million in 2010, including approximately $10 million for base gas at PNG. It's about $5 million under the $360 million of capital program we announced in the beginning of 2010, and was approximately $25 million below our updated forecast from last quarter. Weather delays and delays of material 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 have established a $550 million expansion capital program for 2011, representing $195 million increase over our 2010 capital program. Slide 8 outlines the larger projects included in this 2011 capital program. We have approximately $103 million of capital attributable to PNG projects, they are primarily related to cavern well expansions that Dean will cover.

At Cushing, we have three projects in process that, in total, we added approximately 4.3 million barrels of storage capacity to our facility by the end of 2011. I'll 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, the 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 [Occidental Petroleum] will have an initial design capacity of over 10,000 barrels a day in LPG and will involve making storage and rail enhancement to our Shafter facility. The project is expected to be placed into service in the third quarter of 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, Arcadia 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 of 2011. We estimate our 2011 investment will be $36 million.

We are also moving forward with the construction of an LPG rail storage and transloading facility to be located near Stanley, North Dakota. So the capital cost is approximately $25 million and 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 9. 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. And while we're not in the 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 resource play 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 of 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 asset acquisitions.

I'll now turn the call over to Dean for an update on our gas storage activities.

Dean Liollio

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 and 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's 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/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 contract for physical delivery at Pine Prairie. The contract began trading in February on the NYMEX floor and electronically to 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 U.S. last week. During that period, we set new records for daily withdrawal, 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 in the pipelines for transportation. As a result, the amount of gas we can withdraw from that storage reservoir has been temporarily 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 demands, we expect to be able to continue to meet our obligations throughout the remainder of the withdrawal season, which typically ends March 31. 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 operation 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 the 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 a 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 the prior conference call is the $4 million purchase price reduction for estimated cost to replace an existing wellhead seal and make other modifications and upgrades to the wellhead assembly of Cavern Well #3 after closing. These modifications are similar to modifications we made last year on Cavern Well #3 at 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 of 2011. Selected portions of this guidance are summarized on Slide 12. Our guidance for 2011 forecasted 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 in adjusted EBITDA is: one, the addition of Southern Pines; two, the full year realization in 2011 of capacity at Pine Prairie brought on line in the second quarter of 2010; and three, the incremental Pine Prairie capacity to be brought on line 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 yearend capacity of 50 Bcf. These volume estimated 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 Cavern Well's #4 and #5, the conversion of Cavern Well #4 to storage service and various Fill/Dewater activities. Approximately $30 million is related to Southern Pines and includes the completion of drilling operations on Cavern Well #4 and ongoing space creation in Cavern Wells #1, #2 and #3 through primary leaching activities, Fill/Dewater activities and solution mining under gas or smugging. 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 arrangement 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 in 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 of 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 to: 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 we'll continue to be very selective.

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

Al Swanson

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 targets. In recognition of both an upward shift in acquisition multiple 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 3.5x to 4.0x. Previously, we were targeting a 3.5x 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 to liquidity I mentioned include 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 balances 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 receivables. 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 linefill 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 3.8x, and our adjusted EBITDA-to-interest-coverage ratio was 5x.

With respect to PNG's capitalization, PNG exited the year with the debt-to-capitalization ratio of 26%, adjusted EBITDA to interest coverage of 20.3x and debt-to-adjusted-EBITDA ratio of 4.2x. Subject to covenant compliance, PNG's committed liquidity was $140 million at December 31.

Since the third quarter earnings call, both PAA and PNG conducted quite 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' over-allotment option. It totaled net proceeds of $296 million, which include the general partner's 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 notes offering for net proceeds of $592 million. Proceeds or liquidity from these three financings totaled $1.4 billion.

Of the approximate $900 million of cash proceeds from the equity and senior note offering, $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 will mature 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 the financing activities, PAA's consolidated long-term debt primarily consists of senior unsecured notes and including balances outstanding on the revolving credit facilities has an average tenor of approximately 10 years. We have no maturities until September 2012 and 90% of our long-term debt is fixed, and we have an average rate of 5.9%.

PNG was also quite active in its financing activity. In connection with its acquisition of Southern Pine, 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 cost. 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 so 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 included 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 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 their 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 is associated with our Class B units in our general partner, for which PAA bears none of the cost, but is required to be pushed down to expense in the 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 point of our 2011 guidance, which excludes 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% 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 result 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, our representative quarterly profile of our 2011 guidance is included in the inset in the upper right side of the Slide 20.

The midpoint of the 2011 guidance furnished yesterday is approximately $80 million above the preliminary 2011 guidance we've provided in November 2010. The majority of this increase is attributable to the impact of Nexen and Southern Pines acquisitions that were announced and closed after we've provided the 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 planning 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 U.S., we anticipate suppressed waterborne imports of foreign crude oil and that foreign quality differentials will remain in a tight range. We're 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 result and our capital structure.

Finally, I just want to comment that we did complete tax restructuring with respect to our Canadian entity at the end of 2010, and the estimated impact of all of our Canadian entity 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 will 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.

Greg Armstrong

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: deliver baseline offering 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 the 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 distribution 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 and 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 of 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 quarter, typically the weakest quarters and distribution coverage can dip below 1:1 even though annual guidance supports a level above 1:1 for the whole year. As a result, we typically look at several quarters of expected performance and related coverage when 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 of observations with respect to why we think PAA represents an attractive investment opportunity that combines a low-risk business profile with an attractive total return. Over the last several years, PAA has placed a number of extreme realized micro and macro stressed 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 U.S. 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 those elements while 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 illustrated its commitment to maintaining a solid capital structure and strong liquidity that has an investment-grade profile.

We believe the combination of PAA's tested and proven low-risk business profile, attractive current yield and visible 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 investing in PAA and PNG and for the trust that you have placed with us. We look forward to updating on our activities during our first quarter call in early May. And at this time, we would open the call up for questions.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from the line of Michael Blum from Wells Fargo.

Michael Blum - Wells Fargo Securities, LLC

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 do you expect it to impact your business either to the positive or to the negative?

Dean Liollio

I think the impact would be less foreign crude moves into the U.S. Gulf Coast. We've got that segment of our business, we've got offsetting factors that's offset by more production in the U.S. that feeds to our U.S.-based pipeline systems and terminals.

Greg Armstrong

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

Michael Blum - Wells Fargo Securities, LLC

Now there's 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 crudes or anything of that nature? Do you expect to see that?

Greg Armstrong

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 calls go up. It gets hard to find more and more labor that has the skill sets, and therefore, you end up paying the premium for those that do and they pull up the whole wage scale. So the answer is yes, we do expect to see that happen.

Michael Blum - Wells Fargo Securities, LLC

Have you already baked that expectation into your CapEx budget?

Dean Liollio

Pretty much. I certainly can't forecast all of those dynamics as you put together capital program over a 12- to 18-month period, but we certainly try to. We're somewhat taking 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 the room for some slippage so that we make sure we still make a good return.

Michael Blum - Wells Fargo Securities, LLC

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

Al Swanson

Yes. And it's a little bit of when you look at kind of what we're seeing with acquisition multiples being one that 50-50 technically works when you're closer to 7x to 8x. And so we are looking at and now we have looked at a target, but then we really look at the actual cash flow from the asset we're acquiring and try to balance it to it, and what we're finding is that we really need to be at that 55%. And again, that's how we view at least that much. And so really what we've done is changed our target to equal what our practice has been.

Greg Armstrong

Michael, effectively, what's happened when we set our goals several years in certain of our metrics, a lot of our capital projects we might start in January and February, and they're 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, multibillion dollar projects. But we looked at, for example, 2011, I think if we took out all the capital program that we're planning on spending $550 million, I think the impact on 2011 was less than 2% or 3% of EBITDA. And so what that means is you just got a longer lead time on your balance sheet for some of these calls. And so I think it's prudent for us to do two things. One was to adjust the amount of equity and cash flow we're 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're moving to is widening that band out from 3.5% to 4%, which is really an acknowledgment of reality. We've been running about 3.8%. If we stop spending, we'll go back down to about 3.5% pretty quick. But we don't think we're going to stop spending. And if anything, we think our projects are having a little bit longer lead times. So it's just a recognition of the reality of the market. And if the right agencies are listening, I just want to make sure they know that we're doing all the prudent things.

Operator

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

Darren Horowitz - Raymond James & Associates

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

Greg Armstrong

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

Dean Liollio

Physically, it's not really moving any volume in that direction. You got rail or barge I guess only to get it there.

Darren Horowitz - Raymond James & Associates

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

Greg Armstrong

Well, I think what's going to happen is we haven't talked about all of pipeline projects that we have on the drawing board. But some things that have to happen to move more crude into an area that’s bought by all of us. 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 LOS mid-dollar pipeline. That pipeline's been full for quite some time. So you can't actually move from West Texas over that leak and also, basin, Ozark bring it over into the Wood River area. But Ozark has some limitations as well. So that's really a lot of thoughts are as how to get crude that used to move up a different corridor into an area that can source LOS type crudes.

Darren Horowitz - Raymond James & Associates

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

Greg Armstrong

Let me say this. We've got a $550 million capital program that does not include solutions to that, but we're working hard to try and make that $550 million bigger.

Dean Liollio

I think rail's going to be the shorter answer. The short term, there might be some rail move from the Eagle Ford to St. James but don't think that's really a solution.

Darren Horowitz - Raymond James & Associates

Switching gears. Dean, over to you. Just a quick comment on the spread environment between a lot of the outcast prices and the futures curve, and I fully appreciate that you all want to comment on specific Cavern pricing but how do you think about, from a big picture perspective, balancing the duration of contracts versus price? As you look to your new contracts going over, I recognize there's only 10% or 15% of capacity that's exposed in the near term. So it's really more of a question for your 2012 outlook when you have 25% of the capacity rolling off?

Dean Liollio

That's a good question, Darren. I'll try and 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're looking at their prices. I think what we see right now, spread's one component of it, but it's really how much flexibility do they want, how many times. We're seeing a little bit -- a lot of the customers wanting to go a little bit less on turn and a little bit less on the flexibility or the number of turns. So the volumes there, as we talk to them, it really gets down to what each particular customer desires. But generally, as the trend, that's what we're seeing out there right now.

Darren Horowitz - Raymond James & Associates

Just a big picture question. This builds off your comments about the potential for Pine Prairie to be a major marketing hub. As you all think about integrating the Southern Pines assets and the basal gas processing plant, how do you think longer term about leveraging that footprint to capture more value across the entire natural gas supply chain?

Dean Liollio

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 flexibility of moving the supply all over. To that aspect, big picture, clearly, Southern Pines is a great asset, particularly to market demand in the Southeast. Pine Prairie where it sits has market demand but great access to really all of the supply components of the industry right now. And then as we look out, we certainly have our eyes on storage and other market areas that we currently are not in. So from a big picture, when you put it all together and as we go forward, we'll look at leveraging those together, just on the points you mentioned.

Operator

The next question comes from the line of Brian Zarahn from Barclays Capital.

Brian Zarahn - Barclays Capital

You're expanding your base and pipe, can you talk about what you're seeing in the Permian? And if it's possible to give a little more color on what opportunities you see to increase takeaway capacity in the region?

Greg Armstrong

There's a lot of activity, as you certainly know in the Permian Basin. We currently have takeaway capacity on Basin. Basin is not full, but we are looking forward. And as we see increasing production, and we're trying to start to get out ahead of the curve and make sure that Basin have enough takeaway capacity. 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. Based on the pipeline, we were about 120,000 barrels a day, 100,000 to 120,000 barrels a day. It has capacity, so we're looking at alternatives that de-bottleneck the connecting carriers to increase movement out of Permian Basin as well. We've got a number of projects we're looking at in West Texas to expand pipelines, connect to our existing infrastructure. We think we're very well situated; we have that asset presence in the Permian Basin and certainly expect to spend a fair amount of capital there this year.

Brian Zarahn - Barclays Capital

And turning to the recently announced Shafter expansion project, do you see other near-term opportunities with Occi?

Dean Liollio

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

Greg Armstrong

Clearly, Brian, we get the question probably every other quarter, at least, we're 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, you look at our footprint, West Texas and now on the Rockies and then 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 has shown to be a very savvy investor. So hopefully, this is the first of many opportunities yet to come.

Brian Zarahn - Barclays Capital

The final question is just given the incident at Bluewater and the recent incident at a competitor facility in Mont Belvieu, just rolling it in together with other sort of high media attention energy incidences for pipelines and other spills. Can you talk about what you're doing to you review all your integrity of your assets and any broader impacts on costs going forward and all this increase, this recent events increased regulatory scrutiny?

Greg Armstrong

I think the question of regulatory scrutiny or increased regulatory scrutiny is not a question. I think it's just a fact. It is there and it's going to be there. I don't know that we, "do anything different" because we've been for several years and we've been disclosing in our 10-Ks and other areas that we've been well ahead I think of what we think industry or regulatory demands are going to be, whether they're required by jurisdictional pipes or non-jurisdictional. And do we basically -- we were trying really hard before do we try even harder? I think the answer is absolutely, but it's not a major step change for us because we were already pretty intense on that. I think we have estimated cash here we spent -- hereby looks at maintenance capital, we expensed a tremendous amount through our P&L activity. We spent on routine maintenance and upgrade and integrity management well over $100 million, I believe. So Brian, we're pretty aggressive in that area to try to be ahead of the curve. I don't think 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 not just a question, that's an answer.

Operator

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

Jeremy Tonet - UBS Investment Bank

I just want 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?

Greg Armstrong

I think there's certainly some. Yes, I think what we have right now when we bought CV MAX two years ago. What we got is we got a group of people that really, really know processing inside and out and efficiency. And I think there's a tremendous opportunity with all of the drilling that's 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're building there is worth $150 million a day. And its efficiency, I think, is almost unparalleled. And I think with the liquids differential relative to gas today and what's likely to continue to happen, I think there will be a significant numbers of opportunities there, and within our organization, what we referred to as CV MAX, which is the Hellion subsidiary they say a lot of opportunities to be able to take home multiple projects if they were out on their own, which they were at one point in time, it was all project financing stuff. So we're starting to see an increased velocity of that over time.

Jeremy Tonet - UBS Investment Bank

In regards to 2011 guidance, it seems with the LPG volumes in the Facilities segment appears to be decreasing year-on-year while in the Supply and Logistics segment, the LPG volumes look to be increasing. Could you give a little color on what's driving this?

Greg Armstrong

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

Harry Pefanis

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

Operator

Next question comes from the line of Gabe Moreen from Bank of America.

Gabriel Moreen - BofA Merrill Lynch

I hate to harp on California again, but I'll do it and see if I can fish for some volume guidance on line, 632,000 it seems like that is trough, so you're not expecting much growth in 2011. Is that just 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?

Greg Armstrong

I don't 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 got to look at increasing onshore volumes with declining offshore volumes when you're looking at what's actually going to move on the pipeline from Bakersfield even north to San Francisco or south to L.A. I think our view is that probably volume south into L.A. are going to be at the same level that they're at right now, but I'm not expecting a whole lot of increase or decrease.

Gabriel Moreen - BofA Merrill Lynch

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

Greg Armstrong

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'd probably consider doing joint ventures with. And certainly, Gabe, there has been some preliminary discussions in different areas as people evaluate all potential alternatives to try and come up with the best answer. With respect to when you talk about larger pipeline projects, again, we're not talking about multibillion, multiyear 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 take probably, Harry?

Harry Pefanis

18 to 24 months.

Greg Armstrong

18 to 24 months. So there's some exposure there, Gabe, but not of the magnitude perhaps that we've seen on some of these other projects when you had two- to three-year construction periods. A couple of billion dollars numbers have turned into a couple of billion dollars plus numbers. I don't think we're facing that. And in almost all the case, we were talking about something big enough there. We are talking about some participation protection in our execution risk on that. You can't lay out 100% of it, but you want to make sure you don't fix your revenues then have all your cost flow and end up having your margin eroded.

Dean Liollio

JVs are probably more in the context of opportunities where they're synergistic; they make sense as opposed to trying to lay off some of our capital exposure or risks.

Gabriel Moreen - BofA Merrill Lynch

In terms of the guidance on profit per barrel at Supply and Logistics for the first quarter being I think $0.98 versus up $0.49 you realize in the fourth quarter given that, if anything, differentials and contangos are even better in the first quarter thus far. In the fourth year, is LPG opportunities or is it that it's just not March 31 yet?

Greg Armstrong

Well, we had some unique opportunities in the fourth quarter. Obviously, if we did know they were going to transpire, our guidance would've been higher. They were non-repeating where you're able to put some crude in the inventory because differentials do a lot. Look at what happened in Canada. Differentials got wide, came in, got wide again. So velocity and some of the volume we had in tankage both in the U.S. and Canada that isn't necessarily repetitive. And when you put that gain against the metrics in the volume category, it adds a lot of margin. Like I said, that's not necessarily repeatable, but we're definitely try to capture those opportunities when they arise.

Dean Liollio

Under promise, over perform.

Operator

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

S. Ross Payne

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's your long-term goal to get back to that range, correct?

Harry Pefanis

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

Greg Armstrong

Ross, we run our models, and again part of this is trying to make sure that we communicate what we're going to do and then do it and not have a metric out there that we're constantly not getting to and have people think that it's not real. If we quit spending our growth capital tomorrow and we couldn't make an acquisitions, we'll be at 3.5% and go sub-3.5% pretty quick. But what we've seen now as we've institutionalized the aggregate level of acquisitions, it's probably in the $300 million to $500 million year range and our capital program building up. And that comes with tremendous economics, but it's always on a delayed basis. And so we felt like it was appropriate to boost the amount of equity that we're funding those projects with, then also to recognize that as you pointed out, as we do those, it's going to put us closer to the 3.8%, 3.9% possibly a 4% number. And so we just recognize that as a range. And the wording that we've used for our policy is that we will average within that range. Clearly, if we go outside of it, you're going to see us hustle in pretty quick. We don't want to jeopardize the upward momentum we have on our rating. We think we're at least one click, if not two clicks below where we need to be. And this is basically a way of acknowledging that we're still going to maintain discipline even as we continue to build the company. And so I'm hopeful that this is viewed very much as a positive recognition where we see some of our peers, our other competitors, they may have a target but they're never there, and it seems that you have basically one or two, realistic.

Operator

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

John Edwards - Morgan Keegan & Company, Inc.

Just with all the unusually cold weather we've been having, I'm just curious what impacts you're seeing to natural gas storage pricing, if any?

Dean Liollio

John, at least when you look at it right now, I think today, it's supposed to be the coldest day across the nation on average. Next week, you're going to have the warmest day this winter on the nation. I think when you look out there, you're not seeing the front end move up. Actually, it's moving at the opposite direction. So as far as the pricing you're seeing, it seems to be going, people are anticipating I guess supply be strong. And as far as right now what's 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's in the low $4 range.

Greg Armstrong

John, if I may just comment and this kind of goes back to Darren Horowitz' question too, when you look at our leasing decisions, I think we’ve given ourselves with our profile leases that we have relative to total capacity, a lot of times to be patient. I think time is on our side for the following reasons. I think as we've seen this cold snaps come through here, any facility can operate probably in the milk toast kind of market. What we're seeing right now is we've had draws of up to 1.3 Bcf per day for several days. That's really hard on facility, and our goal if you recall from a couple of conference calls ago was 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're seeing and some of the competing facilities where they may have perhaps established the nameplate that may be above their actual physical capacity. And so I think when it comes to time for renewals, one of the things that's going to happen in the next 24 months is that people are going to say, well, you may tell me that I can do, but if you force majeure, you have some operating limitation on me. It doesn't do any good to have this horsepower and not being able to use it. So ultimately, right now, our goal is to try and make sure we never have to tell our customers no and that we meet our obligations. And we've done that. At Pine Prairie, we intend to do the same philosophy. At Southern Pines, we had to try and make sure we do that. And even with Bluewater, as we've had the challenges we have there, clearly, we didn't expect that but we've been able to meet all of those obligations and we want to continue to do that. So I think ultimately, just like we have at Cushing, I think in Cushing, we have the most versatile, the most high-performance facility up there and I think if you gave anybody equal pricing, they'd 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.

Operator

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

Barrett Blaschke - RBC Capital Markets, LLC

Just kind of a quick question as you see the Bakken continue to play, to build up and Keystone and then eventually Keystone excel to come on, how does that affect your ability to adjust your prices at Cushing and how did that affect your growth plans?

Greg Armstrong

In our storage terminals?

Barrett Blaschke - RBC Capital Markets, LLC

Yes.

Greg Armstrong

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

Operator

The next question comes from the line of Michael Cerasoli from Goldman Sachs.

Michael Cerasoli - Goldman Sachs Group Inc.

Can you perhaps define your Bakken opportunity set? And the only reason I asked is, correct me if I'm wrong, I haven't seen the identified projects from you guys in the region. Maybe just an update on your potential Bakken pipeline project?

Dean Liollio

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

Greg Armstrong

Michael, I missed your question is, is it in the budget. The answer is no. It's not. It is one that we hope to with additional priority on some of the discussions we're having and some commitments. I would hope by the time we get done with 2011, we're not talking about a $550 million capital program but something north of $657 million, $700 million, $750 million kind of range, which would reflect either the Bakken or some other projects that we're working on. These are just ones that we have real high confidence level that we're going to execute and can give our investors enough comfort that they're going to say a great 2010 as a very solid, if not great, 2011 and set up 2012. If we start adding these other projects to it, we're going to basically be reinforcing 2012 and push it into '13, which is what every MLP's dream is, is to have visibility of controlling of your own destiny through distribution growth without having to rely on somebody else selling on assets. If you take those all, stack it up and you put acquisitions on top of it, we feel pretty compelled. It's a pretty compelling story.

Michael Cerasoli - Goldman Sachs Group Inc.

Is the obstacle that’s securing these projects -- because there's just a lot of other infrastructure projects out there now with the TransCanada, the Enbridge or is it more just making sure everything kind of gets in place? I guess it's more just a negotiating thing at this point?

Greg Armstrong

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

Michael Cerasoli - Goldman Sachs Group Inc.

And then my final question is just 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 the oil side?

Greg Armstrong

I can make a couple of definitive statements. You will not see us on the refinery. And on the gas side, I think right now, as Dean said, we've got so much on our plate. All we have to do right now to achieve success is just to execute. So we'll look at acquisitions. We've been very selective. Our focus right now, Michael, is on incremental storage opportunities. I think if you ask me in 10 years from now and we look back, what does PNG look like? I think we're probably going to own some long shipping pipelines. But you really can't force those opportunities yet 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 familiar storage facilities the U.S. 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. We could not have PAA without taking the step 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 on that. If you ask me, if we don't make one in the next 10 years, I'm going to be disappointed.

Operator

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

Selman Akyol - Stifel, Nicolaus & Co., Inc.

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're seeing there?

Greg Armstrong

It's trimming up a little bit. Part of it is asset mix as we bring on -- we're converting obviously some of our gas storage into a 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 some of the new construction we've done, we've tried to tie it to a regular return and it's attractive there as well. So it's not any one element. It's just a combination of things, but they're all pretty solid fundamental.

Selman Akyol - Stifel, Nicolaus & Co., Inc.

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

Greg Armstrong

We've been pushing for longer-term renewals. We certainly think there is some risk in certain areas of an overbuild. Our business is no different than anybody else's. Inevitably, it goes in cycles, and so we've been pushing. I think in Cushing, we're longer term. We've got probably 90%, Harry, leased up there, and anywhere from three to seven-year leases and maybe a little bit longer in a couple of areas.

Selman Akyol - Stifel, Nicolaus & Co., Inc.

Turning to PNG and you can just help me understand the dynamics on the storage related cost. It looks like they're coming down in 2011 despite having certainly more capacity?

Harry Pefanis

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

Greg Armstrong

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

Selman Akyol - Stifel, Nicolaus & Co., Inc.

I guess you got 100% of your capacity lease for first quarter. And then as you look out, you still have 10% to 15%. Is that was we should think in terms of the opportunity for the optimization group?

Greg Armstrong

The answer is yes, that's the inventory that we have 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 that we're going to keep that. If the answer is somebody comes in and makes us an attractive offer and we say look, we'll just build more. And that's exactly what we've done at Cushing. We've been chasing that animal for a while trying to get John VonBerg and his group to have some more lease because we've leased it at an attractive rate. Every time we get something else built, they'd lease it. We would hope to get into that situation at Pine Prairie and Southern Pines and other areas. But yes, right now that's the total inventory we have to work with. And I think we're actually targeting to have ultimately, we'd like to have somewhere in the neighborhood of 3 Bcf in their hands, and that can move a little bit up, a little bit now. But again it's going to be a function of market factors.

Operator

And there's no further questions in queue. Please continue.

Greg Armstrong

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

Operator

That does conclude our conference for today. We thank you for your participation and for using AT&T Executive Teleconference Service. You may now disconnect.

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