Pembina Pipeline Corp (PBA) 2010 Q3 法說會逐字稿

Good morning ladies and gentlemen, and welcome to the Provident Energy Trust third quarter 2010 conference call. I would like to turn meeting over to Glen Nelson, Senior Investor Relations Analyst. Mr. Nelson, please go ahead.

Thank you, Matt. Good morning everybody, welcome to Provident's third quarter 2010 conference call. Leading our discussion today, we have with us Doug Haughey, President and Chief Executive Officer, and Brent Heagy, Senior Vice President and Chief Financial Officer. Also available with us during the Q&A session, we have with us Murray Buchanan and Andy Gruszecki, who run our Midstream business operations.

It is important today to note that we will be discussing some forward-looking information on the call. This forward-looking information is based on a number of important factors and assumptions, as a result actual results could differ materially from those discussed during the call. Information concerning underlying factors and assumptions is available in yesterday's news release, and is also discussed in our Annual Information Form under the heading Risk Factors, which is available on Provident's website or on SEDAR. Also be advised that all dollar figures given today will be in Canadian dollars.

With that being said, I would like to now turn the call over to Doug Haughey.

Okay. Well, thanks Glen. And good morning everyone. Overall Provident delivered a strong first quarter in our first quarter operating as a standalone pure play Midstream business. Given current forward pricing assumptions, we are maintaining our 2010 adjusted EBITDA guidance at the lower end of our original CAD200 to CAD230 million range. The NGL pricing environment during the third quarter of 2010 was significantly stronger than the same quarter in 2009. Average third quarter West Texas intermediate crude prices increased 12% year-over-year.

Propane prices relative to crude were also much stronger than in the prior year. Propane as a percentage of WTI averaged 59% during the third quarter of 2010, versus 53% in the third quarter of 2009. Butane and condensate prices were also much improved, which were reflective of higher crude prices and steady petrochemical and oil sands demand. Overall market frac spreads increased 13% over the third quarter of 2009 as a result of higher NGL prices. However the benefit to Provident was partially offset by higher extraction premiums at Empress.

Third quarter natural gas throughput at the Empress Eastern border averaged 4.8 Bcf per day, which was in line with the same period in 2009, but still lower than historical averages. For reference, early November throughput is approximately 4 Bcf per day, which is about a 0.5 Bcf lower than November last year. For Empress East third quarter production was flat compared to the prior year, but NGL sales volumes were 6% higher than in the third quarter of 2010, versus the third quarter of 2009 due to more favorable propane markets. Provident has partially mitigated the impact of lower natural gas based NGL volumes at Empress through the construction of a truck rack, which began receiving NGL mix supply in April. We also purchase NGL mix supply from other Empress plant operators, and while positive from a volume point of view, unit margins from these volumes are thinner than gas-based supply.

Redwater West had a strong third quarter, increased ethane sales volumes, which resulted from increased NGL mix supply and production of Redwater, were slightly offset by lower butane and condensate sales. Butane sales volumes were lower in the third quarter mostly as a result of lower activity levels by heavy oil blenders in the Edmonton area, while imported condensate volumes were lower due to softer condensate margins. However on a combined basis Redwater West propane plus sales prices increased by 13%, reflective of a stronger market-based pricing environment for NGLs.

Production at Redwater is slightly up year-over-year, due to the successful contracting of NGL supply mix. We have also started to benefit from the additional supply volumes at the Younger extraction plant, as a result of the recently completed self-pieced pipeline, which brings natural gas from the rapidly developing Montney area in northeast British Columbia, to the younger processing facility. I would now like to turn the call over to Brent, who will discuss further detail around our third quarter financial results. Brent?

Thank you Doug, and good morning everyone. In the first nine months of 2010 Provident's gross operating margin was up 5%, reflecting the increased contributions from both the Redwater West and Commercial Services business lines. Provident's gross operating margin during the third quarter of 2010 was CAD62 million, which was nearly flat when compared to margins from the same period a year ago. The slight decrease is primarily attributable to lower margins generated by our Empress East business line, despite higher year-over-year sales volumes. At Red Water West gross operating margin for the third quarter of 2010 was CAD33.5 million, an increase of 9% compared to the third quarter of 2009. The increase in margin was primarily due to improved product margins in ethane and propane, driven by higher ethane sales volumes, and more favorable sales prices for both products.

Year-to-date margins have increased to CAD100 million in 2010 from CAD92 million in 2009, an increase of 9%. The increase is due to stronger margins on propane and ethane sales resulting from stronger NGL pricing. Empress East gross operating margin was CAD13 million in the third quarter of 2010, compared to CAD19 million in the same quarter of 2009. The decrease was due to increased natural gas costs because of the higher [ARO] price, as well as significant increases in the extraction premiums paid to purchase natural gas, offset by slightly higher NGL sales volumes, and higher NGL sales prices. The Commercial Services operating margin in the third quarter was approximately CAD16 million, representing an increase of 6% compared to the same period of 2009. The increase was largely due to incremental storage revenues from our new condensate storage caverns, which were completed in the third quarter of 2009.

During the first nine months of 2010, the Commercial Services margin was CAD47.4 million, an increase of 5%, compared to the same period in 2009. The increased Commercial Services margin is largely attributable to incremental condensate storage revenues. Third quarter 2010 adjusted EBITDA excluding buy out of financial derivative instruments and strategic review and restructuring costs, increased to CAD53 million from CAD26 million in the third quarter of 2009. This increase was largely a reflection of lower realized losses on financial derivative instruments as a result of the Midstream derivative contract buy out program undertaken earlier this year.

Year-to-date adjusted EBITDA, excluding buy out of financial derivative instruments and strategic review and restructuring costs increased to CAD139 million from CAD119 million in 2009, reflecting higher margins, lower hedging losses, and lower general and administrative expenses. Third quarter adjusted funds flow from continuing operations was CAD44 million, a 77% improvement from the CAD25 million recorded in the third quarter of 2009. While gross operating margins during the third quarter of 2010 were consistent with the same period in 2009, realized losses on financial derivative instruments were significantly lower because of the Midstream derivative contract buy out program.

Cash distributions to unitholders during the first nine months of 2010 totaled CAD143 million, 110% of adjusted funds flow from continuing operations. This ratio was impacted by realized losses on financial derivative instruments incurred prior to the buyout of the contracts in April 2010, and does not include proceeds from Provident's DRIP program. As we stated in our October 14th Analysts' Day presentation, which is available on our website, we are targeting a long-term payout ratio in the range of 80%. Provident maintained its financial flexibility with total debt to EBITDA from continuing operations for the 12-months ended September 30th, 2010 of 2.8 to 1. Total debt was approximately CAD547 million.

To give a brief update on our hedging program, subject to market conditions Provident hedges approximately 50% of its natural gas and natural gas liquids volumes on a rolling 12-month basis. Also subject to market conditions we may add additional hedges as appropriate for up to 24 months. Given the current pricing available, we will look at layering in additional hedges in future quarters where pricing is attractive. Currently Provident has hedged approximately 80% of its frac-exposed volumes for the 2010/2011 winter season. A complete summary can be found on our website.

Since the second quarter, Provident has announced two key items. On October 6, 2010, Provident laid out our plans for a conversion into a dividend-paying corporation on or about January 1st 2011, subject to unitholder, court, and regulatory approval. Provident new dividend level, beginning with the January 2011 dividend is planned to be CAD0.045 per share per month. The new dividend level is intended to allow internally generated cash flow to support organic growth, maintain a strong balance sheet, and provide sustainable monthly dividends to shareholders.

On November 9th, 2010, we issued CAD150 million aggregate principal amount of convertible debentures, the debentures bare interest at 5.75% per year, payable semiannually in arrears on June 30th and December 31st each year, commencing June 30, 2011, and mature on December 31, 2017. Provident intends to initially use the net proceeds from the offering to repay existing revolving term-bank debt, which will then be available to be drawn as required to fund the purchase of any of Provident's previously issued 6.5% convertible debentures. Provident has granted to the underwriters an overallotment option to purchase up to an additional CAD22.5 million aggregateprincipal amount of debentures, exercisable in whole or in part any time for a period of up to 30 days following closing of the offering.

I would now like to turn the call back over to Doug, who will provide some closing comments.

Okay. Well, thanks Brent. What I would like to do is spending a couple of minutes talking about our growth initiatives. Capital expenditures during the third quarter totaled $11 million, we spent CAD21 million year-to-date. Total growth capital for 2010 is anticipated to be approximately CAD42 million as the result of an additional CAD15 million of capital costs being moved in to the early part of 2011, and that merely reflect the timing of capital deployment. Provident also expects to spend approximately CAD8 million in 2010 on maintenance capital, and we estimate a future annual run rate of approximately CAD70 million deployed on growth capital, and CAD8 million to CAD12 million annually deployed on maintenance capital.

We continue to made upgrades at the storage facility at Corunna Ontario that will enhance operating flexibility and commercial opportunities in the surrounding area. We currently anticipate the completion of the rail terminal in the spring of 2011, subject to permitting and regulatory approvals. Overall we intend to spend approximately CAD27 million through 2011 to complete a number of upgrades that will provide greater commercial flexibility in the future. In addition, Provident is also reviewing future joint venture opportunities to facilitate the pipeline and rail movement of NGLs, from the Marcellus shale play in Pennsylvania to the storage facility at Corunna. Provident's storage facility is ideally located to be a terminalling hub for NGL from the rapidly growing Marcellus natural gas play.

Turning to Redwater, Provident is developing three new 500,000 barrel multi-purpose storage caverns, that will be commissioned in 2011, 2012, and 2013. Provident is also constructing a brine pond to facilitate future cavern operations. Over the medium to long-term Provident expects that condensate demand will continue to improve, as a result of continuing investment in the Alberta oil sands by producers. Provident is also considering an estimated CAD7.5 million ethane plusdebottlenecking initiative, that would increase C2 plus fractionation at the Red Weather facility, by up to 4,000 barrels per day. The additional capacity would be utilized to process incremental field plant volumes, and future NGL from upgrader off-gas.

So in closing, everyone, we are pretty happy with the quarter. That concludes our prepared comments. I would like to turn the call back to the moderator to open the line for questions. Matt?

Thank you. We will now take questions from the telephone lines. (Operator Instructions). There will be a brief pause while participants register, we thank you for your patience. Our first question is from Robert Catellier from Clarus Securities. Go ahead.

Thank you. First just a housekeeping question, can you tell us what the maintenance capital was in Q3?

We are just looking up the Q3 number, Rob.

While you are doing that, a follow-up question I have on the capital outlook for 2011. So with your CAD70 million annualized run rate for growth cap, and you are shifting some in to 2011, so would we expect 2011 to be CAD85 million?

Yes, we are still looking at that. I would think so, I always worry about the timing of capital deployment. It seems like projects are taking longer, but my sense is that we have always anticipated a CAD70 million run rate, and with that deferral in to 2011, I think we ought to be targeting CAD85 million in 2011.

Okay. Thanks. And then just on the Empress situation, how did you do in terms of recontracting extraction volumes for the new gas year? Just directionally, were you able to contract a similar amount 220, to the expiring gas contract year?

Yes, we were. It is Murray here. Yes. We were able to resign a significant portion of volumes, and our budget numbers in terms of go forward, we fully expect to be very similar numbers expected as to last year.

And how much would you say out of your total portfolio of gas contracts there are on for a one-year basis versus shorter periods?

We run a portfolio of one year, and then one month, and then we do also daily, and I think if you used approximately a third, a third, and a third, you would be there.

Okay. And finally Doug, on your Ethane debottlenecking project, that sounds like a good project. What is the catalyst to go ahead with that project? Are you looking to secure and finalize the commercial terms with a counter party?

I will let Andy answer that.

We are working on a related project, and it is up in the northeast part of BC. We do hope that we can be making an announcement on that before year end, and the two are related to the extent that proceeds the debottleneck makes a lot of sense, and that is again, one of the reasons for some capital being deferred, because that project is coming together in Northeast BC, the capital or that will be deployed in 2011, and in turn the capital for the debottleneck will also be deployed.

Okay. Got you. I wanted to know about note 11, the gain on sale of assets, I wonder if you could tell us who was the counterparty in the multi-year condensate storage agreement, and the strategic value of the land that you acquired as a result?

Yes, we can't disclose the counterparty, Rob. Sorry.

I am not surprised. Okay. And what about the land?

Hey, the third quarter maintenance capital was CAD700,000.

Okay. What about the land? What can you tell me about the value of that land to Provident? How could you develop it?

We are working on a few potential opportunities in and around acquisitions in, I am not sure how specific here I can be, but we are looking at some trucking and blending options, and we are in the western part of Canada. They tie in very nicely to some of the new oil plays going on in Saskatchewan and Alberta, and in turn they tie in very nicely to our storage facilities at Redwater.

Thank you.

That is a very good non-answer. So that is all you are going to get.

Thank you. Our next question is from David Noseworthy from Scotia Capital. You may go ahead.

Good morning.

Good morning.

First question is just with respect to Corunna. It looks like, Buckeye's pipeline proposal has changed a bit to an ethane-only pipeline, and I was wondering if successful how that may change your outlook for Corunna, and how you will use it and kind of the contribution you expect from it?

I would suggest at this time that there is still a lot of fluidity in terms of what actually does happen between the developments in the Marcellus and Corunna. If that should happen, then what that would mean is probably there would be obviously less of an opportunity for fractionation in the Corunna area, and more of an opportunity for terminalling and storage, and associated activities. So we I would say, think that there still are a number of different scenarios that are in play, and the one that Nova is leaning towards today is the ethane pipeline idea, because obviously in some sense it doesn't make a lot of sense to be moving C3 plus from Marcellus to Sarnia, and then back into the market in the Northeast part of the US. That is still under examination.

The other question I have is , I mean I see that your assumed metrics in terms of WTI crude, AECO gas have improved significantly from October 6th, but your guidance has kind of stayed flat. I am assuming that your EBITDA has moved up. Are we looking closer now to the mid-range as opposed to the bottom of this, or are we actually or is the assumption that the extraction premiums that you are paying are offsetting that improvement that you are seeing as a result of the higher NGL margins?

Yes, David, we are looking at all of that. I think our view right now is to maintain the guidance where it is, because obviously there are lots of moving parts. The fundamentals have improved. We have hedged a lot of that exposure. So we are looking at it. And we didn't think that the change in our outlook was large enough at this point to change the guidance.

Fair enough, fair enough. Just a related question. Can you give us any kind of a feel for, you have given guidance on a $1 change in NGL margins, gets you about CAD7 million of EBITDA, and that has to be forward extraction premiums. Is there a feel for what portion of that CAD7 million you end up sharing back on extraction premiums? Is it like 50%, 25%? Any feel for that?

I am not sure the math actually works because that sensitivity is to a dollar, we are not disclosing what the extraction premiums are, other than to say that we are at the higher end of that previously discussed range. So I think that is about all we can say on that one. We will give it some thought though, in terms of how the math works.

Okay. I will get back in the queue. Thank you.

Okay.

Thank you. Our next question is from Matthew Akman from Macquarie. You may go ahead.

Thanks guys, good morning. On frac spreads are you inclined to take a view that this is a good time to lock in a little bit more, given obviously what is happening to the oil, gas spread, especially gas at AECO, or are you not going to take any views, you are just going to kind of remain agnostic on views, and just have more of a regular hedging program over the next two or three years?

No, I think it's fair to say, Matthew, that we are probably being more aggressive than our base-rolling plan would have you believe.

Yes.

When we release our hedging numbers, I think you will see that we have moved everything up quite a bit.

Recognizing of course that to go out further, if I understand your question, there is difficulty in going out further, and staying in clean products. Because the liquidity drops off fairly sharply, and so yes, we have significantly increased our hedge position, and we are looking to do that out as far as we can, but to be able to go out much more than 18 months gets extremely difficult, due to counterparty liquidity. People aren't looking to buy the propane that far out, or the butane that far out, so that is the other side of the challenge, when you stay in clean products.

Okay. Thanks for that answer, and then second question is around TransCanada's discussions with shippers on their tolling arrangements. I am wondering if you guys are taking a view on that, if you have involved in any way shape or form, not because it necessarily affects you directly, but it does affect Empress indirectly, are you involved in any way in that discussion, and do you have a view?

We have been talking to in a regular dialogue with all of the parties, and I would say our view is that everybody feels that the TransCanada issue needs at least a short-term resolution, and everybody is working hard on that, and it is a difficult issue. Our view is that obviously the more competitive TransCanada is, the better it is for us, and so we are encouraged actually by where we hear some of the conversations going.

Trying to contain the toll?

Yes, exactly. That is exactly right.

And the moving of part of the mainline toll back to the producer side of the AECO. Some of those initiatives are being discussed.

Yes.

I think you have to have that. I mean, obviously the mainline toll is very, very important to Alberta's economic future.

Yes.

You need the exported gas to generate revenues for the province.

Okay. Great, thanks guys those were my questions.

Thank you. Our next question is from Steven Paget from FirstEnergy, you may go ahead.

Thank you. My first question is, could you please give us your tax pools by class?

By class?

Yes. You would have your Class 49s and Class 8s?

No, we can't break those out for you, but we do have, Steve, about CAD900 million in total pools.

Right. Right. So could you tell us what your CCEA rate is on that? Do you expect it somewhat closer to 8%, or up to 20%?

Well, it is certainly going to be higher than 8.

Okay.

Probably going to be more in the mid-range of the 8 to 20.

Okay. Okay. Alright. Thank you. Second question on TransCanada seemed to be saying that they might not be able to move the toll back into Alberta, so that the AECO system would not bare the burden of the mainline, so are there any other options that you might be discussing with them?

Well, two things on that. First of all, we are not directly involved in those discussions. We just are in conversation with both sides of that issue. Although we do have a stake obviously. I think it would be unwise to speculate on what mechanism they used to try to address the issue. Whether it is moving the tolling zone, or something else. I think we probably ought not speculate on that, other than to say that at the end of the day, people are trying to achieve generally the same thing in keeping TransCanada competitive, and there are lots of ways to do it, right, and you are familiar with most of them. I mean, there are a number of alternatives, and I think those are all under discussion now.

Right. Right. Well, I have been on the record with some of my speculation.

I know.

Finally, how are you working with the Alberta utilities on next process that would restructure how NGLs are contracted?

Well, at this point in time, obviously the next application from TransCanada has been delayed. They were planning to file in the second quarter of this year, and it has been delayed a number of times. We now understand that they may file it in the first quarter of 2011. It would be an application with the National Energy Board.

Right.

It will no longer be before Alberta regulators, because it applies to National Energy Board regulated pipelines. To be honest, we will have to wait and see what the proposal is. We participated in all of the energy committees, and there was far from consensus, I guess.

I don't know what the opposite of consensus is, but that is where we were generally as an industry, so I think to be honest, Steven, it is going to be a long process. There are a lot of complications, and I think TransCanada themselves are seeing the extent of complications, with trying to switch the methodology for purchasing gas by the straddle points, which is really what this is.

Right. Right.

Because there are title issues.

Yes. Yes.

So it is complex.

It is quite a process, and it is going to continue to be one. So thank you. Those are my questions.

Yes, Steven just one last point on that. And this might be reiterating something that we have said before. There is no question. First of all two things, as Murray said it is very unclear what the proposal really is, but the second thing is it will add tremendous complexity for everybody, so there may not be a huge benefit. But at the end of the day from a fundamental point of view for our business, it may be more complicated, but it is not necessarily a negative. It could be a neutral or--

Right.

-- complicating event. So my personal opinion, I am not spending a whole lot of time worrying about next rate. There are lots of other good things to worry about.

Okay. Okay. Thank you.

Thank you. Our next question from Linda Ezergailis from TD Newcrest. You may go ahead.

Thank you. A lot of my questions have been answered, but I guess I am just wondering when you might consider providing guidance for 2011? Similar to what you have been doing for 2010?

We have been talking about that, and what we would like to do is get a good beat on where the markers are settling after the commencement of the November 1st contract year.

Okay.

And so we are looking at that, and then Linda, we will be out with guidance. I think our traditional approach has been to provide guidance like well into the new year, and my sense it that we will definitely push that up quite a bit.

Great. Thank you.

Okay.

Thank you. Our next question is from Robert Kwan from RBC Capital Markets. You may go ahead.

Thank you. You talked about some of your projects on the Marcellus and moving that around. Can you talk about your thoughts on the El Paso Spectra proposed ethane line down into the Gulf, and just your thoughts on that, and what that may or may not do with respect to your planning on the Marcellus?

Well, it looks like a good project, but it is one of many projects being proposed for the Marcellus. We have always said that there will be some self bound movement of product out of the Marcellus, and we think that there will be north-bound movement into the Sarnia area. So it looks like that Spectra project is a good one, but like I said, it is just one of a number. I think this will take quite a while for the market to sort out who goes and who doesn't.

And I guess is it fair to say that was kind of in your planning for how the products may be moved out of the Marcellus?

Yes. Yes. We have always felt that some kind of self-bound project would go.

Okay. That is great. On the quarter there was a realized loss of 4.6 million, and it looked like it was the crude and gas derivatives? Are there particular segments that belonged to, and you have excluded it from your segment forecasts? I just want to think about how should we be thinking about this going forward, or how recurring will this be kind of quarter-to-quarter?

Which 4.6 was that?

Are you talking about realized loss?

There was a realized loss -- Yes. And in the MD&A it talked about it being against gas and the crude derivatives and not the clean product hedges?

Yes, we are just taking a brief look at that.

The majority of the loss relating to this three month would have been related to our GAAP contracts, and the majority of that is all relating to our frac-spread production, primarily.

Okay.

In terms, what was the rest of your question whether or not we expect to see it going forward?

Like are those contracts rolling off quickly or are they something that is going to be--?

We have got a fairly extensive summary of all our hedging positions that is available on our website, I believe.

They are the participating ones, Robert that are identified that aren't tied on the, well Pass is clean, but are the one who weren't bought out.

Right. So I guess I --

So they do go on for a while. They are in 2013, I think. So they have got, there are a number, not real big volume, but there is participating gas and crude that are out there for a period of time.

Okay.

That still come into play that you could see losses on depending on where they mark-to-market.

Right. And it is fair to say when you were talking about frac spreads, so they are mostly at Empress East?

Well, it covers our frac-spread business. There is, Empress East is a portion of our frac-spread business.

Okay. And I just --

Roughly two-thirds, but Taylor is the other piece as well. So it covers both. We don't qualitate those to one business line versus the others, because we do it on an operating, on a margin basis. So the hedging losses are below the operating margin basis.

Okay. So it is an ongoing part of your business?It is part of your hedging program?

Yes, it is part of our hedging program, and it is intended to protect us against the potential event of gas escalating rather rapidly, and crude dropping rather rapidly. That is what they were put on to protect against, and they will do that, should that event happen.

Okay.

But otherwise, when frac spreads go wider than what they were put on at. They incur a loss.

Okay. That is great. Thanks very much.

Thank you. (Operator Instructions). We have a follow-up question from David Noseworthy. You may go ahead.

Alright. Just quick question on the volumes that your sales volumes in Q3 year-over-year were lower. Can we imply from that because your kind of contracts for acquiring NGL mix and what not were about the same, that you have more inventory now, and that we would expect more of that sales volume to be seen in Q4 and perhaps Q1?

We certainly had more NGL mix in inventory in Q3. That is correct.

Okay. And how do the sales look so far in Q4?

Pretty much in line with our expectations and our guidance.

Thank you.

Thank you. There are no further questions registered, and now I will turn the meeting back to Mr. Haughey.

Okay. Thanks, operator. Thanks everyone for participating in the call today. We will be following up on a couple of issues that we raised, or that we talked about today on the business-development front, and look forward to chatting with everyone after our fourth quarter release. So thanks everyone. Have a good day.

Thank you. Your conference call has now concluded. Please disconnect your lines at this time, and we thank you for your participation.