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

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Enbridge Energy Partners, L.P. ( 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
Presentation
Operator
Greetings and welcome to the Enbridge Energy Partners secondquarter 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. Thankyou Mr. Barker, you may begin.
Tracy Barker
Thank you, Latonia and good morning everyone. Welcome to the 2008second quarter conference call for Enbridge Energy Partners. Ifyou've not already done so and want a copy of the slides, condensedfinancial 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 tradingsymbol which is EEP. The partnership's results are also directlyrelevant to Enbridge Energy Management, trading symbol EEQ, whichprovides a vehicle to invest in the partnership through companyshares.
We have online as our speakers today from the general partner;Steve Letwin, Managing Director; Terry McGill, President; and MarkMaki, Vice President, Finance. Available for the Q&A session,we have Steve Wuori, Enbridge's Executive Vice President, LiquidsPipelines; Jonathan Rose, the partnership's Treasurer; and SteveNeyland, Controller for the partnership.
I would also like to introduce Douglas Montgomery who willtransition into the role of Director of Investor Relations bySeptember 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 foreight years; I've been based in Columbia, Calgary, and mostrecently Spain, and now I'm joining the partnership at a prettyexciting time in its history. I had the opportunity to meet anumber of our analysts and investors at the MLP Conference in May.I look forward to meeting and working with many more of you overthe coming weeks. My first official duty is to read our legalnotice for the record and it goes as follows.
Certain information during this presentation will constituteforward-looking statements. These will include but are notnecessarily limited to throughput volumes, financial projections,expansion or acquisition projects, external economics andcompetitive factors. These statements are based on certainassumptions made by the management. Accordingly, actual results maydiffer materially from current estimates. You are referred toEnbridge Energy Partners SEC filings including the annual Form 10-Kfor a more detailed discussion of risks factors.
This presentation will make reference to certain financial measuressuch as adjusted net income which are not recognized under GAAP,reconciliations to the most closely related GAAP measures areincluded in the slides that accompany this presentation. Asmentioned, the slides are available in the Investors section of thepartnership's website.
Please turn to slide 3 and I'll turn the conference over to SteveLetwin.
Steve Letwin
Thank you, Douglas, and I'd like to also extend welcome to Douglasin his new role, and I also want to thank Tracy Barker for his longservice with the partnership. Tracy, you've done a great job forus, very diligent, always there to answer questions about thepartnership, and we are certainly going to miss you. We wish youthe best of luck in your new role at the partnership. So thank youfrom all of us here.
So, Terry McGill summarized the partnership's results very well inthe news release, which I'm sure you all have a copy of. I want toecho his comment that results are running ahead of expectationsthis year. And of course nothing puts an exclamation point on anMLP's performance like a distribution increase and we suspect the$0.16 annualized increase approved by our Board for the Augustpayment was a bit larger than most investors anticipated. Andfrankly, it was larger than contemplated in our initial 2008budget. But that's a testament to the strong earnings beinggenerated by the new assets we've commissioned over the past year.
We are also making excellent progress, building out our currentslate of projects which we are confident will support furtherdistribution increases over the next few years. Terry will havemore to say on these projects a little bit later on. But if youturn to slide 4, Enbridge Inc is progressing on a number of crudeoil transportation projects that we expect will benefit EEP. Tobring you up to date on these, the Spearhead pipeline is onschedule to add 65,000 barrels per day of pipeline capacity toCushing 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 lighthydrocarbons from Chicago to Alberta for use as diluent totransport heavy crude oil. Southern access extension is the planned400,000 barrel-a-day project to link the partnership's futureplanning internal, with the pipeline hub at Patoka, Enbridge iscurrently working with shippers on a tolling methodology for thepipeline.
And barring any regulatory delays in finalizing this, service isexpected to commence in 2009. Regarding the Texas access pipeline,Enbridge is continuing discussions with prospective shippersregarding the appropriate commercial terms and timing for thisproject. Given the slower ramp up of production growth and thelatest forecast, Enbridge is also advancing a near term solution tothe US Gulf Coast that involves the partnership more directly.
If you turn to slide 5, that project is named Trailbreaker. Itinvolves expansion of our Line 6B from Chicago to the Ontarioborder, reversal of Enbridge's Line 9 to Montreal and reversal of athird-party pipeline in Portland, Maine. This will also increaseservice to refineries in Michigan, Ohio and Eastern Canada.
Additionally, access to the marine terminal at Portland willfacilitate transit to US East Coast and Gulf Coast refineries.We're pretty exited about this opportunity because it providescapacity on an as-needed basis, and it involves existing assets soit can be completed at low cost and on a quick turnaround.Consequently, we have financial support from shippers to complete afeasibility review and a draft term sheet.
So, from each perspective, we see Line 6B as another of ourvaluable right of ways. We anticipate that supporting the futuredemand of the numerous refinery centers I just mentioned willrequire more capacity than the 200,000 barrel per day service thatTrailbreaker will provide, and thus you create additional expansionopportunities for the partnership.
With those background remarks I'll hand off the talk to Terry, forhis review of the partnership's business and operations and to MarkMaki for his financial commentary. Terry?
Terry McGill
All right, thanks, Steve, and welcome Douglas. I'll start withslide 6. Q2 was another good quarter for EEP and the highlight wasthe $0.16 annualized distribution increase as Steve mentioned.
We also had strong cash flow coverage of the increased distributionwith 1.3 times coverage ratio, and we reached and all time high forquarterly adjusted earnings at $0.95 per unit. Mark will review thefinancial results in more detail. So let me skip to my usual reviewof operations and projects.
Starting on slide 7, we focused on our crude oil transportation andstorage business. The partnership’s biggest opportunitiesstemmed from our strategic position as the final link betweengrowing oil sands production in Western Canada and expandingrefinery demand in the US. Together, Enbridge pipelines in Canadaand our Lakehead System, delivered nearly 70% of Western Canadiancrude production last year.
On slide 8, we show our forecast for growth and supply from WesternCanada, which we see increasing more than 2 million barrels perday, between 2007 and 2017. Supply includes crude oil productionplus condensate that is used as diluent to transport heavy gradesof crude oil.
Our forecast is modestly higher but directionally consistent withthe Pipeline Planning Case forecast released by the CanadianAssociation of Petroleum Producers or CAPP that was released inJune. Both forecast are substantially lower than the simpleaggregate of producer plans because they both discount for factorssuch as anticipated labor and material constraints and moreconservative ramp up schedules.
Based on this forecast, we project that pipeline capacity fromWestern Canada, including currently approved expansions will befully utilized by 2014 and further expansion at that time will benecessary.
On slide 9, we turn to the demand side of equation. The slide showsthere's ample room for Canadian crude oil to capture a greatershare of refinery demand in all the larger US PetroleumAdministration for Defense Districts or PADD. For economic andsecurity supply reasons, a number of refineries have announcedplans to expand or reconfigure to take more feedstock from WesternCanadian producers and we expect more such announcements in thefuture.
Lakehead Systems serves the largest traditional market for theseproducers in upper PADD II, and it is very well positioned tosupport market reach initiatives throughout PADD II, as well as toPADD III which is the Gulf Coast and PADD I which is the EastCoast.
Turning to slide 10, our initial expansion to support increasedcrude flows from Western Canada to the US through the southernaccess expansion, its first stage was available for service onApril 1 st of this year. Second stage in on schedule to complete the 400,000– it will complete the entire pipeline, the 400,000 barrelpipeline by the second quarter of next year. The project uses42-inch diameter pipe and so it has an ultimate capacity of 1.2million barrels per day.
Capital costs for Stage 1 were approximately $1.3 billion and Stage2 should run about $800 million. 88% percent of the final capitalcosts go into the rate base under the tariff agreement for theexpansion. As we have indicated before, the terms for this projectare very MLP friendly through its predictable stable regulatoryarrangement. It is a 30-year agreement under which EEP will earn a9% real return on equity plus inflation, plus tax allowance.
As a full cost to service agreement, we will recover our costs andcollect our full return via surcharge on all barrels shipped on theLakehead System. This effectively protects us from crude oil supplyvolatility over which we have no control.
Slide 11 shows a sample of the surcharge mechanism in action. Thegreen bands on the chart represent a facility surcharge thatincludes approximately $0.30 for light crude transportation relatedto the new Southern Access Stage 1 facilities. This combines withpreexisting Lakehead System base rate and expansion surcharges toform the transportation rate that applies to all barrels shipped onthe system.
The Southern Access surcharge took effect on April 1 but did notapply to shipments that are already in transit. That means Q3 isthe first quarter in which we will have a full quarter that therate is in effect the entire time. The chart also reflects newLakehead tariffs that took effect on July 1. That’s the dateon which we adjust for facilities operated under FERC index tollingmethodology. This year, the Lakehead base rate was increased about8% while the North Dakota base rate in Mid-Continent Ozark Systemrates were increased about 5%.
Turning to slide 12, our next expansion of the crude oil main lineis underway. The $1.2 billion Alberta Clipper pipeline will be a36-inch diameter pipeline between Alberta and Superior, Wisconsinwith capacity of 800,000 barrels per day. By mid 2010, an initial450,000 barrels per day will be provided and available. Thecommercial terms we negotiated with shippers for Alberta Clipperwere filed with the FERC in June. A copy of the offer forsettlement is available from EEP or the FERC Web sites. Weanticipate receiving all regulatory approvals in time to startconstruction later this year.
The terms are very well suited to an MLP portfolio. As a 15-yearagreement with a renewal provision, it provides the partnershipwith long-term stability. At a full cost of service typearrangement, it protects us from supply risk. Returns are base onFERC's trended original cost model, using a 55% deemed equitycomponent in the rate base. ROE is set at the Canadian multipipeline rate, plus 2.25%, so currently about 11% plus taxallowance that would be collected based on the then-allowed FERCrates.
The financial terms for Alberta Clipper do contain a bit morerisk-reward potential than those for Southern Access, once suchitem is risk-sharing for controllable capital costs duringconstruction. We have negotiated a formula set out in the offersettlement by which we increased rate base for capital cost savingsand decrease it for overruns.
On the downside, we estimate that a 20% overrun would reduce ROE byroughly 75 basis points. However, we are fairly comfortable thatour exposure is limited since we have recent major projectconstruction experience to draw upon.
The Phase 6 expansion, now moving to North Dakota, the Phase 6expansion on slide 13 of our North Dakota System is waitingregulatory approvals, which we anticipate will be received on atimely basis so that the 51,000 barrels per day of incrementalcapacity will be available by early 2010. This includes FERCapproval of our offered settlement filing, which was not contested.The offer proposes a surcharge at all system lines that wouldrecover capital cost of the estimated $150 million project overseven years.
We are in continuing discussions with producers in the regionregarding additional energy transportation requirements. Advancesin recovery techniques have led to a resurgence in drilling in theBakken area in North Dakota, and in April, the USGS increased itsestimate of undiscovered, technically recoverable reserves in thisformation by 25 times to between 3 billion and 4.3 billion barrelsof oil.
Starting on slide 14, we will turn to the natural gas business,which is primarily focused on the Anadarko, Fort Worth and EastTexas basins. Combined throughput for these systems was up 17%compared with the year ago levels, as we've been very active tyingin new producer wells.
We've also been responding to producer needs to process raw naturalgas to meet increasingly stringent downstream pipeline specs.Processing plant additions over roughly the past three years hasincreased our capacity to approximately 1.2 BCF per day. Thecapacity is heavily utilized and we are reviewing opportunities foradditional expansions.
On slide 15, show a recent update of forecast natural gasproduction covering some 55 counties in which we operate. Theforecast is based on fairly conservative assumptions and projects a1% to 2% annual growth rate through 2014. We expect to exceed thisrate for a number of reasons, including the opportunities to expandour footprint. And good exposure to unconventional gas plays thatare not yet fully delineated such as the outskirts of the BarnettShale and Haynesville Shale, the Bossier sands, the deep Bossierformations, all of these are still waiting to see where thesesystems will actually end.
The application of new technology to these existing areas and thenew areas such as the Anadarko basin is really a boost to therecovery and the deliverability that we're experiencing.
Our final slide is slide 16 which maps our principal East Texasassets. Here we're completing the final stages of our 700 million aday Clarity transmission system. This primarily involves tie-in tothe Florida Gas interstate system, which we expect we'll bedelivering into by November. We also completed tie-in of a newwholesale customer in July which will help volumes in Claritycontinue to build in the third quarter.
Finally, we expect increased contributions as volumes build at ournewer plants. This includes the 200 million a day CO2 trader atMarquez, the 125 million a day asset gas injection facility at Akerthat'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 growthprojects and continue to identify new opportunities in both ourcrude oil and natural gas businesses. This bodes well for enhancedreturns to our investors over the long term.
And now for more detail, we'll turn it over to Mark Maki for thefinancial results.
Mark Maki
Thank you, Terry and Steve Letwin, for your comments as it relatesto Tracy. I worked with Tracy for better part of 20 years here atEEP or other entities in the Enbridge family and certainlyabsolutely value his contributions to the company over the yearsand 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 slidewe show operating income contributions by business segment, withvolatility FAS133 mark to market valuations removed.
Each of the business segment shows significantly improved resultsand in total, adjusted operating income is $66 million higher thanthe second quarter of last year. I'll review the individualoperating second quarter results in a moment.
At the bottom of the slide, we show adjusted EBITDA which alsoimproved up approximately 84 million to 211 million for thequarter. We explained the $30 million increase in interest expensein some detail in the news release, but fundamentally the increasewas more than offset bearings from new assets that come in service.
Other income increased about $2 million due to two roughly equalitems, first being interest expense on surplus cash invested duringthe quarter and the recovery of a previously written downreceivable in our gas unit. The bottom line as Terry mentioned wasa new all time high for us at $0.95 per unit.
On slide 18 we focused on the liquid segment, where operatingincome was roughly $90 dollars or double the second quarter of2007. Looking at the components of operating income, operatingrevenue improved by almost $60 million due to a number of factorsincluding a new surcharge with our $0.30 per barrel for light crudeservice, related to the start-up of the first phase, the southernaccess project on April first.
Material surcharge for North Dakota phase 5 expansion that tookeffect on January 1, the FERC index total adjustments effectiveJuly 1 last year for three liquid systems, 4.6% increase indelivery volumes and higher oil prices applying to oil collectedunder our carriers as compensation for transportation services, areroughly $7 million.
Power cost increase 4 million, the increase was primarily to theincreased of delivery volumes and higher utility rates, they arecharged by our power suppliers. Depreciation expense was up $10dollars, largely attributable to new assets, in particular theSouthern Access Expansion.
Turning to natural gas segment in slide 19, its contribution toadjusted operating income was 60.5 million, roughly $19 millionhigher than the second quarter of 2007. Reading the breakdown ofthat increase, gross margin increase almost $41 million for bothvolume and price reasons,
Throughput of on our three largest systems was up 17%, natural gasprices were very strong during the quarter, for example natural gasclimbed to briefly above $13 as well liquids prices were stronger.And we benefit from higher pricing on the portion of our naturalgas link and natural gas liquids link that is not hedged.
The stronger natural gas prices though did attract some fromprocessing 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 offsetby $16 million increase in OE expenses, primarily workforce relatedcost, maintenance activities, materials and supplies and so forth,the increases were in line with higher systems throughput andincrease processing plant capacity and compression units that wecommissioned since last year.
Depreciation expense was up, up roughly $6 million as a result ofnatural gas projects that was completed since last year. Marketinggroup reported just an operating income of 4.4 million an increaseof 2.1 million compared with one year ago. And this increasestemmed primarily from our enhanced ability to access premiummarkets. For example the quarry expansion is alleviating some ofthe capacity bottlenecks in our East Texas system that requiredmarketing to move gas to less permeable markets last year.
In slide 20, we break our keep-whole processing since its one ofthe more volatile parts of our business. The volume we processunder keep-whole arrangements was up around 50 million cubic feet aday from second quarter last year, primarily due to the capacitythat we've added and partially due to the refurbishing of theZyback plant during the second quarter of last year. The gain wasoffset by lower after hedging margin with the net result that arekeep-whole contribution was flat at about $17 million.
The next slide shows our calculation and distribution coverage, andwe consider the year-to-date as declared calculation to be the mostrelevant. On that basis, DCF exceeded distributions by 1.26 times.As reminders we include our pay-in-kind distributions as if theywere paid in cash and our as-declared calculations associatedistributions with the quarter in which they are earned, ratherthan the quarter in which they were paid.
Our book capitalization is shown on slide 22 with standardadjustments for other comprehensive income or OCI, and hiber [ph]securities that are noted on the slide. Total debts, total cap was50% at quarter end. In terms of floating rate, debt outstanding asof June 30 we had a $100 million outstanding on commercial paper atan average interest rate of 3.1% we had $250 drawn on a revolverand an average rate of 2.9% as well we had approximately $300million outstanding on letters of credit. This left us around 600million available under our 1.25 billion standby regular creditfacility and we have access to $500 million more on a standby linethrough our general partner.
Slide 23 shows our CapEx year to date maintenance CapEx is 32.1million, on enhancement CapEx is 640 million. The largestcomponents of the enhancement CapEx include 410 million forSouthern Access followed by 32 million for the Alberta Clipperproject.
Slide 24 shows our estimated capital expansion commitments goingforward, which we find (inaudible) modestly since our last earningscall. First, we've increased our 2008 estimate by approximately$300 dollars to 1.7 billion in total. This is largely due to someacceleration of the anticipated spin pattern for Southern accessstage 2, plus the addition of a few smaller natural gas projectsthat we anticipate moving forward in the fairly near future.
On balance though, there is no net change in 2009 or 2010estimates, as it relates to the large projects. In these estimateswe've included projects that are commercially secure, although wefeel fairly certain are going to proceed as usual we have aninventory of less well developed projects that could add to currentestimates. A good example of this is the Trailbreaker project thatSteve described in the opening comments. It's not included yet, butlooks very promising.
Finally in slide 25, we've indicated that we've increased ourestimate portfolio earnings by about $60 million, we now anticipatethat adjusted net income for the year will finish between the rangeof 370 and 400 million. First half results did exceed ourexpectations and major factors included the value of unhedgedcommodities, volume growth, continued strong processingfundamentals that would continue to benefit us for the second halfof the year. That covers my prepared remarks, let’s takequestions from the analysts. Latonia, could you please open thephone lines.
Question-and-Answer Session
Operator
We will now conduct a question and answer session. (Operatorinstructions) Our first question comes from Sharon Lu from WachoviaSecurities. Please proceed with your question.
Sharon Lu – Wachovia Securities
Hi, good morning. This question is in regards to the AlbertaClipper, I noticed that the cost is a little bit higher than youroriginal estimates. Is that just a function that the old estimatewas based on 2007 cost?
Terry McGill
Yes we're basically picking up now more nominal dollars and that'sbeing reflected, Sharon.
Sharon Lu – Wachovia Securities
Okay. Also if you could provide an update on your equity financingneeds, I think that your original budget had assume some assetsales 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 assetssales, that's always an option that we could go to, as source offinancing, as far as our cord [ph] financial plans. We turn to JohnRose here, our treasurer.
John Rose
For the balance of 2008, we do have some equity capital needs inthe range of probably $200 to $300 million. And we'll be looking totake advantage of a market window that would present itself in theback half of this year. But we do have available liquidity to us tomanage ourselves through more difficult markets such as the marketswe're seeing today.
Sharon Lu – Wachovia Securities
Okay. Thank you.
Operator
Our next question comes from Gabe Moreen, Merrill Lynch. Pleaseproceed with your question.
Gabe Moreen – Merrill Lynch
Hi, good morning. In terms of the oil allowances this quarter aswell as the favorable measurements, is it possible to quantify thatin kind of year over year, what the differential was there?
Terry McGill
The allowance revenue difference was around $7 million relative tothe second quarter of last year and that’s largely due to therun up in commodity prices. So, if we take very small fraction ofthe oil that's transported in our system, as compensation, most ofour RPs are based on it is just key reserves, you take some oil ascompensation and we sell that back, so that's the difference yearover year.
Oil losses is usually is a variety of different factors, thatreally lay in to that, but as far as quarter over quarter, modestdifference 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 processingvolumes were way up, quarter over quarter sequentially but your key– your NGL production in terms of your equity NGL wasactually down sequentially, can you talk about that? Were you doingrejection or something on those lines?
Terry McGill
No. One thing that's different if you're talking from Q1 to Q2 wedo have some contracts that are migrating away keep-whole topercentage of liquids, so we have some lift in POL barrels and somedrop off in keep-whole, that's probably the item that you'recatching with your analysis.
Gabe Moreen – Merrill Lynch
Okay. And then finally, I wonder if Terry can maybe talk about someof the more exciting place in the natural gas world over the lastcouple of months in terms of exposure to the Haynesville, whatyou're seeing in East Texas and whether your Louisiana systems alsohave any exposure there as well?
Terry McGill
Yes, of course it's all been pretty exciting down here in Houstonon this, the Haynesville is just would say, Audrey McLanan wasquoted as saying, "Could have up to TCF or reserves." Oursystem sits over by syntaxes, but the belief is the Haynesvillecrosses to the areas of the red rivers, (inaudible) bend area, andcomes in to the Texas of which we, the eastern part of our systemShelby County, Harrison County, were already here. So were startingto see some of the effects of the Haynesville showing up in oursystems.
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 moreactivity to delineate that field and really get the attributes ofthat field defined. But it is certainly promising, and you see theprices people are paying, break ridge of $13,000 to $15,000 anacre, yes, there’s a lot of people who believes it's theplace to be.
The Barnett, we see it continue to grow from the Barnett, it'smoved south and starting to move a little bit west. They got thedrilling down to a science under flex rigs, so we're seeing a– growth was on the North Texas but a lot of that is forwardbasin 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 closeto Marseille’s but the Haynesville is the one the one that wekind of tickle on the edge and we have plans on moving in to thatarea.
Gabe Moreen – Merrill Lynch
Okay, great. Thanks, Terry.
John Rose
I can give one of their follow up on your NGL question, the otherthing that would have affected the quarter’s production, wehit of the key facility, NGL line going out of it down forhydrotesting service, and that also affected some of ourproduction. 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 theLakehead system deliveries despite the (inaudible) of an accessproject 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 theoil sands with some of the plants, the new plants coming on, theSAGD operations of the steam-assisted gravity drainage has takenmore time than expected to see those volumes come on, and theSouthern Access phase 1, the tolls [ph] were applied, the line fillof 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 haveseen any effect of that capacity yet, because there isn't the linefill that yet in the system to fill that line. So, you wouldn'thave seen any effect yet, that'll be later on.
Terry McGill
The other thing worth noting is if for some reason the volumeforecast for the year is below, what we had anticipated when wefiled the tariff, we'll just treat that up next year, as it relatesto our cost for Southern Access, so to an extent we under-collectthis year, it gets billed in the next year's toll surcharge, andit's collected then. Our volumetric exposure really in the companyis 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, thatis still – you are still looking at that?
Terry McGill
That’s probably little on the high side, if I was going toreguide in that particular point, I'll take it down some from whatwe 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. Twoquestions, one on the fuel and power cost in the liquid system,where do you see those trending with higher commodity prices, andthen two, if you could give us a fill of the, if you've updated thedeck that you're using with the new (inaudible).
Terry McGill
The OE [ph] guidance reflects our current fairly recent look atcash commodity prices of later extremely lower crudes at 3 buckstoday day, but one thing to keep in mind with our business, is wedo hedge substantially our exposures.
We’ve got some exposure to commodity price, but it's notlarge, roughly 70% our margin is hedged on the places we have(inaudible). As relates to your power question – because ofthe input cost, coal, natural gas, we are seeing rates of powercost increase, which exceed the general rate of inflation and it'svery regional, depends on the type of production and each of thelocations 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 ofinflation, now one good thing again with tolling arrangements thatwe have now whether it’s Southern Access or Alberta Clipperor the North Dakota expansions, our cost of service arrangements,sort of the extent you got, basically modeling your incrementalpower 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 FruehaufConsulting. 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 operationtoday, what would be the overall toll from Alberta to the GulfCoast?
Steve Wuori
Good morning Winfred, it's Steve Wuori, I'll take that one, thatone is not yet tied down, there's a number of moving variablesthere, including the cost of the Line 6B expansion on the East [ph]system, line 9 reversal and then the Portland pipeline reversal aswell as tanker rates between Portland and the gulf coast, so Idon't think we're prepared to pin a number down yet, because thereare those moving pieces, but something in the $8 range with apretty wide band around that is probably note a bad proxy for whereit many end up, but again, I cautioned that that is not somethingthat is definitive because of the variables that I talked about.
Winfried Fruehauf – Fruehauf Consulting
Thank you, and another hypothetical, assuming your Texas accessproject were to go ahead and were on operation today. What would bethe 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 thinkthat in all of these cases, we are talking about tolls in that samerange, but less probably because Texas access is a high volumesolution to the Gulf Coast, whereas the Trailbreaker is somethingon the order of less than 200,000 barrels a day Texas access,ultimately can deliver up to 800,000 barrels a day. So you wouldsee a lower toll on Texas access than you would on the Trailbreakersystem.
And that's why, they really don't compete against one another,because Trailbreaker is two years ahead of any solution to the GulfCoast, including Texas access, so it really is more of a timing andoptionality play as opposed to a toll on toll competition. Butcertainly the higher volume toll more direct to the gulf coast inTexas access will be lower, than the Trailbreaker toll.
Winfried Fruehauf – Fruehauf Consulting
And if Texas access was in operation, would be built – is itpossible that Trailbreaker might still operate as a supplementarysystem, delivering smaller volumes to the Gulf Coast or anywhere inthe East coast?
Steve Wuori
Yeah, I think the thought with trailbreaker is that once Texasaccess goes into service and takes the bulk of the heavy movementsto the gulf coast, trailbreaker could move synthetic crudes fromthe oil sands into the Philadelphia Delaware river refining area inPADD 1, so that's really the optionality that's provided there, isthat it can move heavy oil in the early years and then syntheticoil in the later years, and there's still is the optionality aroundspot movements of heavy oil after that point in time. But certainlyTexas access would be intended to take the bulk of the heavymovements on a regular basis to the gulf.
Winfried Fruehauf – Fruehauf Consulting
And final question, if trailbreaker were to go ahead, who would beresponsible 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 Montrealpipeline ownership partners, they really have responsibility forthe reversal of that pipeline as well as the dock operations atPortland, so I do not think that EEP or Enbridge would be directlyresponsible 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, isthere opportunity for you to capture incremental business and howare 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, theremight be some opportunities and we would be one of those parties aswell. So, we are looking at it, we are evaluating it. We haven'treached 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 goover exactly how much of the processing business is hedged rightnow?
Mark Maki
Roughly 70%.
Brad Siegel – Aurora Capital
Okay, got it. I do want to ask one other question. When you look atthe financing needs for this year, and that you are running abovebudget, how does that play in to your hands, in to your thinking asit relates to excess cash flow being able to mitigate the amount ofequity, you might have to raise?
Mark Maki
What we have done over the last number of years is laid out, cashwhole metric targets and other targets with the rating agencies, aswe've stated repeatedly over the years are triple BBB mid ratingsis very important to us, so we manage our capital needs inaccordance to the targets that we set out with the rating agencies,as we see more cash flow being generated off our assets, obviouslythat could have lead some portion of equity financing that will berequired, because that cash flow would go to service, the debt thatwe've got, notwithstanding whether this is interim debt at thispoint. So it could serve to either replace or defer the timing ofparticular 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 thelandfill now in Southern Access, when you expect incrementaltariffs to be realized, and how quick will that ramp up be? Thankyou.
Terry McGill
They're already being realized now, Ross. I mean they're basicallyin… every barrel that moves in the system is effectivelypaying some of access today, whether the line is filled, or movingor 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'svery rough approximation, but the month of April would have beenunder old tariffs and then May and June would have been undernew… I think it's very roughly… 3 weeks, 4 weeks topump the system, to get all the old barrels out and new barrelsearning 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 onthe system, it pays less, if goes longer it pays more, itit’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 CapitalMarkets; please proceed with your questions.
Shawn Wells – RBC Capital Markets
Good morning guys, I have a question on the TransCanada's competingpipelines to the Gulf Coast, apparently it received backing fromValero [ph] and I was wondering, what if any impact that has had onthe Texas access pipeline or your plans for the Texas Accesspipeline.
Steve Wuori
Yes, it's Steve Wuori here, I can't confirm who the support wouldbe from that was announced when they announced the open season forthe project to the Gulf Coast, I think our view is, as we study theramp up in production, coming out of the oil sands being slowerthan it was a year ago, by 200,000 to 300,000 barrels a day itreally has caused us to focus on what we think is the best answerfor the industry which is a phased approached, that has theTrailbreaker project moving heavy volumes to the Gulf earlystarting in 2010 and then Texas Access after that, ramping up fromanywhere from 400,000 to 800,000 barrels a day if the market isthere to support that. So, we really feel that that offer is thelowest cost and the greatest flexibility to the industry and that'swhat 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 thelatest information regarding the size and potential productioncoming out of the back information, with your plans for stage 6, Iwas wondering, do you think you might be a little too conservativewith your plant's increase capacity by 15,000 barrels per day, doyou think that's right sizing it or do you think you might be alittle too conservative on that?
Steve Wuori
That's a great a question and I don't think it is right-sized, Ithink it is too small, but that pushes the existing pipe to itslimit. And so, we also have discussions underway about otheroptions to pipe more volume coming out of the back and as thepotential certainly appears to be there, but what we're doing withthis stage expansion is really maxing out the capacity of theexisting system completely, to make sure that that's available forthe industry, while we work on other solutions that can come out ofthere. 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 toturn the floor back over to Mr. Barker for closing comments.
Tracy Barker
Thanks everyone for joining us in the call today, just a fewreminders as we conclude, in the supplemental slides to thispresentation, you'll find reconciliations for the non-GAAP measuresthat we referred to in our remarks.
And for those in the webcast, these slides are being scrolled as wewrap up, as a reminder of materials from this call are also postedon enbridgedpartners.com/q, which is our one stop webpage forearnings release materials. We'll have the call transcript and adownloadable audio replay as soon as they're available, we expectby the end of business today. And as usual, we're available inHouston for any follow-up calls you may have, I thank you forjoining us and have a good day.
Operator
This concludes today's teleconference; you may disconnect yourlines at this time, thank you for your participation.
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