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Enbridge Energy Partners, L.P. (NYSE:EEP)

Q2 2008 Earnings Call Transcript

July 29, 2008 10:00 am ET

Executives

Tracy Barker – Manager, IR

Douglas Montgomery – Director, IR

Steve Letwin – Managing Director

Terry McGill – President

Mark Maki – VP, Finance

Jonathan Rose – Treasurer

Analysts

 

Sharon Lu – Wachovia Securities

Gabe Moreen – Merrill Lynch

Bryan Sarom [ph] – Lehman Brothers

Shawn Grant – Zimmer Lucas Capital

Winfried Fruehauf – Fruehauf Consulting

Brad Siegel [ph] – Aurora Capital

Ross Payne – Wachovia Securities

Shawn Wells – RBC Capital Markets

 

Operator

 

Greetings and welcome to the Enbridge Energy Partners second quarter 2008 earnings conference call. (Operator instructions)

It is now my pleasure to introduce your host, Mr. Tracy Barker, Manager of Investor Relations for Enbridge Energy Partners. Thank you Mr. Barker, you may begin.

Tracy Barker

 

Thank you, Latonia and good morning everyone. Welcome to the 2008 second quarter conference call for Enbridge Energy Partners. If you've not already done so and want a copy of the slides, condensed financial statements, and news release associated with this call, they can be downloaded from our Web site at enbridgepartners.com/q; that /q as in quarterly.

In the call, we'll often refer to the partnership by its trading symbol which is EEP. The partnership's results are also directly relevant to Enbridge Energy Management, trading symbol EEQ, which provides a vehicle to invest in the partnership through company shares.

We have online as our speakers today from the general partner; Steve Letwin, Managing Director; Terry McGill, President; and Mark Maki, Vice President, Finance. Available for the Q&A session, we have Steve Wuori, Enbridge's Executive Vice President, Liquids Pipelines; Jonathan Rose, the partnership's Treasurer; and Steve Neyland, Controller for the partnership.

I would also like to introduce Douglas Montgomery who will transition into the role of Director of Investor Relations by September 1, as I move to other duties with EEP. Douglas?

Douglas Montgomery

 

Thanks, Tracy. I know it we have lots of good news to cover today, so I just want to say a brief hello. I worked with Enbridge for eight years; I've been based in Columbia, Calgary, and most recently Spain, and now I'm joining the partnership at a pretty exciting time in its history. I had the opportunity to meet a number of our analysts and investors at the MLP Conference in May. I look forward to meeting and working with many more of you over the coming weeks. My first official duty is to read our legal notice for the record and it goes as follows.

Certain information during this presentation will constitute forward-looking statements. These will include but are not necessarily limited to throughput volumes, financial projections, expansion or acquisition projects, external economics and competitive factors. These statements are based on certain assumptions made by the management. Accordingly, actual results may differ materially from current estimates. You are referred to Enbridge Energy Partners SEC filings including the annual Form 10-K for a more detailed discussion of risks factors.

This presentation will make reference to certain financial measures such as adjusted net income which are not recognized under GAAP, reconciliations to the most closely related GAAP measures are included in the slides that accompany this presentation. As mentioned, the slides are available in the Investors section of the partnership's website.

Please turn to slide 3 and I'll turn the conference over to Steve Letwin.

Steve Letwin

 

Thank you, Douglas, and I'd like to also extend welcome to Douglas in his new role, and I also want to thank Tracy Barker for his long service with the partnership. Tracy, you've done a great job for us, very diligent, always there to answer questions about the partnership, and we are certainly going to miss you. We wish you the best of luck in your new role at the partnership. So thank you from all of us here.

So, Terry McGill summarized the partnership's results very well in the news release, which I'm sure you all have a copy of. I want to echo his comment that results are running ahead of expectations this year. And of course nothing puts an exclamation point on an MLP's performance like a distribution increase and we suspect the $0.16 annualized increase approved by our Board for the August payment was a bit larger than most investors anticipated. And frankly, it was larger than contemplated in our initial 2008 budget. But that's a testament to the strong earnings being generated by the new assets we've commissioned over the past year.

We are also making excellent progress, building out our current slate of projects which we are confident will support further distribution increases over the next few years. Terry will have more to say on these projects a little bit later on. But if you turn to slide 4, Enbridge Inc is progressing on a number of crude oil transportation projects that we expect will benefit EEP. To bring you up to date on these, the Spearhead pipeline is on schedule to add 65,000 barrels per day of pipeline capacity to Cushing in late 2009.

The Southern Lights project is on schedule for completion in 2010. Its function will be to return 180,000 barrels per day of light hydrocarbons from Chicago to Alberta for use as diluent to transport heavy crude oil. Southern access extension is the planned 400,000 barrel-a-day project to link the partnership's future planning internal, with the pipeline hub at Patoka, Enbridge is currently working with shippers on a tolling methodology for the pipeline.

And barring any regulatory delays in finalizing this, service is expected to commence in 2009. Regarding the Texas access pipeline, Enbridge is continuing discussions with prospective shippers regarding the appropriate commercial terms and timing for this project. Given the slower ramp up of production growth and the latest forecast, Enbridge is also advancing a near term solution to the US Gulf Coast that involves the partnership more directly.

If you turn to slide 5, that project is named Trailbreaker. It involves expansion of our Line 6B from Chicago to the Ontario border, reversal of Enbridge's Line 9 to Montreal and reversal of a third-party pipeline in Portland, Maine. This will also increase service to refineries in Michigan, Ohio and Eastern Canada.

Additionally, access to the marine terminal at Portland will facilitate transit to US East Coast and Gulf Coast refineries. We're pretty exited about this opportunity because it provides capacity on an as-needed basis, and it involves existing assets so it can be completed at low cost and on a quick turnaround. Consequently, we have financial support from shippers to complete a feasibility review and a draft term sheet.

So, from each perspective, we see Line 6B as another of our valuable right of ways. We anticipate that supporting the future demand of the numerous refinery centers I just mentioned will require more capacity than the 200,000 barrel per day service that Trailbreaker will provide, and thus you create additional expansion opportunities for the partnership.

With those background remarks I'll hand off the talk to Terry, for his review of the partnership's business and operations and to Mark Maki for his financial commentary. Terry?

Terry McGill

 

All right, thanks, Steve, and welcome Douglas. I'll start with slide 6. Q2 was another good quarter for EEP and the highlight was the $0.16 annualized distribution increase as Steve mentioned.

We also had strong cash flow coverage of the increased distribution with 1.3 times coverage ratio, and we reached and all time high for quarterly adjusted earnings at $0.95 per unit. Mark will review the financial results in more detail. So let me skip to my usual review of operations and projects.

Starting on slide 7, we focused on our crude oil transportation and storage business. The partnership’s biggest opportunities stemmed from our strategic position as the final link between growing oil sands production in Western Canada and expanding refinery demand in the US. Together, Enbridge pipelines in Canada and our Lakehead System, delivered nearly 70% of Western Canadian crude production last year.

On slide 8, we show our forecast for growth and supply from Western Canada, which we see increasing more than 2 million barrels per day, between 2007 and 2017. Supply includes crude oil production plus condensate that is used as diluent to transport heavy grades of crude oil.

Our forecast is modestly higher but directionally consistent with the Pipeline Planning Case forecast released by the Canadian Association of Petroleum Producers or CAPP that was released in June. Both forecast are substantially lower than the simple aggregate of producer plans because they both discount for factors such as anticipated labor and material constraints and more conservative ramp up schedules.

Based on this forecast, we project that pipeline capacity from Western Canada, including currently approved expansions will be fully utilized by 2014 and further expansion at that time will be necessary.

On slide 9, we turn to the demand side of equation. The slide shows there's ample room for Canadian crude oil to capture a greater share of refinery demand in all the larger US Petroleum Administration for Defense Districts or PADD. For economic and security supply reasons, a number of refineries have announced plans to expand or reconfigure to take more feedstock from Western Canadian producers and we expect more such announcements in the future.

Lakehead Systems serves the largest traditional market for these producers in upper PADD II, and it is very well positioned to support market reach initiatives throughout PADD II, as well as to PADD III which is the Gulf Coast and PADD I which is the East Coast.

Turning to slide 10, our initial expansion to support increased crude flows from Western Canada to the US through the southern access expansion, its first stage was available for service on April 1st of this year. Second stage in on schedule to complete the 400,000 – it will complete the entire pipeline, the 400,000 barrel pipeline by the second quarter of next year. The project uses 42-inch diameter pipe and so it has an ultimate capacity of 1.2 million barrels per day.

Capital costs for Stage 1 were approximately $1.3 billion and Stage 2 should run about $800 million. 88% percent of the final capital costs go into the rate base under the tariff agreement for the expansion. As we have indicated before, the terms for this project are very MLP friendly through its predictable stable regulatory arrangement. It is a 30-year agreement under which EEP will earn a 9% real return on equity plus inflation, plus tax allowance.

As a full cost to service agreement, we will recover our costs and collect our full return via surcharge on all barrels shipped on the Lakehead System. This effectively protects us from crude oil supply volatility over which we have no control.

Slide 11 shows a sample of the surcharge mechanism in action. The green bands on the chart represent a facility surcharge that includes approximately $0.30 for light crude transportation related to the new Southern Access Stage 1 facilities. This combines with preexisting Lakehead System base rate and expansion surcharges to form the transportation rate that applies to all barrels shipped on the system.

The Southern Access surcharge took effect on April 1 but did not apply to shipments that are already in transit. That means Q3 is the first quarter in which we will have a full quarter that the rate is in effect the entire time. The chart also reflects new Lakehead tariffs that took effect on July 1. That’s the date on which we adjust for facilities operated under FERC index tolling methodology. This year, the Lakehead base rate was increased about 8% while the North Dakota base rate in Mid-Continent Ozark System rates were increased about 5%.

Turning to slide 12, our next expansion of the crude oil main line is underway. The $1.2 billion Alberta Clipper pipeline will be a 36-inch diameter pipeline between Alberta and Superior, Wisconsin with capacity of 800,000 barrels per day. By mid 2010, an initial 450,000 barrels per day will be provided and available. The commercial terms we negotiated with shippers for Alberta Clipper were filed with the FERC in June. A copy of the offer for settlement is available from EEP or the FERC Web sites. We anticipate receiving all regulatory approvals in time to start construction later this year.

The terms are very well suited to an MLP portfolio. As a 15-year agreement with a renewal provision, it provides the partnership with long-term stability. At a full cost of service type arrangement, it protects us from supply risk. Returns are base on FERC's trended original cost model, using a 55% deemed equity component in the rate base. ROE is set at the Canadian multi pipeline rate, plus 2.25%, so currently about 11% plus tax allowance that would be collected based on the then-allowed FERC rates.

The financial terms for Alberta Clipper do contain a bit more risk-reward potential than those for Southern Access, once such item is risk-sharing for controllable capital costs during construction. We have negotiated a formula set out in the offer settlement by which we increased rate base for capital cost savings and decrease it for overruns.

On the downside, we estimate that a 20% overrun would reduce ROE by roughly 75 basis points. However, we are fairly comfortable that our exposure is limited since we have recent major project construction experience to draw upon.

The Phase 6 expansion, now moving to North Dakota, the Phase 6 expansion on slide 13 of our North Dakota System is waiting regulatory approvals, which we anticipate will be received on a timely basis so that the 51,000 barrels per day of incremental capacity will be available by early 2010. This includes FERC approval of our offered settlement filing, which was not contested. The offer proposes a surcharge at all system lines that would recover capital cost of the estimated $150 million project over seven years.

We are in continuing discussions with producers in the region regarding additional energy transportation requirements. Advances in recovery techniques have led to a resurgence in drilling in the Bakken area in North Dakota, and in April, the USGS increased its estimate of undiscovered, technically recoverable reserves in this formation by 25 times to between 3 billion and 4.3 billion barrels of oil.

Starting on slide 14, we will turn to the natural gas business, which is primarily focused on the Anadarko, Fort Worth and East Texas basins. Combined throughput for these systems was up 17% compared with the year ago levels, as we've been very active tying in new producer wells.

We've also been responding to producer needs to process raw natural gas to meet increasingly stringent downstream pipeline specs. Processing plant additions over roughly the past three years has increased our capacity to approximately 1.2 BCF per day. The capacity is heavily utilized and we are reviewing opportunities for additional expansions.

On slide 15, show a recent update of forecast natural gas production covering some 55 counties in which we operate. The forecast is based on fairly conservative assumptions and projects a 1% to 2% annual growth rate through 2014. We expect to exceed this rate for a number of reasons, including the opportunities to expand our footprint. And good exposure to unconventional gas plays that are not yet fully delineated such as the outskirts of the Barnett Shale and Haynesville Shale, the Bossier sands, the deep Bossier formations, all of these are still waiting to see where these systems will actually end.

The application of new technology to these existing areas and the new areas such as the Anadarko basin is really a boost to the recovery and the deliverability that we're experiencing.

Our final slide is slide 16 which maps our principal East Texas assets. Here we're completing the final stages of our 700 million a day Clarity transmission system. This primarily involves tie-in to the Florida Gas interstate system, which we expect we'll be delivering into by November. We also completed tie-in of a new wholesale customer in July which will help volumes in Clarity continue to build in the third quarter.

Finally, we expect increased contributions as volumes build at our newer plants. This includes the 200 million a day CO2 trader at Marquez, the 125 million a day asset gas injection facility at Aker that's just been completed and the three hydrocarbon Dupoint [ph] control plants added last year.

So, on conclusion, we're making good progress in our growth projects and continue to identify new opportunities in both our crude oil and natural gas businesses. This bodes well for enhanced returns to our investors over the long term.

And now for more detail, we'll turn it over to Mark Maki for the financial results.

Mark Maki

Thank you, Terry and Steve Letwin, for your comments as it relates to Tracy. I worked with Tracy for better part of 20 years here at EEP or other entities in the Enbridge family and certainly absolutely value his contributions to the company over the years and look forward to his contributions in his new role here at EEP.

For my remarks, let's start with slide 17. At the top of the slide we show operating income contributions by business segment, with volatility FAS133 mark to market valuations removed.

Each of the business segment shows significantly improved results and in total, adjusted operating income is $66 million higher than the second quarter of last year. I'll review the individual operating second quarter results in a moment.

At the bottom of the slide, we show adjusted EBITDA which also improved up approximately 84 million to 211 million for the quarter. We explained the $30 million increase in interest expense in some detail in the news release, but fundamentally the increase was more than offset bearings from new assets that come in service.

Other income increased about $2 million due to two roughly equal items, first being interest expense on surplus cash invested during the quarter and the recovery of a previously written down receivable in our gas unit. The bottom line as Terry mentioned was a new all time high for us at $0.95 per unit.

On slide 18 we focused on the liquid segment, where operating income was roughly $90 dollars or double the second quarter of 2007. Looking at the components of operating income, operating revenue improved by almost $60 million due to a number of factors including a new surcharge with our $0.30 per barrel for light crude service, related to the start-up of the first phase, the southern access project on April first.

Material surcharge for North Dakota phase 5 expansion that took effect on January 1, the FERC index total adjustments effective July 1 last year for three liquid systems, 4.6% increase in delivery volumes and higher oil prices applying to oil collected under our carriers as compensation for transportation services, are roughly $7 million.

Power cost increase 4 million, the increase was primarily to the increased of delivery volumes and higher utility rates, they are charged by our power suppliers. Depreciation expense was up $10 dollars, largely attributable to new assets, in particular the Southern Access Expansion.

Turning to natural gas segment in slide 19, its contribution to adjusted operating income was 60.5 million, roughly $19 million higher than the second quarter of 2007. Reading the breakdown of that increase, gross margin increase almost $41 million for both volume and price reasons,

Throughput of on our three largest systems was up 17%, natural gas prices were very strong during the quarter, for example natural gas climbed to briefly above $13 as well liquids prices were stronger. And we benefit from higher pricing on the portion of our natural gas link and natural gas liquids link that is not hedged.

The stronger natural gas prices though did attract some from processing margins, however, we are up roughly $8 million on POL (percentage of liquids) processing and flat on a key (inaudible) basis due to increase volumes. That performance is partially offset by $16 million increase in OE expenses, primarily workforce related cost, maintenance activities, materials and supplies and so forth, the increases were in line with higher systems throughput and increase processing plant capacity and compression units that we commissioned since last year.

Depreciation expense was up, up roughly $6 million as a result of natural gas projects that was completed since last year. Marketing group reported just an operating income of 4.4 million an increase of 2.1 million compared with one year ago. And this increase stemmed primarily from our enhanced ability to access premium markets. For example the quarry expansion is alleviating some of the capacity bottlenecks in our East Texas system that required marketing to move gas to less permeable markets last year.

In slide 20, we break our keep-whole processing since its one of the more volatile parts of our business. The volume we process under keep-whole arrangements was up around 50 million cubic feet a day from second quarter last year, primarily due to the capacity that we've added and partially due to the refurbishing of the Zyback plant during the second quarter of last year. The gain was offset by lower after hedging margin with the net result that are keep-whole contribution was flat at about $17 million.

The next slide shows our calculation and distribution coverage, and we consider the year-to-date as declared calculation to be the most relevant. On that basis, DCF exceeded distributions by 1.26 times. As reminders we include our pay-in-kind distributions as if they were paid in cash and our as-declared calculations associate distributions with the quarter in which they are earned, rather than the quarter in which they were paid.

Our book capitalization is shown on slide 22 with standard adjustments for other comprehensive income or OCI, and hiber [ph] securities that are noted on the slide. Total debts, total cap was 50% at quarter end. In terms of floating rate, debt outstanding as of June 30 we had a $100 million outstanding on commercial paper at an average interest rate of 3.1% we had $250 drawn on a revolver and an average rate of 2.9% as well we had approximately $300 million outstanding on letters of credit. This left us around 600 million available under our 1.25 billion standby regular credit facility and we have access to $500 million more on a standby line through our general partner.

Slide 23 shows our CapEx year to date maintenance CapEx is 32.1 million, on enhancement CapEx is 640 million. The largest components of the enhancement CapEx include 410 million for Southern Access followed by 32 million for the Alberta Clipper project.

Slide 24 shows our estimated capital expansion commitments going forward, which we find (inaudible) modestly since our last earnings call. First, we've increased our 2008 estimate by approximately $300 dollars to 1.7 billion in total. This is largely due to some acceleration of the anticipated spin pattern for Southern access stage 2, plus the addition of a few smaller natural gas projects that we anticipate moving forward in the fairly near future.

On balance though, there is no net change in 2009 or 2010 estimates, as it relates to the large projects. In these estimates we've included projects that are commercially secure, although we feel fairly certain are going to proceed as usual we have an inventory of less well developed projects that could add to current estimates. A good example of this is the Trailbreaker project that Steve described in the opening comments. It's not included yet, but looks very promising.

Finally in slide 25, we've indicated that we've increased our estimate portfolio earnings by about $60 million, we now anticipate that adjusted net income for the year will finish between the range of 370 and 400 million. First half results did exceed our expectations and major factors included the value of unhedged commodities, volume growth, continued strong processing fundamentals that would continue to benefit us for the second half of the year. That covers my prepared remarks, let’s take questions from the analysts. Latonia, could you please open the phone lines.

Question-and-Answer Session

Operator

 

We will now conduct a question and answer session. (Operator instructions) Our first question comes from Sharon Lu from Wachovia Securities. Please proceed with your question.

Sharon Lu – Wachovia Securities

 

Hi, good morning. This question is in regards to the Alberta Clipper, I noticed that the cost is a little bit higher than your original estimates. Is that just a function that the old estimate was based on 2007 cost?

Terry McGill

 

Yes we're basically picking up now more nominal dollars and that's being reflected, Sharon.

Sharon Lu – Wachovia Securities

 

Okay. Also if you could provide an update on your equity financing needs, I think that your original budget had assume some asset sales about 260 million, can you just provide an update?

Terry McGill

 

The budget we had posted at the end of the year, not so many assets sales, that's always an option that we could go to, as source of financing, as far as our cord [ph] financial plans. We turn to John Rose here, our treasurer.

John Rose

 

For the balance of 2008, we do have some equity capital needs in the range of probably $200 to $300 million. And we'll be looking to take advantage of a market window that would present itself in the back half of this year. But we do have available liquidity to us to manage ourselves through more difficult markets such as the markets we're seeing today.

Sharon Lu – Wachovia Securities

Okay. Thank you.

Operator

 

Our next question comes from Gabe Moreen, Merrill Lynch. Please proceed with your question.

Gabe Moreen – Merrill Lynch

Hi, good morning. In terms of the oil allowances this quarter as well as the favorable measurements, is it possible to quantify that in kind of year over year, what the differential was there?

Terry McGill

 

The allowance revenue difference was around $7 million relative to the second quarter of last year and that’s largely due to the run up in commodity prices. So, if we take very small fraction of the oil that's transported in our system, as compensation, most of our RPs are based on it is just key reserves, you take some oil as compensation and we sell that back, so that's the difference year over year.

Oil losses is usually is a variety of different factors, that really lay in to that, but as far as quarter over quarter, modest difference and I wouldn't say much more than that at this point.

Gabe Moreen – Merrill Lynch

 

Okay. And then on the processing side, looks like your processing volumes were way up, quarter over quarter sequentially but your key – your NGL production in terms of your equity NGL was actually down sequentially, can you talk about that? Were you doing rejection or something on those lines?

Terry McGill

 

No. One thing that's different if you're talking from Q1 to Q2 we do have some contracts that are migrating away keep-whole to percentage of liquids, so we have some lift in POL barrels and some drop off in keep-whole, that's probably the item that you're catching with your analysis.

Gabe Moreen – Merrill Lynch

 

Okay. And then finally, I wonder if Terry can maybe talk about some of the more exciting place in the natural gas world over the last couple of months in terms of exposure to the Haynesville, what you're seeing in East Texas and whether your Louisiana systems also have any exposure there as well?

Terry McGill

 

Yes, of course it's all been pretty exciting down here in Houston on this, the Haynesville is just would say, Audrey McLanan was quoted as saying, "Could have up to TCF or reserves." Our system sits over by syntaxes, but the belief is the Haynesville crosses to the areas of the red rivers, (inaudible) bend area, and comes in to the Texas of which we, the eastern part of our system Shelby County, Harrison County, were already here. So were starting to see some of the effects of the Haynesville showing up in our systems.

But there's not a lot of well drilled in to the Haynesville yet. There've been good results, but there needs to be a lot more activity to delineate that field and really get the attributes of that field defined. But it is certainly promising, and you see the prices people are paying, break ridge of $13,000 to $15,000 an acre, yes, there’s a lot of people who believes it's the place to be.

The Barnett, we see it continue to grow from the Barnett, it's moved south and starting to move a little bit west. They got the drilling down to a science under flex rigs, so we're seeing a – growth was on the North Texas but a lot of that is forward basin Barnett production, so we're seeing the growth there also.

We're not in the wood with Fayetteville, those of further north. And of course Marseille is in Pennsylvania so we know we're close to Marseille’s but the Haynesville is the one the one that we kind of tickle on the edge and we have plans on moving in to that area.

Gabe Moreen – Merrill Lynch

 

Okay, great. Thanks, Terry.

John Rose

 

I can give one of their follow up on your NGL question, the other thing that would have affected the quarter’s production, we hit of the key facility, NGL line going out of it down for hydrotesting service, and that also affected some of our production. That's the other item that would be notable.

Operator

 

(Operator instructions) Our next question comes from Bryan Sarom [ph] from Lehman Brothers. Please proceed with your question.

Bryan Sarom – Lehman Brothers

 

Good morning. Could you comment on the sequential decline in the Lakehead system deliveries despite the (inaudible) of an access project from your line?

Terry McGill

 

You want to fill that or you want to me to take a crack at it?

Steve Wuori

 

Sure, well I think we've seen a number of upstream issues in the oil sands with some of the plants, the new plants coming on, the SAGD operations of the steam-assisted gravity drainage has taken more time than expected to see those volumes come on, and the Southern Access phase 1, the tolls [ph] were applied, the line fill of that will occur between now and when the phase 2 is completed, when it would go on to flowing service and so, you wouldn't have seen any effect of that capacity yet, because there isn't the line fill that yet in the system to fill that line. So, you wouldn't have seen any effect yet, that'll be later on.

Terry McGill

 

The other thing worth noting is if for some reason the volume forecast for the year is below, what we had anticipated when we filed the tariff, we'll just treat that up next year, as it relates to our cost for Southern Access, so to an extent we under-collect this year, it gets billed in the next year's toll surcharge, and it's collected then. Our volumetric exposure really in the company is not quite the same as it was say two, three years ago.

Bryan Sarom – Lehman Brothers

 

Okay. In terms of the guidance you provided early in the year, that is still – you are still looking at that?

Terry McGill

 

That’s probably little on the high side, if I was going to reguide in that particular point, I'll take it down some from what we had at the beginning of the year.

Bryan Sarom – Lehman Brothers

Thank you.

Operator

 

Our next question comes from Sean Grant with Zimmer Lucas Capital. Please proceed with your question.

Sean Grant – Zimmer Lucas Capital

 

Hi! Good morning guys. Congratulations on the quarter. Two questions, one on the fuel and power cost in the liquid system, where do you see those trending with higher commodity prices, and then two, if you could give us a fill of the, if you've updated the deck that you're using with the new (inaudible).

Terry McGill

 

The OE [ph] guidance reflects our current fairly recent look at cash commodity prices of later extremely lower crudes at 3 bucks today day, but one thing to keep in mind with our business, is we do hedge substantially our exposures.

We’ve got some exposure to commodity price, but it's not large, roughly 70% our margin is hedged on the places we have (inaudible). As relates to your power question – because of the input cost, coal, natural gas, we are seeing rates of power cost increase, which exceed the general rate of inflation and it's very regional, depends on the type of production and each of the locations it goes through, again we cover a big geographic area, such all kinds different power producers, but generally speaking, that does – the rate of increase exceeds the rate of inflation, now one good thing again with tolling arrangements that we have now whether it’s Southern Access or Alberta Clipper or the North Dakota expansions, our cost of service arrangements, sort of the extent you got, basically modeling your incremental power and that's what gets included in the terra.

Sean Grant – Zimmer Lucas Capital

 

Okay, great! Thanks.

Operator

 

Our next question comes from Winfried Fruehauf from Fruehauf Consulting. Please proceed with your question.

Winfried Fruehauf – Fruehauf Consulting

 

Thank you, good morning. I have a question on Trailbreaker, assuming that project already go ahead and we're in operation today, what would be the overall toll from Alberta to the Gulf Coast?

Steve Wuori

 

Good morning Winfred, it's Steve Wuori, I'll take that one, that one is not yet tied down, there's a number of moving variables there, including the cost of the Line 6B expansion on the East [ph] system, line 9 reversal and then the Portland pipeline reversal as well as tanker rates between Portland and the gulf coast, so I don't think we're prepared to pin a number down yet, because there are those moving pieces, but something in the $8 range with a pretty wide band around that is probably note a bad proxy for where it many end up, but again, I cautioned that that is not something that is definitive because of the variables that I talked about.

Winfried Fruehauf – Fruehauf Consulting

Thank you, and another hypothetical, assuming your Texas access project were to go ahead and were on operation today. What would be the toll from Alberta to the Gulf Coast for that project, roughly?

Steve Wuori

 

Well, there you run in to some of the same variables, but I think that in all of these cases, we are talking about tolls in that same range, but less probably because Texas access is a high volume solution to the Gulf Coast, whereas the Trailbreaker is something on the order of less than 200,000 barrels a day Texas access, ultimately can deliver up to 800,000 barrels a day. So you would see a lower toll on Texas access than you would on the Trailbreaker system.

And that's why, they really don't compete against one another, because Trailbreaker is two years ahead of any solution to the Gulf Coast, including Texas access, so it really is more of a timing and optionality play as opposed to a toll on toll competition. But certainly the higher volume toll more direct to the gulf coast in Texas access will be lower, than the Trailbreaker toll.

Winfried Fruehauf – Fruehauf Consulting

And if Texas access was in operation, would be built – is it possible that Trailbreaker might still operate as a supplementary system, delivering smaller volumes to the Gulf Coast or anywhere in the East coast?

Steve Wuori

 

Yeah, I think the thought with trailbreaker is that once Texas access goes into service and takes the bulk of the heavy movements to the gulf coast, trailbreaker could move synthetic crudes from the oil sands into the Philadelphia Delaware river refining area in PADD 1, so that's really the optionality that's provided there, is that it can move heavy oil in the early years and then synthetic oil in the later years, and there's still is the optionality around spot movements of heavy oil after that point in time. But certainly Texas access would be intended to take the bulk of the heavy movements on a regular basis to the gulf.

Winfried Fruehauf – Fruehauf Consulting

And final question, if trailbreaker were to go ahead, who would be responsible for chartering the tankers would it be EEP or Enbridge?

Steve Wuori

 

That's yet to be worked out, it maybe neither EEP nor Enbridge. That certainly has to be worked out with the Portland Montreal pipeline ownership partners, they really have responsibility for the reversal of that pipeline as well as the dock operations at Portland, so I do not think that EEP or Enbridge would be directly responsible for that.

Winfried Fruehauf – Fruehauf Consulting

Thanks very much.

Steve Wuori

 

Thank you.

Operator

 

(Operator instructions) Our next question comes from Brad Siegel [ph] with Aurora Capital. Please proceed with the question.

Brad Siegel – Aurora Capital

 

Thank you, I have two questions, and one is best of luck Tracy, I've enjoyed working with you as well.

Tracy Barker

 

Thank you.

Brad Siegel – Aurora Capital

 

And two questions are, one is – as relates to SEM group, is there opportunity for you to capture incremental business and how are you thinking about it?

Steve Letwin

 

It’s Steve Letwin here, I think everybody is looking at SEM [ph] group right now, trying to figure out whether or not, there might be some opportunities and we would be one of those parties as well. So, we are looking at it, we are evaluating it. We haven't reached any conclusions, but certainly we're taking a look at it.

Brad Siegel – Aurora Capital

 

Okay. And the second question is, Mark I apologize, but did you go over exactly how much of the processing business is hedged right now?

Mark Maki

 

Roughly 70%.

Brad Siegel – Aurora Capital

 

Okay, got it. I do want to ask one other question. When you look at the financing needs for this year, and that you are running above budget, how does that play in to your hands, in to your thinking as it relates to excess cash flow being able to mitigate the amount of equity, you might have to raise?

Mark Maki

 

What we have done over the last number of years is laid out, cash whole metric targets and other targets with the rating agencies, as we've stated repeatedly over the years are triple BBB mid ratings is very important to us, so we manage our capital needs in accordance to the targets that we set out with the rating agencies, as we see more cash flow being generated off our assets, obviously that could have lead some portion of equity financing that will be required, because that cash flow would go to service, the debt that we've got, notwithstanding whether this is interim debt at this point. So it could serve to either replace or defer the timing of particular equity needs.

Brad Siegel – Aurora Capital

 

Great. Okay, thank you very much.

Operator

 

Our next question comes from Ross Payne with Wachovia Securities. Please proceed with your question.

Ross Payne – Wachovia Securities

 

Yeah, just a couple of question, obviously you're doing the landfill now in Southern Access, when you expect incremental tariffs to be realized, and how quick will that ramp up be? Thank you.

Terry McGill

 

They're already being realized now, Ross. I mean they're basically in… every barrel that moves in the system is effectively paying some of access today, whether the line is filled, or moving or not.

Mark Maki

 

That's the $0.30 we were talking about.

Terry McGill

 

Yeah, so the only thing I would say is, in the second quarter, it's very rough approximation, but the month of April would have been under old tariffs and then May and June would have been under new… I think it's very roughly… 3 weeks, 4 weeks to pump the system, to get all the old barrels out and new barrels earning the surcharge.

Ross Payne – Wachovia Securities

 

Okay, okay, so at that point, you are 100% of the 30% additional.

Terry McGill

 

Yeah, $0.30 additional.

Ross Payne – Wachovia Securities

 

Thirty cents, yeah.

Terry McGill

 

Rough round numbers, it depends, if you move a barrel shorter on the system, it pays less, if goes longer it pays more, it it’s a heavy barrel it pays more, those kind of things.

Ross Payne – Wachovia Securities

 

Okay, great, thanks guys.

Operator

 

We have a follow up question from Shawn Wells with RBC Capital Markets; please proceed with your questions.

Shawn Wells – RBC Capital Markets

 

Good morning guys, I have a question on the TransCanada's competing pipelines to the Gulf Coast, apparently it received backing from Valero [ph] and I was wondering, what if any impact that has had on the Texas access pipeline or your plans for the Texas Access pipeline.

Steve Wuori

 

Yes, it's Steve Wuori here, I can't confirm who the support would be from that was announced when they announced the open season for the project to the Gulf Coast, I think our view is, as we study the ramp up in production, coming out of the oil sands being slower than it was a year ago, by 200,000 to 300,000 barrels a day it really has caused us to focus on what we think is the best answer for the industry which is a phased approached, that has the Trailbreaker project moving heavy volumes to the Gulf early starting in 2010 and then Texas Access after that, ramping up from anywhere from 400,000 to 800,000 barrels a day if the market is there to support that. So, we really feel that that offer is the lowest cost and the greatest flexibility to the industry and that's what we're going to keep focusing on.

Shawn Wells – RBC Capital Markets

 

Okay, and I have just one more question, and it has to do with the latest information regarding the size and potential production coming out of the back information, with your plans for stage 6, I was wondering, do you think you might be a little too conservative with your plant's increase capacity by 15,000 barrels per day, do you think that's right sizing it or do you think you might be a little too conservative on that?

Steve Wuori

 

That's a great a question and I don't think it is right-sized, I think it is too small, but that pushes the existing pipe to its limit. And so, we also have discussions underway about other options to pipe more volume coming out of the back and as the potential certainly appears to be there, but what we're doing with this stage expansion is really maxing out the capacity of the existing system completely, to make sure that that's available for the industry, while we work on other solutions that can come out of there. But it's a great question.

Shawn Wells – RBC Capital Markets

 

Okay, thanks guys. That's all I have.

Operator

 

There are no further questions in queue at this time; I'd like to turn the floor back over to Mr. Barker for closing comments.

Tracy Barker

 

Thanks everyone for joining us in the call today, just a few reminders as we conclude, in the supplemental slides to this presentation, you'll find reconciliations for the non-GAAP measures that we referred to in our remarks.

And for those in the webcast, these slides are being scrolled as we wrap up, as a reminder of materials from this call are also posted on enbridgedpartners.com/q, which is our one stop webpage for earnings release materials. We'll have the call transcript and a downloadable audio replay as soon as they're available, we expect by the end of business today. And as usual, we're available in Houston for any follow-up calls you may have, I thank you for joining us and have a good day.

Operator

 

This concludes today's teleconference; you may disconnect your lines at this time, thank you for your participation.

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Source: Enbridge Energy Partners, L.P. Q2 2008 Earnings Call Transcript
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