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Plains All American Pipeline, L.P. (NYSE:PAA)

Q1 2011 Earnings Call

May 05, 2011 11:00 am ET

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

Dan Bach -

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

Harry Pefanis - Vice Chairman of PNGS GP LLC

Analysts

Bernard Colson - Oppenheimer & Co. Inc.

John Edwards - Morgan Keegan & Company, Inc.

Darren Horowitz - Raymond James & Associates, Inc.

Operator

Ladies and gentlemen, thank you for standing by, and welcome to the PAA and PNG First Quarter Earnings Conference Call. [Operator Instructions] As a reminder, this conference is being recorded. I would now like to turn the conference over to Mr. Dan Bach. Please go ahead.

Dan Bach

Good morning. My name is Dan Bach, Manager of Investor Relations. I want to welcome you to Plains All American Pipeline and PAA Natural Gas Storage's First Quarter Results Conference Call. Throughout the call, we may reference the companies by their respective New York Stock Exchange ticker symbols of PAA, or Plains All American Pipeline and PNG, for PAA Natural Gas Storage.

During today's call, in addition to reviewing the results of the prior period, we will provide forward-looking comments on the partnership's outlook for the future, which may include words such as believe, estimate, expect, anticipate or other words that indicate a forward view.

The partnerships intend to avail themselves of applicable safe harbor precepts and direct you to the risks and warnings set forth in the partnership's most recently filed prospectus, 10-K, 10-Q, 8-K and other current and future filings with the Securities and Exchange Commission.

In addition, we encourage you to visit our website at www.paalp.com, and www.pnglp.com, and in particular, the sections entitled Non-GAAP Reconciliations, which presents certain commonly used non-GAAP financial measures such as EBIT and EBITDA, which may be used here today 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 GAAP financial measures, and includes a table of selected items that impact comparability with respect to the partnership's recorded financial information. Any reference during today's call to adjusted EBITDA, adjusted net income and the like, is a reference to the financial measure, excluding the effect of selected 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 of PAA and PNG.

Prior to turning the call over to Greg, I want to mention that we'll be holding our annual Analyst and Investor Meeting on Thursday, June 9, in downtown Houston. The meeting will begin with lunch at noon, followed by presentations from 1 to around 5:30. We intend to have several members of the management team present and available for questions.

If you have an interest in accounting and have not yet received materials on the meeting, please call either Roy Lamoreaux or myself.

I will now turn the call over to Greg.

Greg Armstrong

Thanks, Dan. Good morning and welcome to everyone. In addition to Harry, Dean, Al and Dan, we also have several other members of our management team present and available for the question-and-answer session. Roy Lamoureux, our Director of Investor Relations is out of the office today on location.

As a reminder, the slide presentation we will be referring to in this call is available on our websites, our 2 websites at www.paalp.com and www.pnglp.com. During today's call, we will discuss PAA's first quarter operating and financial results, our 2011 capital program and acquisition activities, our financial position and our updated guidance for the second quarter and remainder of 2011. In an abbreviated fashion, we will also address summary information for PAA Natural Gas storage or PNG.

As many of you are aware, PNG is a separate publicly-traded MLP, focused exclusively on the Natural Gas Storage business. PAA owns 100% of PNG's general partner and 62% interest in -- limited partner interest for an aggregate 64% ownership interest, and thus, we consolidate PNG into PAA's financial statements.

The primary purpose of today's call is to address our first quarter performance and our outlook for the rest of the year. However, late last week we experienced a release of oil from our Rainbow Pipe Line system in Canada. Before we discuss our quarterly results, I wanted to provide some comments in context for the Rainbow release, and thus enable us to remain focused on the primary purpose for today's call.

On Friday, April 29, we shut in the northern portion of the Rainbow Pipe Line after detecting a crude oil release at a point that is north of our Nempsee [ph] station. We immediately notified the appropriate regulatory agencies, and lost a large very comprehensive response. The volume of the spill is currently estimated at approximately 4,500 cubic meters, which is approximately 28,000 barrels. Although this isn't immediately a significant volume, it was largely contained through our pipeline right of way, which substantially reduces the impact in cost of the response and the clean-up.

The current status is that the situation is stable and the oil is contained. We are still dealing with less than complete information, but because of the tight area of containment, and our team's comprehensive response, we currently estimate the total cost will be less than $25 million, a portion of which will likely be covered by insurance. That estimate will no doubt be refined, but based on the information we have and some reasonable assumptions, I believe it is in a reasonable neighborhood.

We are working closely with the Alberta Energy Resources Conservation Board, or ERCB, and the root cause of the release is continuing to be investigated. But all information we have indicates this is a singular failure and thus, it is not systemic and is not due to corrosion or stress corrosion cracking. As a result, repairs have been made, and we are waiting authorization to place the pipeline back in operation.

For those requiring more detailed information, we have set up a page on our website titled Rainbow Incident Information Page, which contains a lot of information that's updated periodically as conditions warrant.

You can access this information page by accessing our website at www.paalp.com, scrolling over the Environmental Health and Safety tab and clicking on Rainbow Incident. I think you will find information we have provided fairly comprehensive, including the initial report we provided via press release on Friday, April 29, and the last update we've provided yesterday afternoon, which did include photographs of the site. Over the last 7 days, we have provided a total of 14 information updates on the website during that 7-day period. I trust that my comments, plus the information provided on the website will provide you with the important information you need with respect to the impact on PAA.

Let me now shift to the discussion of our first quarter financial results we released yesterday after the market closed. We are very pleased with Plains All American's first quarter results. PAA delivered strong performance for the first quarter of 2011, exceeding the high-end of our adjusted EBITDA guidance by $38 million, which equates to $53 million above the midpoint of the guidance range.

As shown on Slide 3, for the first quarter of 2011, PAA reported EBITDA of $326 million and net income of $182 million, or $0.90 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 first quarter of 2011 was $348 million and adjusted net income was $202 million, or $1.03 per diluted unit. Adjusted EBITDA, adjusted net income and adjusted net income per diluted unit for the first quarter of 2011 increased 28%, 37% and 34%, respectively over last year's first quarter.

PAA's results are driven by strong performance on all 3 segments, but the largest contributions in our performance is coming from the Supply and Logistics segment.

Slide 4 graphically represents this quarter's aggregate performance versus historical guidance, highlighting the fact that we have now delivered 37 consecutive quarters of results in line with or above guidance throughout a variety of energy market conditions.

Yesterday evening, we also furnished financial operating guidance for the second quarter, and increased our full-year 2011 guidance. Last month, PAA declared a 3.7% year-over-year increase in our run rate distribution to $3.88 per unit on an annualized basis.

As of the distribution payable next week, PAA will have increased its distribution in 26 out of the last 28 quarters, as well as in each of the past 7 quarters.

At the end of today's call, I will provide some additional comments on our outlook, and then open the call out for questions. But for now, let me turn the call over Harry.

Harry Pefanis

Thanks, Greg. I'll now review our first quarter operating results compared to the midpoint of our guidance issued on February 9, 2011. I'll discuss the operational assumptions used to generate our guidance for 2011. I'll discuss our expansion capital program and our acquisition activities.

Dean will cover the PNG specific information in a moment. As shown on Slide 5, adjusted segment profit for the Transportation segment was $143 million or $0.53 per barrel, which is in line with our guidance for the quarter. Volumes for the segment of approximately $3 million barrels per day were also in line with our guidance.

Adjusted segment profit for the Facilities segment was $87 million, or $0.37 per barrel, which total is about $13 million above the midpoint of our guidance. The primary drivers to the overall performance were the favorable performance of -- from PNG and the recognition of inventory gains associated with the annual proving of certain of our LPG storage captives.

Segment volumes were 77 million barrels, and they were also in line with our guidance. Adjusted segment profits of the Supply and Logistics segment was $117 million, or about $1.46 per barrel. The segment profit was about $38 million above the midpoint of our guidance. And during the quarter, the segment benefited from increased crude oil gathering volumes and increased optimization opportunities that were captured.

In addition, we're able to lower our minimum operating inventory requirements by approximately 190,000 barrels during the quarter, and the gain from the disposition of this inventory contributed to the over-performance in this segment.

Total volumes for the segment were in line with our guidance, however there were some ups and downs. Our least gathering volumes were approximately 23,000 barrels a day more than our guidance, while both waterborne foreign volumes and LPG volumes were lower than guidance by approximately 14,000 barrels and 4,000 barrels per day, respectively.

The lower waterborne cargo volumes are reflective of the increase of domestic production, and the wide WTI-Brent Differential. The lower LPG volumes were the result of warmer weather in some of our propane markets.

Maintenance capital expenditures were $24 million for the quarter. These costs were higher than our expected run rate, and primarily due to the timing of repairs and a couple of the lines that were smart break[ph].

We continue to expand our integrity management program beyond the regulatory requirements, and we're increasing our projected maintenance capital expenditures for 2011 by $5 million, to approximately $90 million for the year.

Now let me move on now to Slide 6 and review the operational assumptions used to generate the second quarter midpoint guidance, which was furnished in our Form 8-K last night.

For the Transportation segment, we expect volumes to average slightly over 3 million barrels per day, which is in line with the first quarter volumes, and segment profit of about $0.49 per barrel. Slightly lower than the first quarter, and it reflects the impact of our Rainbow Incident. Note that the second half of the year, a number of our insurance will by the FERC index that goes into effect July 1.

With Facility segment guidance assumes an average total capacity of 82 million barrels of oil equivalent, with segment profit per barrel of $0.35. The capacity increase are due to the weighted-average addition of approximately 16 BCF of additional soft Cavern capacity, which includes bringing Cavern #4 on at Pine Prairie, and recognizing the full quarter impact of the Southern Pines acquisition.

Supply and Logistics segment guidance, volumes are projected to average 850,000 barrels a day for the quarter, with the projected midpoint segment profit of $1.05 per barrel.

Compared to our first quarter results, both the volumes in segment profit reflect a positive impact of increasing volumes of the least gathering barrels, and then the decline -- a seasonal decline in our LPG activities.

Our 2011 capital program is being increased to $600 million includes -- and includes the 2 new projects. One of these projects we are very close to signing up, but not yet in a position to disclose specific details. In the second project, we can discuss some, but not all the specifics.

The second project was previously referred to as an undisclosed capital program, and it includes a 12-inch 20 [ph] pipeline system. This line will connect dedicated production from the Bones Spring's Avalon area into our basin pipeline systems, and will be in service by the end of this year.

Now for purpose of our CapEx table, we have combined this project with a $7 million expansion of our key [ph] system, which also extends into the Bone Spring's Avalon area, and we'll be in service in the third quarter of 2011.

In the Bakken area, we're expanding our route facility at Ross to handle crude oil as well as LPG. Costs for the crude oil portion of the project are expected to be an incremental $35 million, and this portion of the facility is expected to be in service in early 2012. This year, we expect to spend about $15 million advancing our Bakken north project as well.

We continue to be very active in the pursuit of incremental growth opportunities, both organic and acquisition, and we look forward to updating you on these activities as they materialize.

And with that, and I'll 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 review our first quarter operating and financial results, provide an update on operational activities at each of our assets, and share a few comments about our second quarter guidance and the outlook for the remainder of 2011.

As shown on Slide 9, PNG announced solid first quarter 2011 results, including adjusted EBITDA of $19.5 million, adjusted net income of $12.2 million, and adjusted net income per diluted unit of $0.20. Each of which reflect performance above the high-end of our guidance range. Relative to the midpoint of guidance, this over-performance is due to Hub Services and Firm Storage Services that were higher than forecast and slightly lower expenses. A portion of the higher Hub Services that's due to the accelerated realization of certain short-term opportunities that were previously forecasted for the last 9 months of the year. This timing adjustment has been factored into the guidance we issued yesterday evening.

Let me give you a quick update on our activities at each of our storage facilities. At Pine Prairie, we expect to place Cavern Well #4 into service later this month, with an initial working capacity of over 8 BCF, which is about 10% larger than previously anticipated. We intend to expand Cavern Well #4 to its current permitted capacity of 10 BCF that fill into our water operation, and subject to receiving approval of current permit applications, we anticipate increasing its capacity to as much as 12 BCF over the next several years.

With the addition of our fourth cavern, we have now increased Pine Prairie's total working capacity to just over 32 BCF, which is a 36% increase over our year-end storage capacity of 24 BCF.

Looking ahead to 2012, leaching operations on Cavern Well #5 at Pine Prairie are fully underway, and we remain on track to bring that Cavern into service during the second quarter of 2012. Over the next 12 months, we anticipate increasing working capacity by an additional 9 to 10 BCF, which would further increase the total working capacity at Pine Prairie by approximately 30%. Also at Pine Prairie, we have completed the installation and commissioning of 4 new electric compressors, and are nearing completion of a new connection to a new processing facility currently under construction.

Collectively, we believe these activities are consistent with our long-term objective to make Pine Prairie the Cushing equivalent of the Natural Gas sector. We believe our location, our current and future capability, and overall inter-connectivity were major factors in Pine Prairie being chosen as the delivery point for the physical NYMEX delivery contract we discussed on our prior call.

At Bluewater, we are on schedule to complete repairs prior to the 2011, 2012 winter withdrawal season on the gas-handling portion of our facility that received damage in early January. I believe it is notable that, although the property damage incidents, as discussed on our last call, occurred at the height of this past winter's withdrawal season, we were able to meet all of our customer needs and requests even during the coldest of conditions.

We closed the acquisition of the Southern Pines Energy Center in early February, and have substantially integrated this asset into our business. We will also complete drilling and begin leaching on the fourth Cavern at Southern Pines this quarter. We delayed the start of leaching Cavern Well #4 by approximately 60 days, while reentered a nearby abandoned E&P well, and converted it to monitor well and modified our Cavern design. We also entered into an agreement with the sellers regarding certain outstanding issues and purchase price adjustments, as well as the distribution of the remaining 5% of the purchase price, or $37.3 million, which would escrow it at closing.

As a result, we received approximately $10 million of the escrowed fund, and the balance was remitted to the sellers. The money we receive will be used to fund anticipated facility development and other related costs identified subsequent to closing. This agreement also included mutual releases of any existing and future claims.

Overall, the first 4 1/2 months of 2011 have been very active and very productive. As a result of the acquisition of Southern Pines and our ongoing expansion activities at all 3 facilities, since the end of 2010, we have increased PNG's total storage capacity by 60%, and more than doubled the amount of high-performance soft Cavern working capacity.

In the aggregate, our capital program remains generally on-budget and with the exception of the delay I mentioned on Cavern #4 at Southern Pines, we remain on time. As with any capital program, we have accelerated certain expenditures and delayed others, but we expect our overall net costs will be very close to the $103 million estimate provided at the beginning of the year.

Let me spend a few moments addressing PNG's overall contract position. Since our last call, we have increased our capacity under third-party contracts to approximately 95% for 2011-2012 storage season. This compares to the roughly 85% to 90% range discussed in our year-end conference call in February .

We have released the majority of the remaining storage capacity for the 2011-2012 storage season to PNG marketing, our commercial optimization company, which we established in late 2010. Because of significant portion of the revenues associated with the capacity leased to PNG marketing will be generated from calendar time spread, PNG will recognize most of the revenue from such capacity in the fourth quarter of 2011 and the first quarter of 2012, as opposed to ratably throughout the year, as is the case with storage capacity leased to third parties.

I would also note the remaining tenure of our storage capacity leased to third parties ranges from 1 to 10 years, with the weighted average remaining 10 or being slightly over 3 years.

Slide 10 provides a graphical representation of our cumulative contracts additions for the next several storage seasons. We believe our healthy level of contracted capacity provides us with solid visibility for our financial performance over the next several years, while the uncontracted portion of our capacity represents a manageable risk and provides a meaningful upside opportunity in the event of an improvement in market conditions.

As we have stated in prior conference calls, for competitive reasons, we will not comment on specific pricing levels or contracted volume. However, I will state that in general, the pricing levels associated with our leasing activity over the last several months reflect the softer market conditions that we discussed from several of our previous conference calls. The pricing of each deal will vary quite a bit depending on the level of service being provided, the term of the arrangement and other factors. That said, overall lease rates were down from levels entered into in early to mid-2010.

With respect to PNG specifically, these market conditions are incorporated into the guidance reflected in Slide 11. The guidance for the full year 2011 is essentially unchanged from our guidance provided in February, but does incorporate the acceleration of starting performances into the first quarter and the shift in expected optimization revenue to later in the year.

We continue to 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. To this end, we continue to target achieving a run rate distribution of $1.45 per unit by November of this year. I will now 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, and also provide comments on PAA's guidance for the second quarter and full year of 2011.

As summarized on Slide 12, PAA exited the first quarter of 2011 with solid capitalization, $2.2 billion of committed liquidity and credit metrics in line with our targets. At March 31, PAA's adjusted long-term debt to capitalization ratio was 45%, and our total debt to capitalization ratio was 50%. Our adjusted long-term debt balance was approximately $4.5 billion, which excludes $500 million of notes used to fund hedged inventories.

The total debt ratio includes $1 billion of adjusted short-term debt that supports our hedged inventory. This debt is essentially self liquidating from the cash proceeds when we sell the inventory. For reference, our short-term hedged inventory at March 31, was comprised of approximately 16 million barrels equivalent with an aggregate value of $1.4 billion.

In addition to these inventory volumes and values carried as a current asset, we also have approximately 13 million barrels equivalent of line sale and base gas carried as a long-term asset that has a historical book cost of $654 million. Our adjusted long-term debt to adjusted EBITDA ratio was 3.4x, and our adjusted interest-to-interest coverage ratio was 5.4x.

Included on Slide 13 as a condensed capitalization for PNG at March 31. PNG ended the first quarter with a debt to capitalization ratio of 24% and our debt to adjusted EBITDA ratio of 4x. Subject to covenant compliance, PNG's committed liquidity was $192 million at March 31. As a result, PNG is positioned to finance its projected organic growth capital for 2011 and the majority of 2012 without a need to access the capital market.

In early March, PAA completed an overnight public equity offering that resulted in the sale of 7.9 million units at a price of $64 per unit, for an all-in discount of 5%. Proceeds, including the 2% GP contribution, totaled just over $500 million. The proceeds of this offering were utilized to pay down our revolver. This equity offering further strengthens our capitalization and liquidity, and positions us well for potential incremental investment opportunities.

As we have discussed in the past, PAA has a financial growth strategy that embraces the belief that we will be successful in our efforts to grow, and that is prudent to finance that growth of the partnership when markets are favorable. This offering is very much in keeping with this long-term strategy.

As shown on Slide 14, PAA's consolidated long-term debt primarily consists of senior unsecured notes, and including the balances outstanding on revolving credit facilities has an average tenure of approximately 9 years. We have no maturities until September 2012, and approximately 90% of our long-term debt is fixed at an average rate of 5.9%.

I'll now move on to guidance. The high point of our second quarter and annual 2011 guidance, which excludes collected items impacting comparability between periods, are summarized on Slide 15. For more detailed information, please refer to the 8-K that we furnished last night.

We are forecasting adjusted EBITDA for the second quarter of 2011 to range from $290 million to $320 million, with adjusted net income attributable to Plains ranging from $145 million to $185 million, or $0.61 to $0.87 per diluted unit. The midpoint of our full year 2011 adjusted EBITDA guidance has been increased to $1.3 billion, and reflects an estimated 73% contribution from our fee-based segments which we consider a healthy percentage, given the very strong performance in our Supply and Logistics segment.

Before I turn the call over to Greg, I wanted to mention that we are currently in the process of our annual insurance renewal. The market for hurricane or maimed windstorm-related property damage coverage has remained difficult the last few years. This is not the case -- this is the case not only for high-risk assets in the Gulf of Mexico, but also for relatively low to moderate risk coastal assets like PAA.

The amount of coverage available has been limited and the cost of that coverage has been very high, with the combination of premiums and deductibles totaling 20% or more of the coverage limits. In the last 2 years, we have purchased a relatively small hurricane limit, $10 million to cover property and business interruptions with a view that the market would improve. This level of coverage was pretty much all that was reasonably available, and even this level of coverage had much stricter limitations in the insurance policies available prior to hurricanes Rita and Katrina.

Unfortunately, the market has not recovered, and we have decided not to purchase this coverage for 2011 and '12, and we'll self-insure this risk. For comparison purposes, the largest aggregate claims we have had from a single hurricane season was in 2005, and totaled $14 million. And based on the current terms of the market today, we would have had only net recoveries after premiums and deductibles of less than $3 million.

The majority of the damage we have experienced during these storms is related to storm surge in general, and in particular, water damage to our electrical control systems. As we repaired or rebuilt most of these assets, we modified many of our structures to elevate the more sensitive, electric control systems and assets. And thus, we believe our relative exposure has decreased. We intend to invest the un-voided insurance premium on an annual basis to continue to improve and protect our coastal assets from potential storm damage, as we believe that will offer a much higher return over time for our stakeholders, and help our ability to provide uninterrupted service to our customers.

One final point is that, this division does not affect our third-party liability insurance, which still covers hurricane-related liability claims, and we expect to renew our liability insurance tower at our historic levels. With that, I'll turn the call over to Greg

Greg Armstrong

Thanks, Al. As is apparent from our first quarter results, and the comments provided by Harry, Dean and Al, PAA is off to a strong start in 2011, and is well positioned to accomplish the 2011 goals we shared with you at the beginning of the year. These goals are listed on Slide 16.

Importantly, we believe that accomplishing these goals will set the stage for continued growth for 2012 and beyond.

Let me add a few comments regarding guidance for the balance of 2011, the impact of seasonality in market volatility and, in that context, our distribution growth. The midpoint of our updated guidance for 2011 reflects an increase of $75 million from $1.225 billion, to $1.3 billion.

A portion of the over-performance is related to the overall market structure and market volatility, and the fact that PAA's business model and our asset base provides us with opportunity to benefit from those conditions without exposing us to downside.

Those conditions of related opportunities are not one-time events, but they are also not very predictable. Irrespective of the favorable market conditions, a portion of the increased guidance for 2011 is associated with what we believe are sustainable increases in our baseline cash flows. Our second quarter guidance incorporates both increases in baseline cash flow, as well as the benefit of market opportunities that we have already locked in.

However, the market structure of the second half of the year shifted to a more moderate condition, and thus, we have included only minor contributions from favorable market conditions for the last 6 months of the year. Accordingly, if the market shifts back into a favorable structure and volatility continues, there is upside to our already increased guidance.

Let me now turn to distribution coverage and distribution growth. Our distribution coverage can vary quite a bit on a quarter-to-quarter basis. In a typical year, distribution coverage during the second and third quarters can dip below one-to-one, as a result of seasonality and related factors, even though the annual guidance supports a level above one-to-one for the whole year.

In the year such as the current one, repeatable but unpredictable opportunities related to volatility can provide distribution coverage as well above one-to-one in any quarter. And for example, distribution coverage in the first quarter of 2011 was nearly 130%. As a result, we typically look at a number of different factors we want to establish in our distribution level and associate distribution coverage, which includes a rolling 4-quarter period of expected performance and related coverage.

Our distribution growth decisions are generally not adversely influenced by seasonal variations, nor are they influenced by over-performance from favorable but unpredictable market conditions.

I will say, however, that if we realized an aggregate amount of $100 million of cash flow from favorable but unpredictable market conditions and we, in turn, invest that amount to free equity into a 15% rate of return capital projects, we will increase our repeatable baseline cash flows and predictable cash flows by $15 million per year, so it does have an impact.

As a result, these unpredictable contributions will affect our distribution growth over time.

Slide 17 provides a recap of PAA's 2011 implied distributable cash flow based on the midpoint of the guidance range that Al just discussed. Assuming midpoint achievement of our 2011 guidance and distribution growth goal, we will expect to generate distribution coverage for the year of around 111% to 112%, which gives effect to our March 2011 equity offering that we just completed.

Looking beyond 2011, we believe the increase in our baseline cash flows, combined with the incremental cash flows associated with the investments we are making in 2011, provide PAA and its unit holders with a fair level of visibility to support our multiple -- multi-year distribution growth target range for the next few years. Additionally, we remain disciplined, but also very active on the acquisition front. Based on our historical experiences, any such acquisitions would further enhance our visibility and our capacity for distribution growth over time. 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, provides 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 thank you for participating in today's call, for your investment in PAA and PNG, and for the trust that you have placed with us. We look forward to updating our activities during our second quarter call in early August. And operator, at this time, we'll open the call up for questions.

Question-and-Answer Session

Operator

[Operator Instructions] And our first question comes from the line of Darren Horowitz with Raymond James.

Darren Horowitz - Raymond James & Associates, Inc.

Greg, I've just got a couple of quick questions. The first, as it relates to PAA, with several recent announcements around a lot of crude oil and condensate volumes ramping out of areas like Eagle Ford and West Texas, and now as you guys mentioned, more and more capital going into the development of the Bone Spring's Avalon area, how do you see the market in and around St. James changing? I mean it would seem that you've got production volumes sufficient enough to underscore some producer commitments, for not only more tankage but also more distribution capacity?

Harry Pefanis

Well, this is Harry. I mean, I think given that the people are going to find ways to move crude over into the same trans areas as these projects develop. That's part of our Bakken North, if you look at it, it moves crude up Los [ph] and Enbridge and over to markets that are traditionally supplied by St. James by the volumes.

Greg Armstrong

Yes, I would say, Darren, specifically with respect to the two plays you mentioned, the Bone Springs, and the Eagle Ford. Clearly, we think one of the ways that for example, the Eagle Ford's crude will ultimately find markets perhaps as far east as St. James because it is light, and it will probably have to be put on the water to get there. So I think it's just a matter of time before you see those volumes actually start showing up in significant volume. And then ultimately, I think you're going to see more and more rail as short-term solutions until volumes get to a size that they could support significant commitments. There have been a few projects that had been discussed. One recently announced, the talk about moving crude from Cushing, which is where a lot of the West Texas crude would normally aggregate to the Gulf Coast. Those, I think, everybody would like to see more routes to the Gulf Coast, I think it's tougher to get those commitments than it seems.

Darren Horowitz - Raymond James & Associates, Inc.

I appreciate the color on that, Greg. Dean, just a quick one for you, and obviously with respect to the fact that you're not commenting on specific pricing levels or contracted volumes. But as you look forward, and you look at that 15% to 20% of 2012, 2013 capacity that you've got uncontracted, how do you balance when to lock in the forward curve, versus keeping that capacity open for optimization. I'm just trying to get a better feel for how you think about achieving certain spread thresholds relative to the timing of when you want to have that capacity firmed up.

Dean Liollio

Okay, let me take a shot, Darren. First of all, when it's still our philosophy to lease all the storage out to third parties, once we make a decision that we think our commercial group, internally can do better than that, they will take that in and basically, given that have a strategy of watching the market, I mean, continuously and then locking it in at a certain time. Without going into much detail, and I'm really not going to give too much color on this above that, it's really a case of just being on top of the market and really looking for opportunities. They're much smaller in case than they have been in the past, so you really have to be on top of it and watch it and pick your points where you think it's going to move. I mean given that, that's about as much color as I can give you on it.

Operator

Our next question comes from the line of Shawn Radtke with Oppenheimer.

Bernard Colson - Oppenheimer & Co. Inc.

It's actually Bernie Colson here from Oppenheimer. This is kind of a topic that's been discussed quite a bit, the Cushing storage situation and in light of the EPD-ETP pipeline announcement. My question is really, if you could provide us some more color about what really drives the fundamentals of demand for storage at Cushing? And what do you guys see as a longer term, I guess, value for that after the bottleneck gets released?

Greg Armstrong

Well, I think I'll take that in reverse order there, if I can. I think, Bernie, there's a lot of tankage that's being built in Cushing today, and probably over the last couple of years that really is kind of a sole-purpose tankage. It's purpose is to store oil primarily for financial arbitrage and not for operational utilization. And so I think over time, as these opportunities ebb and flow and they don't ever stay -- the nature of volatility is that it just doesn't stay in any one direction for an extended period of time. And so there's going to be volatility. I think you'll end up with tankage in Cushing than the aggregate, that's always referred to as whether it's $50 million per barrel or $60 million or $70 million, depending on where you're talking about working capacity or shale capacity. But you'll have two tiers of quality storage. The ones that has the highest value will be those that are cultured to the manifold systems and have multiple flexibility. And I can 't help but brag a little bit, when you look at Plains' tankage, we've got the ability -- we've got probably the most versatile manifold. We're connected to every significant pipeline coming into or going out of Cushing. We have dual header systems on there, so we can handle sweep and fire simultaneously. Yes, we can store, we can blend, we can segregate, we can do all that. Whereas if you end up with tankage that volumetrically may sound like a lot, but if it's at the end of a single line where you can either put only crude in or take it out. And there's not opportunities financially to take arbitrages, I think it has limited utilization. And so adding to that comment is the fact that 90% of our tankage that we have in Cushing, even though we're the largest or one of the largest, depending on which tanks are completed or not on a given day, 90% of ours are with true operational customers that are going to use it irrespectable, whether you're in a backwardated market or a containment market, because they needed to do all those functions that I've mentioned earlier. And so I think there certainly will be pressure up at times when there is significant contango on all storage values, and I think they'll be pressured down on -- when it's in backwardated market. But I think, inevitably, the tanks like ours, and there's a few others, too. We're not the only one that are well-connected. We'll continue to have the highest value. Your first question about what drives it? Spreads are a significant contributor to that.

Al Swanson

In addition, one of the fundamental drivers, I think, that's caused a lot of source to be developed has been the influx of Canadian crude. Canadian crude is coming down in large diameter pipes and volumes that the typical mid-content refiner can't take all at once. So that's causing demand to be staged at Cushing. Some of it's blended to get to a certain refinery spec. And additionally, you've had some pipeline reversals that have given more of the refiners access to Cushing source barrels, and Canadian source barrels, we've got a pipeline project that we reversed the streamlined crude into Southern Oklahoma. Third party's reversal line to go into Southern Oklahoma. Oxy's reverse line take crude to western -- West Texas, they've been getting crude that way. So you've got more people taking small batches of Canadian crude or specifically, bundling [ph] crudes, and that's -- that has been causing a fundamental demand for increased storage. And then like Greg said, it's sort of compounded by the end-of-month spread.

Operator

Our next question comes from the line of John Edwards with Morgan Keegan.

John Edwards - Morgan Keegan & Company, Inc.

Just kind of following up Bernie's question. I'm just curious what -- I guess, what would you view as sort of the optimal storage at Cushing? Or, I guess, another way of asking it, how long do you envision that the over-supply situation being in effect?

Greg Armstrong

John, it's a pretty dynamic situation right now of -- and you know me, I'm guilty of using of a lot of analogies, but it's a little bit like trying to shoot a bird in a crossing pattern. You can't aim where it's at. You've got to aim where it's going, and then you've got to anticipate whether it's got a headwind or a tailwind, and you hope your neighbor doesn't shoot you in the process. But in any event, I would say that there's a lot of things happening right now. The demand for the economy can affect what's going on, on the demand side where the natural pull-out at Cushing. At the same time, there's a rising level of domestic production that's coming in. And even though there are some big projects being announced, if tomorrow, you could actually probably move, what, Harry, 40,000, 50,000 barrels a day out of Cushing, you might relieve the pressure immediately and the market might flip back into a smaller but quite patterned basis differential. So I just think it's going to be dynamic for the next 12 to 36 months. And it'll be a function somewhat of how production and supply continues to come in out demand, true economic consumption and then ultimately, the infrastructure relief that happens whether it's in small 25,000 to 50,000 a barrel a day increments, or whether it's some big pipeline project.

John Edwards - Morgan Keegan & Company, Inc.

Okay. And then at what kind of -- what do you view as the additional demand for storage at Cushing in the current market? How -- I mean, there's been a lot of tankage projects announced. What's your thoughts on that?

Greg Armstrong

I think it's -- we certainly see the conversations we have with our operational customers, and we're building an additional 4.2 right now million barrels, which will take us up to about 18.5 million barrels, I believe. But those are already contracted and again, those are for pure operational needs. So it really has nothing to do with some of the other financial issues. We're not sure exactly what's going on in some of the other markets but clearly, they've got demand there with other competitors, so they wouldn't be building, I don't think so. I just think it's really hard to gauge. Clearly, the time spreads have come in now, I think they're around $0.50 a month, in the near month. And then it goes down to about $0.25 out, and then get smaller even further out. So there's probably not a lot of structural encouragement today where if we were having this discussions 3 or 4 months ago, then it might've been $1 on the front line from it -- might extend for a while. Clearly, the differentials are providing some support there, because there's also inter-month spreads on the differential. So your question is just how long are people committing to the demand storage? We've got the same questions. We like where we're at with respect to our position in our customers slate, because we think we've got customers that will -- that have economic value in the tanks we provide, irrespective of the market condition.

Operator

[Operator Instructions] And speakers, no further questions at this time.

Greg Armstrong

Okay. I want to thank everybody for attending. We know this is a very, very busy time period for earnings releases, and other news releases have been coming out so we appreciate your dedication to this, whether you're on the live call or in the replay. And we look forward to updating you for the second quarter results. Thanks, operator.

Operator

You're welcome. Ladies and gentlemen, that does conclude your conference for today. Thank you for your participation and for using AT&T Executive TeleConference. You may now disconnect.

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