Plains All American Pipeline LP (PAA) 2010 Q2 法說會逐字稿

Welcome to the Plains All American Pipeline and PAA Natural Gas Storage second quarter 2010 results conference call. During today's call, in addition to reviewing the results of the prior period the participants will provide forward-looking comments on the Partnership's outlook for the future, which may include words such as belief, estimates, expect, anticipate, or other words that indicate a 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 most recently filed prospectus, 10-K, 10-Q, 8-K as applicable, and other current and future filings with the Securities and Exchange Commission.

Throughout the call participants may reference the companies by the 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 Web sites 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 prepared remarks in the QA session.

This section of the Web site also reconciles the non-GAAP financial measures to the most directly compatible GAAP financial measures and includes a table of selected items that impact compatibility with respect to the Partnership's report of 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 compatibility. Also for PAA, references to the net income are references to net come 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 Dean Liollio, President of PNG, and Al Swanson, CFO of PAA and PNG. I will now turn the call over to Mr. Greg Armstrong.

Thank you, Linda. And good morning and welcome to everyone.

Before we get started I would mention that Harry Pefanis, President and COO of PAA and Vice Chairman of PNG, is on vacation with his family but is on the call and available for questions. However, to avoid potential communication challenges I will cover the operational section of the call that Harry typically addresses. But again he will be available for the QA session. In addition to Harry, Dean and Al we also have other several members of our management team available for the question and answer session including Pat Diamond, our Vice President responsible for strategic planning, and Roy Lamoreaux, Director of Investor Relations.

As a reminder, the slide presentation we'll be referring to on this call is available on our Web site at www.paalp.com and www.pnglp.com.

Yesterday afternoon Plains All American reported second quarter performance within our guidance range. Prior to diving into PAA's result I would mention that last night we also released results for an issued inaugural guidance on our 77% owned Natural Gas Storage subsidiary PNG. Beginning today PAA and PNG will hold joint conference calls, and additional members of PNG's management will join us on the call to review PAANG's operating and financial results and will also be available during the Q&A.

I'll now turn to PAA's operating and financial results released yesterday afternoon. As illustrated on slide three, for the second quarter of 2010 we reported EBITDA of $259 million, and net income of $113 million, or $0.65 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 $248 million and adjusted net income was $120 million, or roughly $0.57 per diluted unit.

In comparison to guidance, our overall results were near the top of the range and were highlighted by overperformance in our fee-based transportation and facility segments and weaker performance in our supply and logistics business.

Adjusted EBITDA results for the second quarter of 2010 were up about 3% over last year's second quarter. However, the net revenue mix changed with an 18% an increased contribution from our fee-based segments.

Adjusted net income and adjusted net income per unit decreased 8% and 23% respectively, due primarily to higher DD&A and interest expense, an increase in the number of units outstanding, and the impact of the incentive distribution rights as they affect net income. Slide four graphically represents this quarter's performance versus guidance. highlighting the fact that we have now delivered 34 consecutive quarters of results in line with guidance.

We believe that this consistent performance which was delivered during a period of significant volatility serves as further reenforcement of the durable and predictable future of PAA's results. Last month, we declared a 4.1% year over year increase in our distributions to $3.77 per unit on an annualized bases.

As of the distribution payable next week, PAA will have increased its distribution in 23 out of the last 25 quarters. We continue to target an annualized distribution rate of $3.80 per unit by year end.

I will now review our second quarter operating results compared to the mid point of our guidance issued on May 5, 2010, discuss the operational assumptions used to generate our third quarter guidance, and discuss the progress of our expansion capital program and acquisition activities. Dean will cover the PNG-specific information in a moment. Overall our second quarter operating results were favorable to the mid point of our guidance. As shown on slide five, adjusted segment profit for the transportation segment was $135 million or $0.48 per barrel which totals about $9 million above the mid point of our guidance range.

The primary driver of the favorable results was about $6 million lower operating expenses. About $ 3 million of this is a timing difference in our maintenance and pipeline integrity programs an should be incurred during the second half of the year.

Transportation segment volumes were up about 5% over mid point guidance which helped generate revenue that was about $3 million higher than forecasted. The higher than forecasted volume in revenue amounts were primary attributable to the Capline and Rangeland systems.

Adjusted segment profit for the facilities segment was $72 million or $0.35 per barrel which was approximately $6 million above mid point guidance. Segment capacity was 70 million barrels per month, which -- capacity was in line with guidance. The favorable results were due primarily to lower operating expenses at PNG and lower than forecast utilities and maintenance expenses. Adjusted segment profit for the supply and logistic segment was $40 million or $0.56 per barrel which was $6 million below mid point guidance and just above the low end of the guidance range.

Although there were several contributing factors to segment performance, the largest revenue variance was lower LPG volumes in margins partially offset by higher than forecast gain on the sale of excess linefill. Segment volumes of approximately 790,000 barrels per day were essentially on target with guidance with lower LPG volumes largely offset by higher water-borne crude oil imparts.

Maintenance capital expenditures were $22 million for the second quarter, and we continue to expect maintenance capital to run about $85 million for the entire year.

Let me move now to slide six and review the operational assumptions used to generate our third quarter 2010 guidance, which was furnished in our form 8K issued last night. For the transportation segment, we expect volumes of approximately 3.1 million barrels per day and segment profit of $.0.48 per barrel. This volume is consistent with our performance in the second quarter. I would mention that our guidance shows and increase of approximately 75,000 barrels per day in the second half of the year versus the guidance we presented in May. The bulk of this increase is due to increased volumes on Capline, Capwood, and the West Texas area systems.

Facility segment guidance assumes a total capacity of 71 million barrels of oil equivalent which is up about 1 million barrels over the second quarter reflecting the full period benefit of capacity additions primarily completed in the second quarter at St. James and Patoka. Midpoint segment profit per barrel is estimated to be $0.33 per barrel. Supply and logistics segment guidance volumes total 815,000 barrels per day, with a projected midpoint segment profit of $0.60 per barrel. This guidance includes some benefit from contango during the quarter, and reflects expected lower seasonal contribution from LPG sales.

As we indicated in our first quarter conference call and discussed in our June 10 analyst meeting we have not experienced any material operational impact nor do we currently foresee any material direct impact from the oil released in the Gulf of Mexico. That said, regulatory oversight of the industry in general is anticipated to increase.

Regarding capital projects, as shown on slide seven, we continue to project total organic growth capital investment of $360 million for the year, and as shown on slide eight our capital projects remain generally on time and on budget. We continue to see solid demand for new tank construction projects at our major market hub terminals as well as demand for additional takeaway capacity within several of our supply basins, and anticipate that we will be able to be more definitive about some of the resulting projects in the coming months. I would mention that we are continuing to pursue Pier 400, and we expect that it will be fourth quarter before we'll have a better view for the path forward on this project.

Lastly, with respect to our acquisition activities, over the past several months we have entered into agreements on or closed a few bolt-on type acquisitions. Total consideration paid and deposits made through the end of June equaled approximately $150 million. We expect that we will be able to give additional color on these acquisitions in the near future. I would also mention that we continue to actively evaluate opportunities in each of our operating segments.

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

Thanks, Greg. In my part of the call I'm going to provide an update on PNG's activities, address our second quarter operating and financial results, and also share a few comments about our third quarter guidance. In addition to completing PNG's initial public offering, the second quarter was a very active period for PNG operationally.

Our overall capital program is on target. We started this year with a 2010 program of approximately $95 million, and despite a lot of activity and typical challenges associated with drilling operations, the cost reductions and cost increases have generally balanced out. A recap of our capital program is included on slide nine.

At Pine Prairie we placed Cavern Well #3 into service early in the quarter and dewatering operations were completed in July. Cavern Well #3 increased the total working capacity at Pine Prairie by 10 BCF or approximately 70%, and increased PNG's total working capacity to 50 BCF, an overall increase of 25%. We also commenced leeching on Cavern Well #4 and based on our latest sonar run in mid July we have created approximately 1.1 BCF of cavern space.

Operations are running smoothly and we are currently on track to bring Cavern Well #4 into service in the second quarter of 2011 in the range of 7.5 BCF to 8 BCF working capacity. In early June, we completed drilling operations on Cavern Well #5 and expect to begin leeching operations in mid August.

We anticipate bringing Cavern Well #5 into service in the second quarter of 2012 at approximately 10 BCF of working capacity. Although we prefer it when the hub services market is very active, we took advantage of a lull in physical market activity during the second quarter to commence an unscheduled fill and dewater cycle on Cavern Well #2. This created an additional 4% of working capacity, increasing capacity from approximately 8.5 BCF to around 8.9 BCF.

The high performance capacity of Pine Prairie's leeching system gives us the flexibility to conduct conventional leeching, fill and dewater operations simultaneously and at relatively high rates. As illustrated on slide ten, the versatility of this system allows PNG to expand Pine Prairie at low-cost and with a high level of certainty regarding the timing of planned capacity additions. Including the addition of this newly created capacity we currently have leased over 99% of our available capacity at Pine Prairie to a diverse mix of customers.

In anticipation of bringing additional working capacity online in the second quarter of 2011, we commenced a non binding open season for two BCF of storage capacity at Pine Prairie in late June. The open season concluded in mid July and was heavily oversubscribed. We received over 20 bids totaling approximately 25 BCF from a healthy mix of current and potential customers with over 75% of the bids coming from new potential customers. The results from the open season come from strong volumetric demand for firm storage for firm storage.

As you can appreciate, because negotiations and discussions are ongoing with participants in the process, it is not to PNG's or its stakeholders' benefit to discuss specific pricing levels. That said, given that customers are fully aware that seasonal spreads and cash to NYMEX spreads are weak right now, I don't feel uncomfortable communicating that bids are at lower rates than we were contracting for three months ago. This is partly due to the recent and rapid change in market conditions including weaker spreads which are simply the price differences of natural gas from the summer injection period to the winter withdrawal period as well as customers looking for lower service levels.

We believe the change in spreads was driven by increased summer demand for natural gas due to a record 30% warmer summer based on year-over-year population-weighted cooling degree dates to date coupled with market confidence and ample winter supplies of natural gas.

As I suspect you have been hearing on some of the other conference calls for MLPs with natural gas infrastructure, hub services in general have been negatively impacted by the decrease in locational price differences or basis. Despite these recent headwinds, the upfront capital investments we have made early on at Pine Prairie give us the ability to construct incremental storage capacity at low-cost, enabling us to generate attractive economic returns in the current or even a weaker pricing environment.

We also believe the certainty of service, interconnectivity and performance capabilities will continue to make Pine Prairie a preferred storage service provider for many years to come. In this regard, as a part of our recent open season we also solicited nonbinding indications of interest for additional capacity at Pine Prairie starting in 2013. Based on the solid response we received, we are making preparations to file an application at FERC to further expand Pine Prairie. We currently anticipate filing this application by the end of the year and will be able to provide you with more specifics regarding the proposed expansion at that time.

At Bluewater, we completed the drilling of a new well designed to withdraw fluid from the reservoir that over time will expand the natural gas storage capacity at this facility by approximately 8%. The storage space will be created whether the fluid withdrawn is formation water or hydrocarbons. The economics of this investment are attractive even if we recover 100% water, but we designed the well to be able to selectively produce oil if reservoir conditions are appropriate.

As it turns out, we were successful in completing the well as an oil producer that came online in early June and is averaging over 140 barrels of oil production per day. As a result of trying to maximize the amount of oil ultimately recovered, and thus optimize long-term cash flow, we are not withdrawing fluid as fast as we might otherwise, and we expect the production rates to vary throughout the injection and withdrawal cycle.

Another notable development I want to mention is that effect he June 1, Ben Reese joined PNG as Senior Vice President Commercial and Todd Brown joined as Vice President of Optimization in connection with the formation of PNG's commercial optimization group. The formation of this group is a significant milestone in the continued growth and development of PNG. I've had the pleasure of working with both of these gentlemen previously and am confident they will add value to PNG.

In addition to benefiting our unit holders by optimizing the value of our natural gas storage assets and related services, this group will also enable us to better serve our customers by providing them with increased liquidity and flexibility as well as problem-solving capabilities. This group's activities will be similar to the low risk hedged activities successfully employed in the crude oil business by PAA and will compliment PNG's basic commercial strategy of committing a high percentage of its storage capacity under multiyear firm storage contracts. The contribution from this effort above current baseline cash flows will take a while to develop and incremental overhead costs will burden results for a few quarters, but we expect to achieve positive results in 2011.

Let me turn now to PNG's operating and financial results which are summarized on slide 11. Yesterday we reported second quarter adjusted EBITDA and adjusted net income of $14.2 million and $7.9 million respectively. Our Firm's storage business was in line with expectations.

However, as discussed during PAA's first quarter conference call, our reported results included some transitional IPO related and start-up related items associated with bringing Cavern Well #3 on line as well as lower than expected contribution from hub services activities. Additionally, these results also reflect the impact of start-up costs for the commercial team and the costs of marking to market and closing out a derivative position.

Taking into account the effect of some one-time offsetting benefits, we estimate the net negative impact of these nonrecurring items was approximately $1.2 million. Our reported financial results also include the burden of nearly $475 million of higher cost debt due to PAA for the first 35 days of the quarter. Effective with the closing of the IPO on May 5, this balance was reduced to $200 million and the interest rate was reduced from 6.5% to around 3.2%.

The net impact on second quarter results of the higher debt balances and interest rates was approximately $1.9 million. At the end of the second quarter, PNG had total long-term debt of $205 million. We believe the transitional issues are now behind us, and as a result the third quarter should be PNG's first reporting period without significant nonrecurring transitional items.

In that regard, yesterday we also filed an 8-K in which we furnished operating and financial guidance for the third quarter and second half of 2010, selected portions of which are summarized on slide 12. In general, this guidance reflects continued steady cash flows from our current portfolio of firm storage contracts but also incorporates our expectation of modest hub services profitability due to continued pressure on spreads and basis.

In summary, although lower hub services rates will impact PNG's results in the near-term, hub services comprised less than 15% of total revenue. And as we have discussed, substantially all of PNG's working capacity is contracted for the 2010/2011 storage season at attractive rates. Additionally, our assets are performing as designed, our capital program is on time and budget and we have a strong financial position.

These points are bolstered by the fact that we can build storage at low incremental cost, enable us to generate attractive returns even when term contract rates are under pressure. Thus, even if current market conditions continue for a number of years, we believe that PNG's is positioned to generate mid single digit organic distribution growth and provide an attractive total return proposition with acquisition upsides.

Finally, in regard to acquisitions, I would mention that although we are limited in the specifics we can provide on past or current acquisition processes in which we have been or may be involved, we continue to remain very active in analyzing various potentially synergistic acquisition opportunities.

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 guidance for the third quarter of 2010, as well as briefly touching on certain accounting issues involved in PAA consolidating PNG after the IPO. As summarized on slide 13, PAA exited the quarter with solid capitalization, approximately $41.2 billion of committed liquidity and credit metrics in line with our target. The committed liquidity I mentioned includes approximately $195 million of availability under the PNG revolver.

After quarter end we further enhanced our liquidity through the issuance of $400 million of five-year senior notes which closed in mid July. The offering was price to yield 3.98% and provided $396 million of net proceeds. We expect to use a portion of the proceeds to redeem our $175 million, 6.25% senior notes due 2015. These notes are callable at 103 in September of 2010 and will result in an approximate $4 million annual interest savings.

At June 30, our adjusted long-term debt to capitalization ratio was 47%, and our total debt to capitalization ratio was 55%. Including the reclass of the $500 million of notes used to fund inventory, our adjusted long-term debt balance was $3.85 billion. The total debt ratio includes $1.5 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 June 30 was comprised of approximately 22 million barrels equivalent with an aggregate value of $1.5 billion.

In addition to these inventory volumes and values, which we carry as a current asset we also have approximately 13 million barrels equivalent of linefill and base gas carried as a long-term asset that has a historical book cost of 622 million.

Our adjusted long-term debt to adjusted EBITDA ratio was 3.6 times. As reflected on slide 14, our long-term debt primarily consists of senior unsecured notes, and has an average tenor of approximately 10 years. We have no maturities until September 2012 and 93% of our long-term debt is fixed at an average rate of 6.2%.

Let me now move on to guidance as summarized on slide 15. Third-quarter adjusted EBITDA is expected to range from $240 million to $265 million, with adjusted net income ranging from $106 million to $136 million, or $0.47 to $0.68 per diluted unit. Our full-year 2010 guidance reflects an estimated 78% contribution from our fee based segments.

Following the IPO, PNG will continue to be a consolidated subsidiary of PAA -- as such its assets and results will be consolidated and reported in PAA's balance sheet and income statement. PAA's consolidated earnings will be reduced by 23% of PNG's earnings, which is the portion held directly by PNG public unitholders and not PAA. This reduction is reflected on PAA's income statement as "net income attributable to non-controlling interest." A similar reduction for "distributions to noncontrolling interests" will be reflected to determine PAA's distributable cash flow. On the balance sheet, PNG's assets, liabilities, and debt will be consolidated into PAA's balance sheet.

The $268 million of equity proceeds raised in the IPO are reflected in the equity section of PAA's consolidated balance sheet with $167 million attributed to noncontrolling interests and the remaining $101 million attributed to PAA's share of net equity. This is effectively reflecting the book gain on the IPO.

As shown on slide 16, PNG exited the second quarter with a debt to capitalization ratio of 22%, EBITDA to interest coverage of 5.1 times, and debt to EBITDA ratio of 3.4 times. The debt to EBITDA ratio is calculated in accordance with the covenants in PNG's credit agreement which includes pro forma adjustments for Cavern #3 which was placed into service in the second quarter.

PNG's committed liquidity was $195 million at June 30. This is subject to covenant compliance. Additionally, I want to provide a few comments relative to the initiation of PNG's commercial optimization efforts that Dean discussed.

We will utilize the same type of low risk, asset-based optimization tools in PNG that we have effectively utilized in PAA's crude oil business. our policy is to purchase only products for which we have a market, to minimize our direct commodity price exposure and not to speculate on outright commodity price changes. These activities are overseen by a risk management committee that is independent of the commercial function. These commercial optimization activities will require working capital that we expect over time may be as high as $75 million. However, we expect the requirements will be well below that level over the next several quarters.

There is one final item I want to address before turning the call back over to Greg. In Dean's remarks he addressed PNG's overall business, the recent market softness for hub services, and PNG's guidance for the third and fourth quarter of 2010. In PNG's initial public offering documents, we included an estimate of the minimum estimated available cash from distributable cash flow for the 12 months ended June 30, 2011, which showed an estimated coverage ratio relative to the minimum quarterly distribution of 107%.

The primary variance impacting our guidance for the second half of 2010 as compared to the earlier forecasts I just mentioned is lower hub services revenue. Our guidance for the second half of 2010 reflects distribution coverage of less than to one. This is in part due to the softer market conditions.

But I would note that even in the initial estimate we anticipated distribution coverage for the second half of 2010 to be less than one to one due to the fact that the significant driver for cash flow coverage for the one-year period ended June 30, 2011, is the revenue additions associated with bringing approximately 8 BCF of new storage capacity on line in the second quarter of 2011.

Accordingly, the distribution coverage for the last three months of our estimate for the 12-month period ended June 30, 2011, was meaningfully higher than 107%. We remain on schedule to bring that capacity into service in the second quarter of 2011, and although we are not yet providing guidance for the first half of 2011, we anticipate run rate distribution coverage for that same three-month period will be well above one to one. As Dean mentioned previously, even if the current market conditions continue for the next few years, we believe PNG can generate mid single-digit distribution growth driven by organic expansion at Pine Prairie while maintaining a comfortable distribution coverage.

With that I'll turn the call back over to Greg.

Thanks, Al. Before we open up the call for today's questions, let me quickly recap the major take aways from this call.

First, PAA delivered another solid quarter of performance versus guidance and is on track to meet its targeted goals for the year.

Second, we have solid credit metrics and ample liquidity and are well positioned to continue to execute our business plan.

Third, our consolidated capital program is progressing as planned and we remain active in pursuing incremental acquisition opportunities.

And then fourth and finally we believe PAA and PNG each provide attractive investment opportunities that combine a low risk profile with an attractive current yield and a positive outlook for future growth.

We very much appreciate your participation in today's call and we look forward to updating you on our activities during our third quarter call in early November.

Linda, at this time we'd be glad to open up the call for questions.

(Operator Instructions.) And our first question comes from the line of Darren Horowitz from Raymond James. Please go ahead.

Good morning, guys. How are you?

Fine, Darren.

Greg, a couple questions. First it looks like gulf coast refinery utilization has picked back up a little bit sequentially. We've also seen some favorable movements in crude differentials. Am I correct in assuming that those two things are the main driver of Capline and Capwood strength in the back half of this year?

Those certainly are contributing factors. I'm looking at our guys here. I think it's that and we're into the driving season right now, too, so people are cranking up runs quite a bit. So it's a combination of all those factors. We still expect Capline to kind of ebb and flow from time to time. But long-term, clearly we've increased our interest in that pipeline. We think it's going to have a lot of activity many years after I'm not on this Earth.

Okay. Shifting over to the west Texas-New Mexico systems it looks like volumes picked up ahead of what you were forecasting for the second quarter and you've got an upward bias into the back half of this year. Is that mostly driven by an uptick in Permian activity, or -- to the extent you can provide more color there we'd appreciate it.

Certainly there's been a lot of drilling activity out in the Permian. And Darren, it looks like it's going to continue for quite some time. And I think also sometimes you'll see some flows out there as we see the tanks build up and then we go into contango and out of contango. Yes, those pipeline movements will shift up. In the section that Harry normally covers and I covered today, a lot of our pipelines we're seeing in west Texas at or near capacity so we're actually building new lines out there. So I think it's definitely consistent with your assessment that activity levels have picked up out there.

Okay. And then last question for Dean. To the extent that you can comment as it relates to the acquisition landscape, has there been any movement in the bid/ask spread for storage assets and also any change in the logistical strategy to move gas east possibly with the addition of complementary pipeline infrastructure?

The second part of your question, no change in that strategy. That's still very valid. Your first question, most everyone saw the recent price paid for the most recent storage transaction at Bobcat. So I would just say that values are still very strong for storage out there.

I might just add, I think -- and it's probably easier to refer back to kind of E&P land. Anytime there's a major move in commodity prices up or down, the buy/sell activity or the acquisition activity tends to pause a little bit while people try to recalibrate what's going to be the new norm. I think we've seen the market for hub services and spreads, for example, I think in May, Dean correct me if I'm wrong, but I think the seasonal spread was probably a $1 or a little over that. Recently we saw it down as low as $0.47 I think you got $0.42 or $0.43 cents on an intra-day basis. So if you equate that to kind of the same type of issue when you have a rapid move in commodity prices, I think there's a potential here for the acquisition process to drag out a little bit.

I think sellers are going to live in the prices of April, May, and buyers are going to want to move to the current activity levels. And it will just take a while to sort itself out. I think probably this time next year we'll look back and realize it was temporary, but while you're in it doesn't feel very good.

Yeah. Greg, I appreciate the color and congratulations again on another solid quarter.

Thank you.

Next we'll go to the line of Brian Zarahn from Barclays Capital.

Good morning.

Good morning.

Can you give a little more color on the acquisition, the $150 million you mentioned? What type of asset?

Unfortunately I can't at this point in time. As kind of the comments, they were intentionally a little bit vague. You'll see when we file our 10-Q which I think is going to be filed tomorrow, we've entered into some contracts and we've put some deposits down but those transactions haven't closed yet. And our hands are pretty much tied, Brian, from giving much more color at this point. But we did want to give you the heads up on this call that if you study the 50 or 60 page 10-Q you'll see that there's about $150 million of transactions that again we've either entered into agreements and made deposits and some small ones we've closed. I would certainly suspect by when we have our next call we can talk about it if not before then.

Okay. And then on Pine Prairie, Dean, you mentioned that rates are a little bit lower -- well you mentioned they're lower than three months ago. Can you give us a sense of order and magnitude?

Brian, I prefer not to right now. I mean, we're in active negotiations. But also, it's reflective a bit in the level of terms, too, that was requested. So I'd just prefer not to if you don't mind.

Okay. And then can Al provide growth CapEx for PAA and PNG in the second quarter?

PAA's was right at $80 -- hang on one second. Right at $78 million. And I want to say PNG was roughly a quarter of that. I don't have that exact number in front of me.

We'll work on that, and if we don't get it before we get off the call we'll give you a buzz.

Okay. I guess just finally, Greg, can you elaborate a bit on your comments on increased regulatory oversight?

Boy, Can I ever. Yeah, I think there's no question that anytime there's an event the way we've seen in the Gulf everything's going to be put under a microscope. And I think what we're hearing and seeing from both in the headlines and in the back channel communications is that Washington, DC, is going to help the unemployment a little bit by hiring a lot of people to make sure they oversee the operations in the field. I think that's going to carry over from Gulf of Mexico into the onshore.

There's also been unfortunately a spate of activities onshore with some pipeline releases and that kind of stuff. So my comment was really directly just simply to give a heads up that I think it's probably out there and coming. I think from a standpoint of how it affects our profitability, et cetera, inevitably those costs get passed on to the consumers. But the transition generally is painful. And the headline issues that happened during the debate that generally goes on between the left and the right trying to claim who's taking the higher ground, it's always comical if not painful.

Okay. Thank you.

And Brian, on the PNG's capital, it was roughly about $30 million of the $80 million.

All right, thanks, Al.

Thank you. Our next question comes from the line of Stephen Maresca from Morgan Stanley. Please go ahead.

Good morning, everybody. Dean, thanks a lot for the detail on the storage side. That's what my first question is. You talked about the hiring and the commercial optimization group. What does the PNG model look like going forward in terms of how you view the business in the next two to three years? Percent optimization, percent you feel that will be just flat out contracted storage.

Yes, Steven. I mean, from a percentage basis I think before these recent activities we probably had about 12% of our total revenues coming from hub services. We've clearly lowered that in our guidance in the last half of the year. But where I see customers going at least currently with slightly lowered terms of service, our group will be able to take the additional operational capabilities that that creates at Pine Prairie and really increase that over time. So if you can kind of think about it from that term, maybe a little bit lower on the firm storage rates, perhaps, and with the level of service that customers are wanting a little bit higher over time in hub services as far as the percent to revenue. But given that, we've we're still on the path and the pricing we saw as far as still very comfortable with contracting our long-term storage contracts in the three to five-year tenors at Pine Prairie and saw healthy demand for it.

Maybe, Steven, just to clarify, I think we're still expecting to be in the 90% if not all the way to 100% leased category. I think what Dean's referring to is if whereas four or five months ago people were willing to pay a higher price for higher turn service so they paid a premium price and they got the full nine turns that our facility could deliver. We seeing where people are saying, look, the hub services market is not currently active. Nobody is trying to cut costs. So they say I need your storage. I'll pay less for it but I'll take lesser turns. What that means is we'll still lock that in, but we'll have -- but with the optimization group on board we have the ability to participate when those market opportunities do arise.

I think from a distribution coverage, et cetera, we'll still look to say anything that's above what we would consider base level activities, that will be just like we'd treat it at PAA. It's kind of free equity but it's not for the distribution. So you're still going to see a fairly conservative approach as we bring these caverns on to maintaining solid distribution coverage against what we know we can deliver. And then yes, the optimization team, if we're selling fewer-turn services has got more asset to work with that's effectively 100% committed except for the capacity or the excess deliverability receipt capacity is available for those guys to work with the optimization.

Okay. That's helpful. And Greg, looking at PAA, the coverage is a little light this quarter. And you look at guidance for next quarter a little light as well. Do you feel more comfortable going forward operating in the -- a little above one times distribution coverage? Or is this something you think is just temporary market fluctuation?

I think we're very close to the base level of operations. There's not been even on PAA's side as much upside opportunity out there. So I think we said we were comfortable in the 103 to 105 coverage range when we're near the bottom of that. Because it's real solid. We're up over 80% fee-based I think this quarter. And so that's fine. When you look at the coverages, and we do have a little bit of a saddle effect.

Our LPG activities have a fourth quarter-first quarter benefit in there. And there's other parts of our business that also have a little bit of flavor of that. So what you're going to see is if you look at the first six months versus just the quarter you're going to see coverage, I think it's around 106 on the six-month basis. So if you go back, we actually forecasted that in our numbers. I think we foreshadowed that in the year end conference call which was held in February. So none of that's news to us in the sense that we expected it.

I think when you look at the year and you extrapolate out kind of the midpoint or upper midpoint of the guidance, you're in that 103 to 105 in a year where we're basically saying we're in a dead economy and we're not getting a lot of volatility to give John vonBerg and his group a chance to make a lot on the increments. Yes, we are comfortable in that range. As we move up if we start to see a lot of that free equity come in, your coverages might go up but we wouldn't necessarily change our distribution rate. I think our distribution rate is going to be function of incremental capital expenditures and acquisitions.

Okay. And then final question if I may. You talked about the increased regulation and we obviously had the EEP oil spill. I think a lot of us, it's hard to see how well pipelines are maintained. And I think some of us take it for granted. What is it that you guys do to make sure that things are safe and maintained well? And what do you think specifically can be done from a regulation standpoint that's going to increase costs for you guys to make sure stuff like this doesn't happen?

Well, what do we do? We worry a lot. Because there are certain things -- I mean if a farmer goes out there and pulls a tractor and he runs his plow deeper than he should and he pulls our pipeline up, there's not anything in the world we can do to do that. And we had here recently tremendous rains and it washed away a bank and eroded and we had a pipeline -- a little bit of a leak. So we were able to get it cleaned up in a hurry. I think what you do is, we do a lot of scenario planning. We do a lot of drills.

We spent -- I don't know what the number is, Mark Gorman's in here with me, but it's millions upon millions of dollars as we acquired third party pipelines. A lot of what we've done, as you know, Steven, is we've acquired and consolidated other companies, and in many cases the quality of their assets relative to the way we want to operate them, they're just not up to snuff. And so we build into our acquisition program the cost to bring those pipelines up. There's been recently -- just back to the kind of government regulatory, there's been the pipeline integrity rules, and those covered a limited portion of the pipelines in the US, those that were in high consequence areas. And they had highly populated or close to water, and then they also covered -- had a size limitation on diameter of the pipe. We're through all of that program. But many years ago PAA started basically trying to say the next generation, how do we take that type of scrutiny and intensity onto all of our pipes. And we've been working through that program.

In some cases we've probably taken out 2,000 or 3,000-miles of pipe, smaller diameter stuff, that has meaningful exposure to the environment but very little economic benefit when you put it in perspective. And so we built more pipe in west Texas. I bet we've taken at least 2,000-miles out alone. Today you'd love to have that if it was quality pipe. What we would rather do is simply go out and build new pipe. Because at the end of the day we can negotiate with producers and everything on margins in a perfect operating environment but it doesn't work that way with old pipe. So we've had to build that into our margins and our returns.

So quite candidly, I think the industry has done a very good job. It's unfortunate when these events occur. But for anybody to assume that EEP didn't do everything they could to keep that leak from happening, I think that's just wrong. I think sometimes stuff happens. And unfortunately when you've got thousands and thousands and thousands of miles of pipeline out there, unfortunately when you have the spill in the Gulf -- a two barrel spill is going to get a camera put about two inches off it and it's going to look like Lake Ontario.

All right. Okay. Well, thanks a lot for everything.

Thank you.

Thank you.

Thank you. Our next question comes from the line of Yves Siegel from Credit Suisse. Please go ahead.

Good morning. Just a couple if I could. One, just thinking about the open season for Natural Gas Storage, I'm just curious and you may be able to answer it or maybe have I to follow up. But how much ability do the customers have in terms of how much flexibility is built into what they're bidding on, ie, do you go out and say, hey, we have this storage available for you and we expect three to five years of tenor, put in a bid? Or are the customers able to come in and say, you know, this is what we would like, this I how we would like to use it. This is the number of turns. And we want it for just two years? Could you describe how much specificity there is when you have an open season?

Sure, Yves. I mean, we put some general guidelines out there as far as tenor. Not on turns but on tenor. And customers bid. Now, sometimes they'll bid outside those lines. And it's a negotiating process from there. But generally that's how it works. It's fairly flexible once we get into it. But as far as awarding the particular bid, we stick to some pretty close guidelines.

The open season, Yves, is nonbinding. So they're not stuck with strict parameters that if they tender their end, it's -- so they do take some latitude. But I think for example what we saw in this year versus last year, I think last year we put two BCF up for an open season and we got between 25 and 30 BCF of demand. This year we put two BCF up and we got about 25. So that kind of drives Dean's comment about good volumetric demand. What we have seen is that the requests for the high turn service, which is again a premium price, is down this year because I think people are trying to say I need your storage and I want your storage but I just as soon have the lower end of the service. So they're riding coach class as opposed to first class.

All right. I can appreciate coach. Just in terms of diversity of customers, are you seeing the same sort of cast of characters? Or has that changed any?

No. Actually we were pleasantly surprised, Yves. I'll comment on two sides of that. Of the 25 [deeds] -- that Greg just mentioned that we got, 75% of the bids were from brand-new customers that aren't in Pine Prairie right now. So that was very encouraging to us. I would say much more infrastructure-type customers. And even more so if we go out to 2013, the bids that we received or the levels of interest, I should say, and space as far out as that was much more heavily weighted to power generators and utility types.

Okay. So I would read that as a net positive development. And then just the last questions for Greg, you mentioned Pier 400. Could you elaborate on your comments and also maybe put it into the context of more regulations? Does that make it more daunting to try to get that project to the finish line?

Going in reverse, I don't think -- we're talking about more regulations. I think at this point in time it's more negotiations. We have to bring several parties to the table all at the same time. Historically the big hurdle has been some of the environmental issues, which I think everybody has known it takes a long time in California to get through those. I would say -- and I'm looking at Mark Gorman -- we're 98% through those issues and in fact it's probably very close to finished. But I just don't know if you're ever finished in California. We have to work with the Port of LA, the city council, and then the customers, and then the labor issues out there.

So I think what we're seeing here is once we kind of got through the shock and awe, if you will, of the 2008-2009 period where everybody was kind of paralyzed about what the future held for the economy and for energy demand, et cetera, things just stabled out. They probably haven't leveled out at the most optimal level in terms of outlook for demand right now. But the same dynamics still exist today as existed before. And that is ultimately you're going to have to bring in more crude oil by ship into Southern California. And you're going to need to do that in an improving environmentally friendly way.

And this would be -- and I hope I don't overstate this. I think as designed it's probably the most environmentally friendly port certainly in the US. And generally speaking if it's in the US and California that may even extend to the world if we were bragging. So I think we put all those bells and whistles on there. It's just trying to make sure that the economics work. But the interesting thing is throughout the entire shock and awe period of 2008-2009 we still had continued interest from the customers who I think didn't mind that it waited a little bit longer while they were sorting things out. And we've also seen the local regulatory bodies and agencies who are thirsting for jobs to see us come. And so we're closer today than I think we've ever been. That said, I think it will still be fourth quarter before we're able to get back to you. But I think we're looking at -- we would create 500 plus jobs out there, quite a bit. And that's pretty significant right now.

Great. All right. Thank you very much.

Thanks.

Thank you. Our next question comes from the line of Michael Blum from Wells Fargo. Please go ahead.

Thank you. Can you just clarify one point? Do you -- is your view -- and this question is about PNG -- is your view that the weakness you're seeing in the overall market, is that a once a year phenomenon? Or do you think that there's been a structural shift in the market and this is a multiyear trend?

Michael, this is Dean. I mean, I can comment right now on what's causing it. It's just extreme warm weather in what we're seeing. And that's what's driving the front end cash to be higher versus the winter supply. And then just confidence that there's a lot of supply out there this winter. All I can tell you is, I can't predict the market but it will change. It's what we're seeing right now.

Michael, I'd just take Dean's a step further. We've had a 30% warmer winter and we've had record production. And unless fundamental demand, unless the economy is doing stronger and you take away the seasonal weather-driven demand, if we had all of that excess production going into storage right now, you know, you'd be jamming it. And the front end price, summer price, would probably be under tremendous pressure. Because we started the year off with storage levels well above norms, and effectively well above where it was last year. And even today with the -- we've had I think 13 now out of 14 weeks this year where injections were less than last year.

And yet we're still very close to storage levels that we had last year and well above, 400 BCF or 500 BCF above five-year highs. So that's why we think it's temporary. When you ask is it a one-season phenomenon, now you have to say well, how long is the drilling moratorium in the Gulf of Mexico.

If they keep it for a couple of years, well you're going to see that production fall off. And maybe we go back to a different kind of balanced market. But if it got cold tomorrow, I can tell you this, you start seeing injections coming pretty fast because there's no other place to put it. I think for the last two weeks we've actually had withdrawals in the producing part of the US for storage in the middle of the summer when we're typically building inventory. I can certainly tell you that's the case at our facilities. And lastly, not this week but last week you had withdrawals both in the producing in the west.

So I think it's hotter than a pistol and you're seeing it in the market. What Dean was also talking about is because production levels are so high, and inventory levels notwithstanding the lack of injections are still high because we entered the season, nobody is worried about running out of gas in the winter time so you don't have fresh upward pressure on the spreads. Again, you take weather out of the picture you'd be jamming gas into the ground, you'd pushing the price down, and you'd probably have the winter price staying about the same. So your spread would widen out. Last year we went from probably $1 spread as it got close to the end of the summer and people realized that we were going to fill storage up, I think the spread moved out to over $2.

Yeah, Michael, just give a little data points in exactly what Greg was saying. Last year at this time, and these are fresh numbers off this morning's storage report -- we were a little over 3 TCF last year. Right now we're at 2.95 Ts full -- the five-year average is a little over 2.7. So even with this super warm weather and demand up because of that, we're still seeing the storage fill. And I think Greg's exactly right, given here in a couple of months we will see it come in at some pretty strong rates.

Okay. Great. Thank you very much for the color. I appreciate it.

Thank you. Next we'll go to the line of John Edwards from Morgan Keegan. Please go ahead.

Yes, hi. How are you doing?

Hi, John.

Hi, John.

I'm just curious if you could talk about this. How many BCFs of storage are up for sale? And then what is the mix in terms of low turn versus high turn service? I don't know if you can talk about any of that or not but I'm curious about that.

Well, I can tell you we don't have any available in most of the --

I mean in the acquisition market is what I'm talking about.

Okay. Probably can't. Those that we signed CAs on, we're not supposed to say anything about it, and those that we haven't signed CAs on we'd be guessing. So I think generally it was a true statement that we made before. We think most of the facilities that are coming up for sale have been recently built and they were built for the high turn storage services. 90% of storage is probably held by utilities, and it's not up for sale. So it's this storage on the margin that's available. So it's primarily the higher performance service. Realizing that higher performance has a range within that. If you look at our Bluewater facility, which is kind of your more conventional depleted reservoir, that's a one to two, maybe a three-turn service. If you're in a salt cavern storage probably your minimum you're looking for is about four and you can go up as high as nine.

Okay. Then maybe I can ask it, in terms of the value of storage that's on the acquisition market, dollar-wise, any range you can give us?

We're on record. There's approximately $3 billion in terms of projects that we see that are out there. And again I can date that back to pre CAs. And there's been one transaction of recent that's been about $500 million. So if that was included it would reduce that to about $2.5.

Okay. And then the other thing I'm curious about is we've seen announced recently some private equity projects. Are those in the same camp, kind of high turn service that you're seeing? Any thoughts you can --

Most of them are high turn service.

Okay. All right. And then can you -- I didn't catch the debt that was on PNG if you have the second quarter, can you -- I think you said $205 million. What was -- I missed the number and you had it on the slide. What was that again?

You've got it correct. It was $205 million.

Okay. All right. Great. Thank you very much.

Thanks, John.

Thanks, John.

Thank you. (Operator Instructions.) Now we'll go to the line of Michael Cerasoli from Goldman Sachs. Please go ahead.

Thanks. Just a quick question on crude oil pipeline flows. Given the incident in the Gulf and more recently shut down of Line 6b, have there be any opportunities over the past few weeks, months, do you expect any opportunities down the road as a result?

Well, certainly, I mean things are immediately rerouting to try and get crude oil from where it's at to where it needs to be. But we haven't -- I don't think there's been any significant market disruptions, partly Michael because storage was so dadgum high to begin with. There's a lot of stocks to pull down from before somebody's going to start paying a premium to ship it around a problem area. Especially if they think the area is going to be resolved fairly quickly.

Okay. And then from a higher level, are you guys seeing anything to suggest the economy is deteriorating further, is it stabilizing, improving? Some color there would be great.

We don't necessarily see anything to tell us it's improving tremendously. I certainly think it's probably fair to say from what we can see it's stabilizing is probably the right world, probably not stabilizing at the level we all want it to.

That's helpful. Thank you very much.

Thank you. Our next question comes from the line of Adam Rothenberg from [ZLP]. Please go ahead.

Good afternoon.

Hi, Adam.

I'm curious to better understand the acquisition market for Natural Gas Storage. Did you guys look at the Bobcat acquisition? And sort of how did that process go for you guys?

Adam, we really can't comment on other people's processes. Just couldn't.

Okay.

I could give you a long-winded answer but it would still be the same conclusion at the end.

Okay. Fair enough. And what was the effect that Keystone had on you guys for the second quarter since it was going through a linefill?

I'm looking at our guys and they're shaking their heads. Really not a big impact at all. It just hasn't affected the crude close that we're involved with.

Okay. And also it looked like at points during the second quarter the contango curve got a little bit wider and some of the differential -- some of the geographic differentials did as well. Were you guys able to lock any of that in that you'll see maybe in the third and fourth quarter?

We certainly have built part of that, and some of that's in our numbers. I would say, this Adam, we unfortunately haven't figured out how to sit with our tanks empty until they it gets to its peak and then lock it in, but we tend to basically phase in to the opportunities when they're there. So we start seeing pricing points. We'll allocate if it gets to X contango, we'll commit so much of our tankage that we have available and then lag into it. Recently though we've had 90% of our tankage in Cushings pretty much, under long term leases to third parties, so the volume exactly varies in Cushings is not as big as you might imagine.

So that's why you guys realized the higher quality fee base during the quarter. Very good, thanks.

Thank you.

Thank you. Next we'll go to the line of Jeff [Zirak] from George Weiss. Please go ahead.

Hi, guys. I guess building on Michael Blum's question, how does the modern well productivity around the Haynesville area where you operate impact the summer-winter spreads? Presumably a producer could produce a well in the summer, sell the gas forward and then produce it in the winter time and replicate the function of production area storage. Are you seeing -- do you think that phenomenon has an impact on rates going forward? Or how do you kind of balance the value of storage with that spread under pressure?

Yeah. As a former E&P producer I'll answer and then I'll let Dean correct me if I miss it a lot. Part of the issue there is the profile of the wells, Jeff. Back in the -- I'm dating myself but in the early 1980s when we had ownership in the Yucatan and that kind of stuff, we were the primary source of storage. The pipeline companies had us under take or pay contracts. They would call up and say you can only produce gas 90 days a year and we'll tell you which 90 it is. And so we had production there, but these were carbonate reservoirs that had tremendous frost impermeability and so it was just a matter of compression and just opening it up and compression. These wells, when you turn them on they'll have a 70% to 80% decline profile in the first several months. And once you turn them on, because you have to use these great large fracturing techniques and you put tremendous volumes of water in there to create the fractures and the fissures, to then float out. Once they turn it on they really can't turn it off. So it's conceivable that on the margin you can do that. But you really -- if you've seen one of these frac jobs, there's a reason why pumping prices at Halliburton and everything are going through the roof. There's a limited number of these frac tanks and pump trucks to be able to do that. So you're not going to be able to solve the problem of peak to valley storage demand with bringing these wells on in stages. But I do believe it can have an influence simply because people start drilling, and what we've seen already is that if we didn't have the hot weather we would have very low prices which could have -- low price is why people quit drilling. So right now we have the phenomenon of relatively good price in a market that's probably over supplied fundamentally but weather's sucking up all the excess.

Okay. That makes sense. Thank you.

Thank you.

Thank you. At this time we have no further questions, please continue.

First we'd just like to thank everybody for the continued support and participating in today's call. And we do look forward to updating you in November. Thank you, Linda.

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