Plains All American Pipeline LP (PAA) 2010 Q3 法說會逐字稿

Ladies and gentlemen, thank you for standing by and welcome to Plains All American Pipeline and PAA Natural Gas Storage's third quarter 2010 results conference call. During today's call, in addition to revealing the results of the prior period, the participants will provide forward-looking comments on the partnership's outlook for the future, which may include words such as believes, estimates, expects, anticipates, or words that indicate forward view. The partnerships intend to avail themselves of Safe Harbor precepts that encourage companies to provide this type of information and direct you to the risks and warnings set forth in Plains All American Pipeline and PAA Natural Gas Storage's most recently filed prospectus, 10K, 10Q, 8K as applicable, and other current and future filings with the Securities and Exchange Commission.

Throughout the call, participants may reference the Companies by their respective New York Stock Exchange Ticker Symbols of 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 sections entitled non-GAAP reconciliations, which present certain commonly used non-GAAP financial measures such as EBIT and EBITDA which may be used here today in the prepared remarks on in the Q&A section. The 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 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 measure excluding the effect of selected items impacting comparability. Also, for PAA, our references to net income are references to net income attributable to Plains.

Today's conference call will be chaired by Greg L. Armstong, 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 call over to Mr. Greg Armstong.

Thank you Gayle. 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. As a reminder, the slide presentation we will be referring to in this call is available on our website at www.paalp.com and www.pnglp.com.

Yesterday afternoon, Plains All American Pipeline reported third quarter performance between the midpoint and high end of our guidance range. As illustrated on slide three, for the third quarter of 2010, PAA reported EBITDA of $205 million, and net income of $81 million, or $0.28 per diluted unit. Excluding the selected items impacting comparability, which are included in the table at the bottom of the slide, our adjusted EBITDA was $264 million, and adjusted net income was $140 million or $0.70 per diluted unit.

Adjusted EBITDA results, adjusted net income, and adjusted net income per diluted unit for the third quarter of 2010 increased 13%, 23% and 19% respectively over last year's third quarter. In comparison to guidance, PAA's overall results were near the top of the range and were highlighted by over performance in our fee based transportation and facility segments and in line performance in our supply and logistics business. Slide four graphically presents this quarter's aggregate performance versus guidance, highlighting the fact that we have now delivered 35 consecutive quarters of results in line with guidance.

PAA Natural Gas Storage also reported third quarter performance slightly ahead of the mid point of its guidance range, and Dean will cover those results later in the call.

Last month, PAA declared a 3.3% year over year increase in our run rate distribution, to $3.80 per unit on an annualized basis, which met our distribution growth goal for the year. This equates to a 3.7% increase in distributions paid in 2010 versus 2009. As of the distribution payable next week, PAA will have increased its distribution in 24 out of the last 26 quarters.

During the remainder of the call today, we will focus in on the following items for both PAA and PNG which are highlighted on slide five. They include comparison of actual performance to guidance and operational assumptions that are incorporated into that guidance, capital projects and acquisition activities update, capitalization liquidity at the end of the third quarter, fourth quarter 2010 financial guidance and preliminary 2011 EBITDA guidance and growth capital investment plans.

With that I'll turn the call over to Harry

Thanks, Greg. I'll now review our third quarter operating results compared to the mid point of our guidance issued on August 4, 2010, discuss the operational assumptions used to generate our fourth quarter guidance and discuss the progress of our expansion capital programs and acquisition activities. Dean will then cover the PNG specific information in just a moment.

Overall our third quarter operating results were favorable to the midpoint of our guidance. As shown on slide six adjusted segment profit for the transportation segment was $142 million or $0.50 per barrel which is about $7 million above the midpoint of our guidance range. These favorable results are due to the combination of higher revenues associated with our pipeline loss allowance barrels and operating expenses that were a little lower than forecasted.

Volumes for the quarter were in line with the midpoint of our guidance. Adjusted segment profit for the facilities segment was $75 million or about $0.35 a barrel which was approximately $5 million above the mid point of our guidance.

Segment capacity was 71 million barrels per month which was in line with our guidance. Segment profit benefited from higher ancillary fees, primarily related to higher throughput volumes as well as lower operating expenses.

Adjusted segment profit for the supply and logistic segment was $48 million or $0.63 per barrel which was in line with the mid point guidance. With the exception of our water-borne foreign crude oil imports, volumes were in line with guidance also.

The variance in our water-borne volumes was due to an early arrival of a cargo that was anticipated to be received in the fourth quarter. As a result, we'll see lower water-borne volumes in our fourth quarter guidance.

Maintenance capital expenditures were $29 million for the third quarter, resulting in a total of $62 million through September 30. We expect maintenance capital to run between $85 million and $90 million for the year.

Let me now move to slide seven and review the operational assumptions used to generate our fourth quarter 2010 guidance which was furnished in our form 8K to you last night. For the transportation segment, we estimate volumes of 3 million barrels per day and segment profit of $0.50 per barrel. This volume expectation is in line with the actual results for the third quarter.

Facility segment guidance assumes a total capacity of 72 million barrels of oil equivalent with segment profit per barrel of $0.33. Projected capacity is up just slightly from the third quarter.

Supply and logistic segment guidance volumes total 885,000 barrels per day and a projected mid point segment profit of $0.94 per barrel. This guidance includes higher volumes and margins than the third quarter due primarily to the seasonality of our LPG business.

Moving on to our capital program as shown on slide eight. We've invested approximately $255 million thus far this year. We have increased our total organic capital investment -- growth capital investment for 2010 from $360 million to $380 million. Primarily due to the addition of the new Christian expansion which I will describe in greater detail in a moment. The timing of our major project is represented on slide nine.

Greg will discuss the capital committed to our 2011 growth projects in his closing comments. I'll spend a few minutes now going over some of our major projects. Let me start with Cushing. As disclosed on Monday and as shown on slide ten we have recently received permits that will allow us to expand our terminals. The newly-announced expansion will add approximately 4.3 million barrels. I'll point out that a substantial portion of the new tankage is committed to customers with whom we've executed long term contracts. We'll also connect with the Keystone pipeline, which is expected to begin delivering Canadian crude oil into Cushing in 2011. Total costs for these projects are expected to be approximately $85 million of which $60 million is expected to be incurred in 2011.

On Tuesday, we disclosed information about several projects currently in progress in that are part of our mid-continent expansion project. As shown on slide 11 this includes de-bottlenecking segments of our mid-continent systems to increase capacity into Cushing and a project to connect our Cushing terminal as well as our western Kansas and southeastern Colorado systems to the White Cliffs pipeline. We expect these projects to be completed in the third quarter of 2011 at a cost of approximately $25 million.

On Tuesday we also disclosed the Bakken project that we are pursuing. As shown on slide 12, the project will include constructing a new 103 mile pipeline segment from our Trenton station to our Wascana pipeline. The Wascanaline would be reversible and could flow crude north to an interconnect with third party infrastructure in Canada that would in turn move the crude oil to Patoka or Cushing. Total cost of this project would be in the $160 million to $200 million range and would be incurred over a two-year period.

We have a number of projects that are in various stages of development. It's a bit premature to discuss any oft he specifics but I can tell you we're very busy and evaluating expansion opportunities in the Wolfberry, Avalon, Eagle Ford, and East River areas.

We also continue to move forward with our negotiations on Pier 400. We'll provide a little more detailed update on Pier 400 once we've concluded our negotiations with the Port and our customers. And lastly, with respect to our acquisition activities, as previously disclosed during the third quarter, we closed on acquisitions totalling $175 million. These consisted of five individual bolt-on type acquisitions including the purchase of a 34% interest in the White Cliffs pipeline, and additional 11% interest in Capline, and a few other complimentary but smaller value assets. We willcontinue to actively pursue acquisition opportunities in each of our operating segments.

I'll now turn the call over to Dean Liollio, President of PNG, for an update on our gas storage activities

Thanks, Harry. In my part of the call I will provide an update on PNG's activities, address our third quarter operating and financial results and share a few comments about our fourth quarter guidance and preliminary 2011 outlook.

Execution of PNG's 2010 capital program continues to progress. Overall, we remain on time and we currently expect to come in approximately 5% under the amount we had budgeted for 2010, primarily due to lower expenditures on base gas. A recap of this capital program is included on slide 13.

At Pine Prairie, leaching operations continue at cavern well four and we currently estimate we have created approximately four BCF of working gas capacity. We remain on track to bring cavern well four into service in the second quarter of 2011 at approximately 7.5 BCF of working gas capacity. In late September we began leaching operations on cavern well five and we expect to bring approximately 10 BCF of working gas capacity into service in the second quarter of 2012.

Negotiations are ongoing with respect to leasing capacity that will be available in the second quarter of 2011. That said, as a general rule, for competitive reasons, we don't comment on pricing levels or contracted volumes prior to their effective date. However, I do want to make a few comments about overall storage market conditions. As we discussed in August, market conditions for natural gas storage have weakened rather abruptly over the past five to six months. In our opinion, the softer market conditions were primarily caused by the confluence of two significant factors.

First, substantial domestic natural gas production and second, one of the hottest summers on record which led to high levels of gas fired power generation demand. We believe that either of these factors independent of the other would have created a stronger spread environment and a correspondingly stronger market for storage services. Without strong domestic supplies the strong summer natural gas demand would have put a fear premium on winter month natural gas prices. Without the strong natural gas fired summer power generation demand we likely would have faced storage capacity concerns.

In this regard, we estimate the incremental cooling demand in 2010 over 2009 consumed approximately 300 BCF that would otherwise have been injected into storage. That said, based on this morning's EIA weekly gas storage report, current total gas in storage is 37 BCF above comparable 2009 levels and we still have a few weeks of possible injections remaining. As a result, based on our projections, it appears that the final peak storage numbers in 2010 will likely exceed the record levels achieved in 2009. If that turns out to be the case, we will likely test the maximum storage capacity during 2010 even after taking into account recent storage capacity addition.

In summary, given time and a return to normal weather patterns, we believe the natural gas storage markets will strengthen from current levels. At both PAA and PNG, we remain confident in the long term fundamentals of storage gas in general and in PNG's competitive positioning in particular.

As evidence of our commitment to the natural gas storage sector and PNG stakeholders, in response to this unforeseen softening of market conditions, in mid August PAA announced an amendment to the structure of its ownership interest in PNG. This was a proactive move on the part of PAA that reinforces PNG's ability to achieve a mid single digit distribution growth from its organic growth project even in soft market conditions.

In turn, we believe these actions also support PNG's valuation and ability to effectively compete for acquisition opportunities. Although it is challenging to predict exactly how long these conditions may last, we believe these soft conditions are temporal challenges that are self-correcting over time, likely within the next couple of storage seasons in our opinion. Reinforcing this view is the fact that the responses we received to our recent open season at Pine Prairie suggest there is volumetric demand for Pine Prairie capacity in future periods.

Given our ability to add capacity at Pine Prairie at low incremental cost on a per BCF basis, we intend to remain opportunistic in constructing additional storage capacity. Accordingly in September, PNG submitted an application with the FERC requesting approval to construct 32 BCF of additional capacity at Pine Prairie, an expansion that will increase Pine Prairie's permitted working gas capacity from 48 BCF to 80 BCF. Specifically, this filing requests approval to construct two additional 12 BCF caverns and to expand cavern wells two through five from 10 BCF each of permitting working gas capacity to 12 BCF each. This filing helps position PNG to meet future customer demand as market conditions warrant. While at the same time generating solid returns for our unit holders.

From a cost standpoint, we estimate that we will be able to add approximately 8 BCF of our future expansion capacity at incremental cost of $1 million to $2 million per BCF excluding base gas cost. This cost applies to the capacity we create through a process known as fill/dewater where we use the hanging strength in our existing cavern wells to alternately fill and then dewater one or more caverns creating space in the process without interfering with ongoing operations. Although this process produces space at a slower rate than direct leaching, it is clearly our lowest cost expansion alternative and we are routinely looking for opportunities to create space in this manner.

By comparison, our cost estimate for capacity we create through direct leaching, which involves drilling a new cavern well and building out the associated cavern well infrastructure, is approximately $6 million per BCF, once again excluding base gas. Based on current gas prices, we estimate that base gas costs would add slightly over $1 million per BCF to these costs. Our ability to add incremental capacity at such low costs is made possible by our up front investments in the pipeline manifold, water handling, filtration, and leaching systems.

As shown on slide 14, the flexibility of our solution mining system enables us to simultaneously leach a cavern while de-watering another cavern or performing multiple fill de-water operations. We believe Pine Prairie's unique operating capabilities provide PNG the ability to bring additional storage into service faster with a higher level of certainty and at a much lower cost than many of the operators constructing new salt cavern storage capacity. As result of these factors we believe that we have substantial profitability advantages with our ability to expand Pine Prairie especially in the current market environment.

At Bluewater, which is our Michigan storage facility, we continue to make progress on our efforts to expand the gas storage capacity of this facility by removing fluid from the reservoir. During the third quarter and thus far into the fourth quarter, we have produced liquid hydrocarbons at an average rate of 140 barrels per day. As described on previous calls the volume of fluids we were able to extract at any given time varies with reservoir pressures.

Thus as pressure builds through the season, our liquids removal rates can decrease and vice versa. Subject to permitting requirements we are planning to drill a second well to withdraw fluid at Bluewater in the first half of 2011.

Let me turn now to PNG's operating and financial results which are summarized on slide 15. Yesterday, we reported second quarter adjusted EBITDA and adjusted net income of $14.9 million and $10.3 million respectively. Fundamentally during the third quarter, PNG delivered adjusted EBITDA performance above the mid point of guidance.

Both our reported and adjusted results include the impact of an unforecasted $570,000 charge to earning which is attributable to subleasing firm pipeline transportation rights. We secured these transportation rights in 2008 to facilitate our ability to provide hub services at Pine Prairie.

Due to market conditions during the third quarter we elected to sub-lease one year of the firm transportation arraignment to third parties at a discount to our contract price. The resulting charge reflects the realization of the ten months of this sublease that extends beyond the current quarter. Including the impact of this charge, our results were slightly ahead of the guidance midpoint. Excluding the impact of this charge, results were near the high end of our guidance range for the third quarter of 2010.

Yesterday we furnished an 8K in which we provided operating and financial guidance for the fourth quarter of 2010 and also provided preliminary guidance for 2011. Selected portions of this guidance are summarized on slide 16.

Although our updated guidance includes a few adjustments to reflect our current assessment of market conditions, overall our guidance for the first quarter of 2010 is basically unchanged with the mid point of adjusted EBITDA being up $100,000 over the indicative fourth quarter guidance we furnished in early August. With respect to 2011, we are in the mid stages of our detailed planning process. Accordingly, the 2011 information discussed today is preliminary and subject to refinement as we progress through the annual planning and forecasting process.

As shown on slide 17, our preliminary guidance for 2011 forecasts a range for adjusted EBITDA of $66 million to $74 million with a mid point of $70 million. This compares favorably to the $53 million mid point of our most recent guidance of 2010. Our preliminary forecast for 2011 adjusted EBITDA equates to a year over year growth range of 24% to 39% or a midpoint of 32%.

The primary source of growth in adjusted EBITDA is a full year realization in 2011 of capacity brought on line in the second quarter of 2010 and the incremental capacity projected to be brought online in the second quarter of 2011. I want to point out that major economic inputs for this guidance range are consistent with our view that storage conditions will remain challenging for the near future with respect to both term storage arrangements and hub services. Should these market conditions improve or acquisitions materialize, there's upside to our guidance.

With respect to our 2011 capital program, we currently anticipate our organic capital investment will range from $70 million to $80 million. The majority of this capital is related to Pine Prairie and includes the installation of compression, leaching activities on cavern wells four and five, the conversion of cavern well four to storage services, and various fill/dewater activities.

Capital activities at Bluewater include drilling and completion of another fluid withdrawal well. Before turning the call over to Al, let me address our distribution cover and our outlook for distribution growth. Our distribution coverage for the quarter was 92%. On a quarterly basis, coverage of less than one to one was expected pending the addition of storage capacity associated with cavern well four in the second quarter of 2011. The capacity addition is expected to result in a 30% increase in storage capacity at Pine Prairie and a 15% increase in total partnership storage capacity. The revenue additions associated with this increase in storage capacity in the second quarter of 2011 was the primary driver for the full year distribution coverage averaging greater than one to one in our one year IPO projections. As I mentioned earlier, we remain on schedule to bring that capacity into service in the second quarter of 2011 and we anticipate run rate distribution coverage for that same three-month period will be well above one to one and will set the stage a for distribution increase in the first half of 2011.

Based primarily on increasing cash flows from our organic growth activity, we continue to target averaging mid single digit distribution growth, even if the current market conditions persist for the next couple of years. We also remain disciplined but 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 those activities. With that, I will now turn the call over to Al.

Thanks, Dean. During my portion of the call, I will discuss capitalization and liquidity for both PAA and PNG,PAA's recent financing activity and PAA's guidance for the fourth quarter of 2010.

As summarized on slide 18, PAA exited the quarter with solid capitalization, approximately $1.3 billion of committed liquidity and credit metrics in line with our target. The committed liquidity I mentioned includes approximately $180 million of availability under the PNG revolver.

At September 30, our adjusted long term debt to capitalization ratio was 49% and our total debt to capitalization ratio was 56%. Excluding the $500 million of notes used to fund inventory, our adjusted long term debt balance was approximately $4.1 billion. The total debt ratio includes $1.4 billion of debt that supports our hedged inventory. This debt is essentially self-liquidating from the proceeds when we sell the inventory.

For reference our short term hedged inventory at September 30 was comprised of approximately 24 million barrels equivalent with an aggregate value of $1.5 billion.

In addition to the inventory volumes and values carried as a current asset we also have approximately 13 million barrels equivalent of line fill and base gas carried as a long term asset that has a historical book cost of $630 million.

Our adjusted long term debt to adjusted EBITDA was 3.8 times and our adjusted EBITDA to interest coverage was 4.1 times.

As reflected on slide 19, PAA's long term debt primarily consists of senior unsecured notes and including PNG's credit facility has an average tenure of approximately nine years. We have no maturities until September of 2012 and 89% of our long term debt is fixed at an average rate of 6%.

With respect to PNG's capitalization as shown on slide 20, PNG exited the quarter of a debt to cap ratio of 23%, adjusted EBITDA to interest coverage of almost 20 times and debt to adjusted EBITDA ratio of 3.9 times. PNG's committed liquidity was $179 million at September 30. This is subject to a covenant compliance.

Moving on to financing activities, in September, PAA redeemed our $175 million 6.25% senior notes that were due in 2015 for approximately $180 million. We recorded a $6 million charge to earnings and due to the lower interest rate on the replacement notes issued, we will realize approximately $4 million in annual interest savings going forward. Additionally in October, we renewed our $500 million 364 day hedged inventory credit facility.

Let me now move on to PAA's guidance for the balance of 2010 as summarized on slide 21. Fourth quarter adjusted EBITDA is expected to range from $275 million to $300 million with adjusted net income ranging from $150 million to $181 million or $0.76 to $0.98 per diluted unit.

When added to the first nine months performance, the mid point of our current adjusted EBITDA guidance for 2010 is approximately $1.07 billion, which is 3% higher than the mid point for the full year 2010 guidance we provided in February. Our full year 2010 guidance reflects an estimated 78% contribution from our fee based segments.

Taking into account our recent distribution increase and using the mid point of our 2010 guidance range as shown on slide 22, we currently estimate our full year distribution coverage in 2010 will be approximately 107%. Distribution coverage for the third quarter of 2010 was slightly less than one to one, due in large measure to the seasonality of our LPG business which typically generates stronger results in the first and fourth quarters of the year. With that, I will turn the call back over to Greg

Thanks, Al. For several years PAA has used third quarter conference call that typically is held in November of each year to provide preliminary guidance for the following year. Generally this information is provided on a more summarized basis than our detailed quarterly guidance but does include a preliminary range for adjusted EBITDA interest expense and capital expenditures and now income taxes. We are still in the early to mid stages of our detailed 2011 planning process. In addition, as Harry noted during his comments, we remain very active on the acquisition front.

Accordingly, the 2011 information is very much preliminary and subject to refinement as we progress through the annual planning and forecasting process, and is also subject to modification result of acquisition related developments or capital markets activities.

As shown on slide 23, the preliminary guidance range that we furnished last night in our 8K filing forecasted an increase in 2011 adjusted EBITDA to $1.12 billion to $1.17 billion for a mid point to $1.45 billion. This compares to the $1.07 billion that Al just mentioned for the mid point of our most recent guidance for 2010, and translates into a forecasted adjusted EBITDA growth range of 5% to 9% or a mid point of roughly 7%.

Although we are looking for solid year over year growth in EBITDA, I would point out that 2011 will be somewhat of transitional year for distributable cash flow as a fair amount of this increase in EBITDA is offset by incremental taxes on our Canadian operations during 2011. You may recall from prior conference call updates on this subject that effective January 1, 2011, our Canadian entities that are pass through entities for Canadian tax purposes will become tax paying entities. For UStax purposes these entities will continue to be treated as pass through entities. As a result of this and other organizational modifications related to this event, we expect our 2011 Canadian income and withholding tax payments will increase to approximately $30 million to $35 million.

We expect future Canadian tax burdens will be directionally similar in size and will grow proportional to our overall adjusted EBITDA growth. I would note that effective with the 2011 tax year, PAA's unit holders will no longer be required to file individual Canadian income tax returns.

From a distributable cash flow per unit standpoint, after the GP's 50% participation, the year over year increase in taxes works out to about $0.11 to $0.13 per limited partner unit. This amount is equivalent to about 3% of the current $3.80 per unit distribution level.

The tax PAA pays at the entity level in Canada will generate a foreign tax credit that can be used to reduce the US federal income tax paid by our limited partner unit holders and general partner. The foreign tax credit will be allocatedbetween the limited partners and general partner based upon the allocation of taxable income for that year. We believe that the LP unit holders will be eligible for a full tax credit for 2011 based on the $0.11 to $0.13 per LP unit I mentioned previously, thereby resulting in a meaningful economic after tax benefit for effectively a de facto increase in their after tax distributions. This is somewhat like a methodology that is common for investors to convert a tax [green] municipal bond rate to a pretax equivalent bond rate. I would point out that if the tax credit for a unit holder in any given year is larger than their US federal tax obligation from their PAA investment, the excess cannot be applied to non PAA tax obligation but it can be carried over and used to reduce future tax obligations from their investment in PAA.

Accordingly, based on our preliminary 2011 guidance, even if the distribution level of PAA were to remain constant during 2011 at the current $3.80 distribution level, many unit holders would receive an equivalent after tax distribution increase of up to 3%. Because the significant stepup in taxes only occurs during the first year of adoption, the year to year impact on our unit distributions will be substantially reduced in future years and organic growth projects will generally translate in the direct contributions to distributable cash flow.

Based on the mid point of our preliminary 2011 guidance, which does not include the benefit of any additional acquisitions, we estimate the projected distribution coverage at our current distribution level is approximately 106% excluding the tax increase, the same measure would be around 111%.

At the high end of the preliminary 2011 guidance we estimate the coverage will be approximately 112%. Accordingly, because of the stepup in Canadian taxes during 2011 the preponderance of our distribution growth on a pretax basis will be reliant on our ability to perform at or above the mid point of our guidance, which will be augmented by our ability to make and integrate accretive acquisitions.

At the end of 2009 we targeted to grow PAA distribution over a several year period in the 3% to 5% range. Using distributions paid in 2010 versus 2009, PAA increased its distribution 3.7% during 2010.

We continue to target to achieve average annual distribution growth in the 3% to 5% range, anchoring our growth outlook for the next several years are organic growth projects which will be augmented by our acquisition activities. As you can see from some of the projects I reviewed, over the last 18 months we have been working diligently to expand our inventory of organic growth projects, and as shown on slide 24 we currently anticipate that our 2011 organic capital program will range from $500 million to $600 million.

By comparison, the mid point of that range represents a $170 million or 45% increase over 2010's $380 million organic growth expenditures and we are continuing to develop additional expansion opportunities that could add to that range during 2011. 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. We appreciate your participation in the call today and we look forward to updating you on our activities during the fourth quarter call in early February. Operator, at this time, we ready to open the call up for questions.

(Operator Instructions). We'll go to Yves Siegel with Credit Suisse.

Good morning, everybody. I have to be honest. Boy that's a lot of information to digest.

It's a lot of information to prepare.

I'll just try to stick to a couple of questions. First, when we think about natural gas storage and the soft economic environment that we're in, overlay that with the fact that you have very low expansion cost opportunities in front of you. How should we think about the rates that you are looking for going forward within the context of what I just mentioned and within the context of the fact that you will be having additional storage rolling over from legacy contracts? Does that make sense, that question?

Yes, Yves. I'll make a few comments and ask Dean to jump in. I guess firstly, we actually have very few contracts rolling over in 2011 and not much in the way of 2012. We get out in 2013, 2014 we start having some contracts roll over.

And then obviously we have new space that we're bringing on in both 2011 and 2012 that, as Dean mentioned, we're in the process of contracting portions of that and we're not going give any real comment on rates there. What I can say is that we talked about this in the IPO. Based upon a tight market, and we're certainly seeing a tight market, we estimated we could generate very attractive double digit returns at costs that were approaching $10 million per BCF and the numbers that Dean just gave you, which includes kind of a little bit of a fine tuning (inaudible) we look at how would we best expand it and if we slowed down the volume of growth, but we looked at the quality of the volume growth, we can generate 8 BCF more at roughly $1 to $2 and we can generate an additional 24 BCF on that in the $6 range.

Those economics are extremely attractive even in this low environment. So, we certainly don't want to get into an overbuild situation and have our capacity unavailable. We don't think that's the case. We're not the price setters for the market. I think we are ones that can generate attractive returns even in a tight market for an extremely long period of time. The analogy would be if you have to hold your breath, we think we can hold our breath a lot longer than everybody else

But I think the question also is, when you think about the returns, are you thinking about the returns from the total investment or are you thinking about returns on the incremental investment in terms of moving forward?

Both. But primarily because, again, so much of our activity is leased up. We've got two different markets. Again, the Pine Prairie market is different than the market at Bluewater. That one's held up very constantly. That's why we're not too worried about longer term leases up there. In fact we're generating exactly where we thought we would be in Bluewater, even in this environment. It's really Pine Prairie. It's the incremental investments and making sure we're not cannibalizing ourselves. But again we're are a small factor in the big market in terms of total storage, but I think we're a meaningful factor and becoming more so in terms of the high performance storage.

Okay.

So, the answer is it looks good in both cases, both on an incremental and overall. It just looks better for us on incremental than probably just about anybody else.

Okay. And then if I could, two more questions then I'll move forward, I promise. The second question is, as you look at acquisitions, could you give a little bit more, just elaborate a little bit more on the sort of type and size of acquisitions that you're thinking about? And within the context as well of what type of returns that you think that you can achieve and given the fact that cost of capital has come down a bunch, how does that also play into the thought process?

Yves, is your question limited to gas storage or PAA or both?

It's both.

Okay. Well, I mean, the acquisitions that we're looking at -- it's really no change in our approach at PAA. It's everything within crude oil and LPG and natural gas storage. So the nature of the assets we're looking at hasn't changed. We've always been looking not only for assets, but we also look for entity opportunities.

We have recently increased our management strength here to be able to, I think, widen our band width to be able to chase more things at the same time. And the returns we're looking for are still in the -- well above our cost of capital. Right now we calculate our cost of capital at PAA is probably in the 8% range, maybe a little bit higher than that when you embed the expectation of future growth in that. And at PNG it's probably 100, maybe 125 basis points less than that. And so we're looking at transactions that are certainly accretive.

I think part of the challenge that we look at is the cash flow profile of any acquisition, whether it's at PNG or PAA is we've got an expectation of growth. PNG's is a little steeper than PAA, simply because of the relatively small size and the significance of the organic growth. So when we look at those acquisitions of PNG, for example, we have to say, what can we do on our own and generate attractive growth for our existing unit holders? And then also how do we lower our risk or expand our platform and make sure we don't take away from that rate of growth and in fact we want to actually add to it.

That's both a combination of accretion measurement and then also rate of return, because if you think about it, internal rate of return doesn't really give effect to the near term accretion issue. It just looks at a total overall return over an extended period of time. And these are very long-lived assets. So, we look at it all in context. And quite candidly, all of us hold enough units that we all look at it just the way you would look at it. What's best for the unit holder? We don't want to do silly acquisitions that make good headlines but don't make good money. But we do want to do acquisitions that people may not initially understand but six months into the year they look back and say, damn, good move.

So within that, could you see a transforming transaction in 2011? Is that part of the stuff that you're looking at?

There's certainly other MLPs that have made those kind of statements pretty boldly about transforming transactions. I don't want to get into that. I do think -- we've done two MLP mergers, acquisitions, in our history. I don't think we're done in doing those. I think there are big assets, as well as big entities out there to be acquired. And quite candidly, I think our guys are as good as a management teams as anybody out there to be able to not only get our arms around it but to extract at least as much as the seller if not quite a bit more value on top of that. I certainly wouldn't want you to think it's off the table. If anything, I want to make sure you know it's on the table, but I'mnot going to make any promises about 2011.

All right. Thank you very much, Greg.

We'll go to Brian Zarahn with Barclays Capital. Please go ahead.

Good morning.

Good morning, Brian.

On your Cushing expansions, the project's obviously favorable for your fee-based growth. But with your competitors also building out storage in Cushing is there any concern that future contango opportunities may diminish?

Sure, that's a possibility. If you look at the way we've designed our facility, I mean, we've designed it for -- to handle guys that are going to use our Cushing terminal sort of on an operational basis. So, lots of things can impact contango, and availability of storage at Cushing is certainly one of them .

Brian, I might just point out we're little over 14 million barrels going with this new expansion to about 18.5 million barrels. Let's use the bigger number because I think that would be your area of concern. At 18.5 million barrels I think we've got 16 million or 16.5 million barrels of that is termed out under leases that go quite a ways into the future. And ourcustomers that make up that lease base are all operational users. They don't really use our tanks but for contango opportunities. I mean it certainly optimizes their business, but that's not why they're buying it. And from a functionality -- andI know you've been to Cushing, but just to kind ofput it into perspective for others on the call, the total throughput in Cushing is probably in the aggregate volume it move among all facilities in and out is probably in the neighborhood of 1 million to 1.1 million barrels a day.

We have 800,000 barrels a day of throughput capacity through every significant pipeline in and out of there. And we've got dual header systems so we can do all of this in different grades and quality. That's why people really like to be at PAA is because of the functionality. And we think we give good service, by the way, at a fair price.

When you look at some of these facilities that are being built, certainly there's absolutely no question there's been significant expansion. But many of those facilities are located far away from the actual interconnects and they've got single lines going from their tank to a manifold. In some cases it's our manifold. Those thank tanks have a relatively much lower value. You can put oil in, and you can leave it in there. Or you can take oil out. But you can't put oil in and out of those at the same time and so I think those are being built for contango. Our tanks are not being built for contango. They're being built for our customers to operate with it, and they can be used for contango. So I think at some point in time, I don't know of any market that somehow doesn't get over built at some point in time. But ultimately what happens is those that have true value add tend to do much better in that market. And we have protected ourselves by functionality. But we've also protected ourselves with having the right customers with long-term leases.

The other thing I'd add, Brian, is you're going to have more operational requirements at Cushing going forward. When you look at Keystone bringing some more capacity to bring Canadian crude in, [Oxy's] reversed one of their lines, to take Canadian crude to west Texas. We've reversed one of our lines just recently to be able to move Canadian crude from Cushing down to southern Oklahoma refiners. Third party has done the same, (inaudible) station for all those connections. So, there's a greater need for operational capacity at Cushing today than ever. When Keystone gets their Excel project that's going to layer on additional storage requirements.

I appreciate the color on Cushing. I also have one more question, also on storage. Can you comment on additional expansions you're looking at your other storage locations, storage hubs?

We are looking at expansions at St. James and Patoka, I can say that.

We don't have anything to announce yet, Brian. But it's areas that we're looking at and certainly have a lot of interest as we have said in our press releases, in all of our facilities, and I'd just tell you to stay tuned.

Thanks, guys.

We'll go to Darren Horowitz with Raymond James. Please go ahead.

Hey guys, good morning. Greg, a quick question for you as it relates to St. James. With a lot of the condensate coming up from south of the border and arguably evolving out of the Eagle Ford, how do you leverage your footprint at St. James to move a lot of that condensate north, either through Patoka or up north to Canada?

Go ahead.

Our last stage of Cushing we built 900,000 barrels of tank capable of handling condensate at Cushing -- I mean St. James and then added 750,000 barrels at Patoka.

I think we positioned ourselves there very well for the current market and the one that you forecast is coming which is there's going to be a lot more light product on the market. The steps we've taken, we have certainly increased our interest in Capline from 22% to 44% and now up to roughly 54% percent. And as you say that will be a primary conduit to moving condensated diluent up into Canada and then we've got the tanks at Patoka and the tanks at St. James. And we have expansion capacity at both places sufficient I think to double both. Don't we Harry?

We do. And then we've also added the dock at St. James which is capable of handling barges or small ships.

So I think we're as well positioned as anybody. We need to execute. As Brian asked, kind of where we're at on some of the things, andI'd just say stay tuned.

Okay. As it relates to the basin system, just kind of a quick house keeping question. You surpassed the third quarter volume guidance. It looks like now in the fourth quarter you're projecting it to be down about 8% sequentially. What are you seeing in the south Texas kind of southern New Mexico market? Is there anything that stands out as kind of contra seasonal to you?

What's called the [Duransin] Basin, is that what you're asking?

Right.

Yes. Basically in the third quarter, you had a lot of crude come out of tankage and actually in the second quarter. I mean the third quarter And in the third quarter -- Third quarter you had crude come out of tankage that went on basin. Fourth quarter, we're seeing some crude go into tankage, which took some crude off the basin. That happens from time to time. Storage increases or decreases can have an impact on basin. That's really the cause for the swing. Other than that, we're seeing more volume and more drilling in west Texas and New Mexico.

Okay. I appreciate it. Just kind of one final question for Dean. Kind of bigger picture, Dean. Obviously when you look at your advantageous costs to bring on incremental storage capacity at Pine Prairie it would seem like maybe some other fee-based complimentary infrastructure might be higher on the priority list. Certainly as you look to become more vertically integrated and enhance your connectivity, can you give us any big picture, 10,000 foot view thoughts there?

I'll touch on that. We always look -- and I think I have spoken on this a couple of times in our existing storage asset. And see what we can do to compliment the -- what customers would desire as far as pipelines close to those assets. So I would say from a big picture level probably the other priority on our list, Darren, would be intrastate facilities that are fee based that are in close proximity to those existing facilities.

Okay. I appreciate the color. Thanks, guys.

We'll go to John Tysseland with Citigroup.

Hi guys. Greg, in the past, Plains has been a consolidator I think of several underutilized crude pipelines, as domestic pipeline kind of was in a steady state of decline for a while. And now some of these assets, with these assets underutilized and producers targeting more, I guess,liquid rich reserves, with some areas showing some growth, are there any opportunities to bring some of those idled assets back up? And where do you think some of those are? Is it west Texas or where do you see some of those opportunities to bring those assets back online?

Yes. That's really a good question. We see lots of opportunities, particularly on west Texas, to put lines back in service. We do consolidate quite a bit. We had -- in a lot of areas two or three lines in the same corridors. As we've seen some additional drilling, we've gone in. We've retested lines, spent some capital refurbishing the lines and we're putting some old lines back in service. It has been a benefit to have sort of the right away and the ability to move quickly and put lines in service. And then I'll also point out, that's really what we're doing with the Wascana system as well. That Wascana system is currently not in service. That was part of kind of the old eastern corridor system where crude could come down and move from Canada down into Guernsey. So that's another area where we're taking advantage of having a pipe that's currently not in service and putting into active service again.

And then some of the stuff that was released on I think Tuesday, the mid continent expansion project, involved basically optimizing the lines that we have, doing some reconnects and increasing capacity. In some cases, Brian, it may not actually be by reactivating old lines as much as modifying the flow directions and the quality of crude on there and then increasing the pump capacity to do that. And then in general, I would say, and Harry referenced both the right of way as well as the older lines, we have probably taken, I'm going to guess, 3,000 to 4,000 miles of pipe out of service over the last six or seven years. In some cases those were economic decisions. In some cases they were environmental decisions. We're going to always make sure we run safe pipes. Some of these pipes are old. But when you have the right of way, and as Harry said when you're basically either tracking each other or actually in the same right of way, we don't necessarily have to activate an old pipe as much as we may have to lay right beside an existing pipe and put a brand new one in if we've got a long term view on that. So again I think we're as well positioned to service the market as the needs expand today as anybody.

And then also, with a lot of these plays being more associated kind of crude oil production with a gas well, is there any kind of quality differentials that are going to make piping some of these new areas out or is there any blending opportunities for you there or batching in and around your system?

I don't want to get too specific because therein lies some competitive issues, but I will say this. On a geographic basis, there's the likelihood you're going to end up with too much of a particular quality of crude in a regional area and you're going to have to not only get it away from the well head, but you're going to have to get it out of the area. We handle over three million barrels a day and can provide a better solution or one-stop shop to producers that want to get the best value at an end market that they might not have direct transportation to. Is that a fair statement, Harry?

Yes.

I wouldn't want to give you our road map for where we think differentials going to go, because you could just go start your own company and compete with us.

I don't think that's I don't think you have to worry about that. All right guys, thanks for the detail.

Thank you.

We'll go to Michael Cerasoli with Goldman Sachs. Please go ahead.

Thanks. Just a couple of quick questions. On the Wascana reversal, is this pipeline currently utilized? And then separately, do you think the mid-con and Bakken projects may offer up any supply and logistics opportunities?

First question is Wascanais not currently in service. It used to move crude south into the Butte pipeline system. Butte is full with basically Rocky Mountain production. So it's currently inactive What was the second question?

Just separately on the mid continent and Bakken projects. Do you think you'll have any supply and logistics opportunities going forward once the projects are online?

I think we will, yes. I mean, typically when we engage in projects like that, there in areas where we already have a commercial presence and our supply and logistics groups are very involved in those projects.

Okay.

Michael, I'll just point out, and somebody had asked earlier about on the hubs. Some of this stuff goes hand in hand because again, once you get that take away capacity, you've got to get that product to a major hub. And as Harry said, the increased volumes and varieties of crude are creating more and more terminal needs at Cushing, Patoka, and St. James. Ultimately -- some of the Bakken crude, for example, is being railed all the way down to St. James. And we just activated our rail facility in third quarter?

In August, yes.

So I'd say we're again well positioned there, too.

Okay. And then this is probably a little it in picky, but your preliminary 2011 maintenance guidance is around $85 million roughly in line with 2010 and 2009. I was just wondering about the spend here, and your thoughts on potentially higher regulatory scrutiny following third party spills earlier in the year?

Is your question, you thought it would have been higher you mean?

Does it take into account any higher spend, on integrity spending or so on?

Yes, and I don't want to be too aloof in this comment but quite candidly, we better have been doing a good job last year. I think we did put a range on it this year of $80 million to $90 million and we have been on a program, Michael, for some period of time well beyond what regulatory requirements are to extend the same type or similar type of integrity management rules to non regulated pipes or pipes that haven't been uncovered by the integrity management program. So it's already built into our cost structure. Could that number can turn out to be $82 million instead of $90 million or could it be $92 million? The answer is sure. But I don't think it's going to be far outside that range

Okay. That's fair. Finally for Dean, how you expect expansions around [Dawn] storage to impact demand for storage at Bluewater?

Mike, could you say the first part of that question?

A couple of competitors are expanding capacity around [Dawn] storage, the [Dawn] area. And I was just wondering how that may impact your operations at Bluewater.

Right now Bluewater continues to stay full as far as what we're doing over there. I think there is still a need in that part of the area for more storage. It's really area by area specific. We should be okay with what's on the board right now.

Thanks. That's it for me.

We'll go to Selman Akyol with Stifel Nicholas. Please go ahead.

Thank you. Good morning. On the crude oil imports, I know you talked about one tanker coming in this quarter as opposed to next quarter. But is there anything else as relates to your guidance for the decline in the fourth quarter?

No. It was simply just timing of the --

I was just strictly one ship?

Yes.

And then as we take a look at the St. James expansion, it looks like costs went up there from last quarter to this quarter. Anything going on there?

No. Basically there was two pieces to the project. And just the one piece had been reported last quarter in the other category.

Okay. And then in terms of -- and maybe I misunderstood this. But the midpoint of your 2011 guidance, is that based strictly on internal growth projects or are you guys also factoring in acquisitions to get to that?

No acquisitions. Based on what assets we already have, Selman.

All right. And then last question for me. It relates more to Dean. You guys mentioned optimization group in your press release. PNG and I guess is there any more color on that as it's starting to contribute? Or your outlook for 2011? And then distribution policy at PNG, is that independent of the optimization group?

Yes, just to give you a quick update, Selman. We expect that group to be functional in December of this year and they will contribute some in 2011, particularly given what the markets show us then. So that is baked into our plan. And then the last part of your question?

Is in relation to the distribution policy. Is it independent of the optimization group?

Yes. Said differently, we wouldn't include in the distribution calculation any home runs or triples or even doubles that they may hit. They're going to be able to cover their cost, I bet you, and make a base level of profit that we would include in there. But you're talking in the low $1 million to $2 million range. What they hope to be able to do is keep the market honest against leasing storage and then also have the opportunity when we have periods of volatility to capture incremental upside above that. That incremental upside would not be included in the distribution policy. And the mid single digit distribution outlook that Dean talked about is really based on the base line, not what may happen.

All right. Thank you very much.

Thank you.

We'll go to Jeremy Tonet with UBS. Please go ahead.

Hi, good morning.

Good morning, Jeremy.

Just wanted to touch on a couple of the questions that were already asked before. Other teams in the MPL have commented on increased deal flow. Would you agree with this now? Would you say deal flow has increased the opportunity set out there? And also with the trend of GP consolidation out there do you see -- do you think that there's going to be an opportunity for PAA to take advantage of that as far as entity level consolidation in the MLP space going forward?

On the last point, I sure as heck hope so. I think there's some good opportunities out there that we like their business platforms. And again, we feel like we could extractequal if not more value if we could acquire right. Those deals are very difficult to do though, I should say. But we have the ability to work through complicated structures and have done so in the past. As far as on deal flow, at the risk of sounding like a broken record, I think we have been saying this for about the last seven or eight years. We're as busy now as we have ever been. And we've got more people doing it now than we ever have. So yes, I have to concur. I think the deal flow has picked up and we're doing our best to keep up with the high grade, having to basically say no to certain projects. Not because they may not be good projects but because we've got to try to high grade the ones we do chase.

Okay. And then I was wondering if you had any comments as far as refine product demand out there, what your thoughts are in trends? Do you see that improving?

I think that's going to be tied to the economy and this is not a political statement, because the elections are over. We're still looking for the green shoots that can actually survive. So refined products demand I think is going to be a gradual increase, not a sudden. We drop from total petroleum consumption in the 2005 to 2007 range was probably 20.7 million barrels a day. We're probably in the 18.5 millionto 18.8 millionrange right now. So that's down quite a bit. That recovery we think will be a gradual recovery. It will be influenced by government programs. If there's subsidies out there for alternative energy, then you're going to see some of that recovery be a little bit slower. If you take those away, it will be a little faster. One thing I would point out,Jeremy, and I think the US. refiners, by all the upgrades they have done, have increased their competitive position and we're probably actually right now exporting more refined products I think now than we have in many, many, many years. And the actual net imports is down. So in some cases, what I'm saying is, even though USconsumption may not be increasing that much, total refinery product generation is actually doing okay based on exports. Is that fair, John? John von Berg just (inaudible) distillate in particular. You almost have to get grade specific or product specific when you're talking about refined products as a class.

Great. That's helpful. And then one last question I guess in regards to your relationship with Oxy. Do you have any updated thoughts or comments as far as potential joint efforts between the two?

We still like them. We think they still like us. We're still having discussions on how best to do win-win situations, but I can't comment more than that.

Great. Thank you very much.

Thanks.

We'll go to John Edwards with Morgan Keegan. Please go ahead.

Yes. Good morning, everybody.

Morning, John.

Just translate, I just want to make sure if I translate your commentary regarding Canadian taxes, that means you're expecting not as strong or perhaps flat distribution in 2011?

No. I guess what we're trying to say, if you just looked at a 7% growth using the mid point and EBITDA and you assume that we maintain 101% to 103% coverage, you'd probably come away with a higher growth next year than what it will be because we are going to have to absorb about $30 million to $35 million of Canadian taxes. We've talked about that in the past. We just haven't been able to put as fine a point on the range of the impact. I think at one point in time we talked about anywhere from 20 (sic) to 40 (sic). So from our perspective, if you put that down, the take aways we wanted to make sure that you had John was number one, there will be a -- one, you don't have to file any more tax returns, which is a good thing. Two, there will be a de facto distribution increase whether we change the actual pretax distribution or not, the after tax distribution will increase roughly about 3% based upon that range of $0.11 to $0.13 per unit in the form of a tax credit. You're going file your tax return. You're going to look and calculate your US taxes, and then you're going to reduce it by that $0.11 to $0.13. That's on an after tax basis. It's the same as the muni bond calculation.

I think if you look at our distribution guidance for next year and the CapA distribution coverage at the current level, at $3.80, you know, we're about 106% I believe it was, if you wanted to say okay, look, forget the Canadian tax situation, it's already embedded in the numbers, what would that coverage go to? I think you could go to a $3.90 range and at a 101% to 102% coverage range. And certainly when we think we're at the trough part of the economic cycle, that doesn't feel terribly uncomfortable when we're running about 80% fee based. We're not yet at the point where we can actually talk about distribution growth, but next year we'll give as much guidance as we can on the February call, which is when we normally do that. We just wanted to make sure that as soon as saw , and we got the fine point put on those Canadian tax numbers, that we were able to communicate that.

Because we get a lot of questions, John, about how much longer am I going to have to file Canadian tax returns or do I have to file or I don't want to buy until I don't have to file. And so that's a significant statement that we can make today. The other one is that we've actually been able to quantify the amount of the tax credit that you would get and put it into what I call a de facto distribution equivalent. And then the last thing I'd make on the distribution is we did reiterate today that our target is still to grow 3% to 5% per year on average.

Okay. All right. Fair enough. That clears that up for me. And then just I guess a question for Dean. You were talking a little bit about the market in terms of natural gas storage. You were attributing it, I think you said, to production and weather. I guess if the weather hadn't had been as hot you would have had a greater demand for storage, which would have made it stronger. And then you made a comment also on the production side that you don't have as much fear, I guess, as you put it. I guess in terms of strength in the market to translate that, what conditions do you think have to be present to make a stronger? Is it just simply the opposite of what we've had? Or is that too simplistic?

No, I think you break it down. I think what happened this summer, John, your question's good, is just a confluence of both those things, and generally you don't see that. If we had had one or the other, I think we would have been fine. We certainly, though long term I will tell you, our preference is that demand grow over time and it's not supply driven. It just helps the overall fundamentals. So as we go through time and natural gas, in our opinion, is still very much in favor, and we look for that growth particularly in the power generation area. And supply will -- the market will respond to the pricing and such over time and we'll see that work its way out. I do think it's going to take a couple of storage seasons to work off this supply buildup that we have. Producers have, at least in our opinion, have yet to blink. But sooner or later it's going to get painful.

John, just to kind of elaborate on that just a little bit. We believe storage has value, whether it's over supplied or under supplied. And because, quite candidly, if there's too much production and there's not enough demand, you have to put it in storage. If there's too much demand and not enough production, you have to store it, you have to bring it in from where LNG and [othane] and you have to store it so you have it in the winter. The bad situation for storage is when you're adequately supplied and demand is low. And that's what's happening now. You just don't have a summer/winter spread that has a big impact on storage. What happened was, the supply was up.

And I think what Dean's saying is, take the summer heating demand away, and we're probably worried about where we're going to stick all this gas that continues to come at us. Take the excess supply away and we would have been having the increased heat that we had and you'd have pulled inventories down in the summer where people would have been worried about running out of gas in the winter. So I think what solves this, is right now there are gas wells that are being drilled for non-economic reasons, to hold leases and to do other things. I'm not saying that's a bad decision or good decision. I just don't think you can do it in perpetuity, because I don't they're making money on some of these wells. So it will take $2 gas price or $2.50 gas price and you'll start seeing these rigs lay down. And then actually what happens, is the cycle starts all over again. Because if you have $2.50 gas prices you're going to find a lot of industrial and commercial customers want to use natural gas. They'll start driving demand up, we can't pick the rigs up fast enough and so storage comes back into play.

I think it's an anomaly. We have certainly prepared for a long storm that could last in the sense that one to two storage seasons what we're guiding you to is we think is what it could take for the market to correct itself. But having said that, we have anticipated and prepared and built a lot of cushion into our distribution thoughts as we set up PNG, (inaudible) We tweaked that recently. We're prepared for long hard winters, if we will, or long hard summers, however you want to look at it, and still deliver really good value to our unit holders. And if can augment that with acquisitions along the way, we're much better off when the market turns around. So we don't think there's a lose situation here, it's just a question of how much we win. Put a hurricane in the middle of that at about June or July of next year and you may throw all that out the door and find out we've got $3 or $4 spreads. We'll still going to win, because we've got a lot of storage and we've got a lot of ability to make more.

Appreciate the additional detail. That's all I have at this time. Thank you.

Thanks, John.

We'll go to Joseph Ciano with Credit Suisse. Please go ahead.

Hi, good morning.

Good morning.

No, we don't have that specifically in the guidance. We're looking at 2011, we've got some identified projects and some portfolio projects that are sort of risk weighted into it but that project is not, typically --

In early November, we've probably got right now approved or pending approval probably $400 million to $450 million of the $500 million to $600 million range.

Okay.

If we stopped right now and the only additional project that we added to that was the Bakken, then that number would go up probably the middle of that range and we'd have to kill all the other projects. What we actually hope happens over the next several months is that we crystallize some of these. We'll be able to give you the full detail in February of what makes up -- let'ssay the number comes in at $525 million. We'll give you the detail there on that. But I think what Harry's saying is, if we're at $525 million, we don't have the Bakken project in there. If we come back to you in February with a $600 million number, if it's in there everything else would have had to have gotten made. We feel pretty comfortable about our $500 million to $600 million range.

Got it. Okay. And then you touched upon several potential different areas that that $500 million to $600 million, the projects are around. Can you maybe give a little bit more color on maybe just generally which areas you're most excited about or have the largest potential to put the capital to work?

We're excited about all of them.

Each area has its critical lynch pin as to what's causing it from being a potential project to a project. And in some cases those are negotiations with producers or with customers that we supply to. And in some cases it's competition. So I don't think it would benefit our unit holders to get into too much detail on that

Okay. Got it. Thanks.

Thank you.

And we have no further questions at this time.

Appreciate everybody dialling in and want to handily apologize for the length of the call and the level of information. On the other hand, it makes our life easier if you know what we know. We look forward to updating you on the February conference call. Thanks.

Ladies and gentlemen, that does conclude your conference for today. Thank you for your participation and for using AT&T executive teleconference service. You may now disconnect.