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Enbridge Energy Partners LP. (NYSE:EEP)

Q2 2007 Earnings Call

July 27, 2007, 4:15 PM ET

Executives

Tracy Barker - Manager of IR

Stephen J. J. Letwin - EVP, Gas Transportation and International

Terry L. McGill - President

Mark A. Maki - VP, Finance, General Partner

J. Richard Bird - EVP, Liquids Pipelines

Analysts

Ross Payne - Wachovia Securities

Sharon Lui - Wachovia Securities

Yves C. Siegel - Wachovia Securities

Sam Arnold - Credit Suisse

Presentation

Operator

Greetings ladies and gentlemen, and welcome to the Enbridge Energy Partners' Second Quarter 2007 Earnings Conference Call. At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation. [Operator Instructions]. As a reminder, this conference is being recorded.

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 - Manager of Investor Relations

Thank you, Joe, and good afternoon everyone. Welcome to the 2007 second quarter conference call for Enbridge Energy Partners. If you have not already done so and want a copy of the slide, the condensed financial statements, or the news release that's associated with this call, they can be downloaded from our website and that's at ebridgepartners.com/q, q as in quarterly.

In the call, we'll often refer to the Partnership by its trading symbol EEP, and the Partnership's results are also aggressively relevant to Enbridge Energy Management or trading symbol EEQ, that entity provides a vehicle to invest in the Partnership through company shares.

Online today for our call, speakers from the General Partners are Steve Letwin, Managing Director; Terry McGill, President; and Mark Maki, Vice President, Finance. We also have available for the Q&A session, Richard Bird, Executive Vice President, Liquid Systems; Vern Yu, Treasurer; Steve Neyland, Controller.

If you're following along with the slides, on slide 2, we have our standard legal notice, which I will read in to the record. Certain information during this presentation will constitute forward-looking statements. These will include, but are not limited necessarily to, throughput volumes, financial projections, extension or acquisition projects, external economics, and competitive factors. These statements are based on certain assumptions made by management and accordingly actual results may differ materially from current estimates. You are referred to the Enbridge Energy Partners SEC filings, including our Annual Form 10-K, for a more detailed discussion of risk factors.

The presentation will also 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 slides that accompany the presentation, and they can be downloaded from the website as previously mentioned.

If you would all turn to slide 3, I will now give the conference over to Steve Letwin.

Stephen J. J. Letwin - Executive Vice President, Gas Transportation and International

Well greetings everybody. We are here in Superior, Wisconsin where we held our Board Meeting today and took the opportunity yesterday to tour a construction on the Southern Access Expansion. This is EEP's largest expansion project and it's part of the slate of organic growth projects that Terry has already commented on in the earnings release. This will more than double the Partnership's asset base by 2010.

I'll tell you that it was comforting to see, first-hand, the progress our two cruise are making on stage one of Southern Access, which is the section between Superior and Delavan, Wisconsin. The cruise started in the middle and are building towards the endpoint and they've been hitting our target rate of 5,000 feet of pipe laid per day. Assuming weather continues to be reasonably cooperative, we appear to be on track to provide an additional 190,000 barrels per day of crude oil capacity in the Chicago by the early part of next year.

Terry and Mark will review the Partnership's projects, results, and outlook in more detail. However, I note that the Partnership is approaching a number of project milestones between now and early 2008. As you know, our bigger projects have relatively long construction windows, so it will be gratifying to have some of the new assets under ... enter service and start to earn a return on our investment. And if I can use that observation as segue to project financing, the Partnership made considerable project ... progress on that front in the second quarter.

We raised approximately $320 million with the issuance of 5.9 million Class C units and expanded the upper limit of credit facility to $1.5 billion. Both of these transactions were completed early in the quarter, so we commented on them already in our last call. Since market conditions were favorable, we seized the opportunity to raise an additional $310 million to the issuance of 5.3 million Class A units on the May 16th. That deal put us a little ahead of schedule in terms of equity capitalization.

However, given the size of our CapEx program, additional equity capital will be required, as the various projects move forward. And we remain confident; we'll be able to raise the necessary amounts on attractive terms.

Before we get to EEP's results specifically, let me touch on a few of Enbridge Inc.'s projects that are complimentary to the Partnership. The joint EEP and Enbridge Alberta Clipper expansion moved another step closer to reality as we negotiated commercial terms with shippers, and Enbridge filed the term sheet with the National Energy Board in Canada. Terry will review the key aspects of the Partnership's commercial terms which are similar to those for Enbridge. The Partnership will file for FERC approval of the commercial terms next year.

Enbridge's Southern Access extension is a key complimentary project to Southern Access and Alberta Clipper. Enbridge recently finalized the tolling agreement for the extension with shippers and expects to file for FERC approval in August. As you recall, Southern Access extension will provide a new outlet for our Lakehead System volume by transporting 400,000 barrels per day of crude oil from an interconnect near Chicago to the pipeline hub at Patoka, Illinois.

We noted in our first quarter call that Enbridge's Open Season for expansion of the Spearhead pipeline was successful. Enbridge will now embark on the 65,000 barrel per day expansion with an in-service target date of early 2009. Spearhead received all of its volumes from an interconnect with our Lakehead System near Chicago.

Finally, I've mentioned in the past that Enbridge also has a number of conceptual crude oil transportation projects under development that would benefit the Partnership. One of these was made public in June, when Enbridge and ExxonMobil announced a joint initiative to study the feasibility of a new crude oil pipeline from Patoka to the Gulf Coast. Assuming the project goes ahead, we would expect it to draw incremental volumes through our Lakehead System.

With those, as background comments, I will hand it off to Terry for his quarterly review and update.

Terry L. McGill - President

Thanks Steve. I am starting with slide 4. We were pleased with the Partnership's overall results in the second quarter which exceeded our expectations largely due to strong margins for natural gas process. A primary indicator for the state of processing margins is the ratio of crude oil prices to natural gas prices. They rose steadily in the second quarter and currently sits at about 12 times or roughly double the difference in their e-content.

That said the turnaround we took to pick the Zybach Processing plant that we spoke about on the Q1 call, proved to be just-in-time maintenance. The plant was refurbished and restarted in April and has been recovering natural gas liquids at expected level since then, it was also very timely to commission the new Hidetown plant in April, as it ramped up production over the second quarter and helped us capture greater value from the strong processing margins.

The other operational issues that got mentioned in our Q1 call was the gas measurement losses, including water content on the Anadarko System. At this point, losses have declined to an acceptable level and we are evaluating additional cost-effective preventions and mitigation steps that we can implement. As usual, we'll have Mark who'll provide a more detailed financial review and also run through operational highlights and the status of our major projects.

Turning the slide 5, we recently updated our estimates for capital expenditures and now expect to invest more than $5 billion in new facility in the 2006 to 2010 period. The largest project or Southern Access Expansion at $1.8 billion; Alberta Clipper at $1 billion, which is before inflation and capitalized interest; and the Clarity project at $635 million. The footnotes on slide shows ... on the slide show the estimated breakout of CapEx by year for these projects.

This is, by far, the Partnership's largest ever expansion. It's a big program to manage and finance but we're fully up to the task and we look forward to the incremental cash flow that will be generated as major stages come into service.

Turning to Partnership's natural gas business, beginning on slide 6, you'll see that volumes continue to increase on our three principal systems. Year-over-year throughputs improved to 18% in East Texas, 24% in North Texas, and 4% in the Anadarko Basin. Along the volume increases has come more demand for processing. As the slide shows, we've been adding plant capacity at a pretty regular clip over the last three years. This year we commissioned 120 million in Hidetown plant on the Anadarko System in April and we have a further 70 million a day, under development, North Texas for completion in the third quarter.

Late this year, we'll also bring on three conditioning plants in East Texas with an aggregate capacity of 600 million a day. These plants will assist on staying onsite with downstream DuPont [ph] specifications, and will generate reasonable financial return.

Slide 7, let me talk about natural gas drilling. We see no abatement in gas well drilling programs. Although gas prices have recently closed below the $6 level, producers appear confident in longer-term supply and demand fundamentals. In fact, since the hurricanes of 2005, there hasn't been much too really rile up the gas markets. So a serious storm, a cold winter, or hot summer would erode the high inventory balances that have prevailed for some time and put pressure on prices.

After one of these events and assuming no precipitous drop in prices, the Partnership is a net beneficiary of the current higher oil price and lower gas price environment. First gas processing margins are strong, and we have increasing our plant capacity. Second, basis differentials tend to be narrower, and we still are fairly... fairly reliant on secondary gas markets, while developing increased access to premium markets.

The map on slide 8, depicts transmission facilities we've added to find defined attractive markets for growing natural gas supply. These facilities, plus a few smaller new regional connections, have been ... excuse me, successes. However, our largest initiative is still under construction that being the expansion and extension of the East Texas system.

It is showed in more detail on the next slide. The 700 million a day intrastate project, which we referred to as Clarity, will increase market optionality for producers in East and North Texas, largely due to prolonged led spell around the Clarity construction well, we have some slippage in our milestones, and we are revising our cost estimates up to $635 million to complete the project. Either factor will cause a material change in our return expectations for Clarity though.

The good news is that the project is making tangible progress. Stage 1 facilities were commissioned in the first quarter and included 36-inch transmission lines from Crockett to Goodrich, that's 200 million a day C02 treatment plant in Marquez that is connected by a 24-inch line to the larger transmission system. At Goodrich, we have connections to Bellsouth, Kinder Morgan Texas, and NGPL. We are currently ramping up the Marquez plant connecting supply to those new facilities. And really ... literally any day now, we will commission the upstream leg Stage 2, which allows us to access supply from the Bethel hub. However, the full benefit of Stage 2 will not be realized, really, until October, when we are scheduled to complete the downstream line to Kountze and tie in to the trunk line system. We will then be positioned to deliver some efficient volumes to have a meaningful impact on the Partnership's earnings. Thus we anticipate an up-tick in Q4.

Stage 3 is now scheduled for completion by February next year. It extends the main transmission line from Kountze to Orange County, where it will tie in with Florida gas system. In addition, we are pursuing a number of opportunities to supply in wholesale customers in the Southeast Texas region.

Beginning on slide 10, we turned to opportunities in our crude oil transportation business. Together our Lakehead mainline system, and Enbridge pipelines in Canada are the main conduit from moving western Canadian crude oil to refinery markets. Today these markets are primarily in the US Midwest and Ontario, Canada. However, as Alberta is 174 billion barrel oil sands reserve is increasingly exploited. There is growing need to access to additional refinery markets, primarily in the US PAD 2 and PAD 3 districts, which have approximately 70% of the US refining capacity. Our Lakehead System will play a pivotal role in linking increased crude oil supply with these expanding markets.

Slide 11 shows the supply side of the equation. It reflects the recent update of our forecast for petroleum production from the Western Canadian Sedimentary Basin out of 2016 -- to 2016. The forecast assumes there will be relatively little in the way of market constraints for increased crude supply from Western Canada. The key assumptions include supportive oil prices, timely development in new markets and available transportation infrastructure. On this basis, we forecast production will grow from approximately 2.3 million barrels per day in 2006 to 4.4 million barrels per day in 2016; on average nearly 7% per year.

The green line on the chart represents the aggregate of producer plants per annual survey which is one input to the forecast. It is relatively unconstrained case in terms of assumed labor and materials availability. Therefore, we think the forecast of nearly 6 million barrels per day production in 2016 is on the extreme high side. However, the result may indicate continuing growth potential beyond to 2016.

As featured on slide 12, we've undertaken a Lakehead system expansion that will ultimately add 1.2 million barrels per day of capacity to support increased exports from Western Canada. The first stage of our $1.8 billion Southern Access expansion is under construction. Steve mentioned the two -- the fact that this stage is on target to start delivering an incremental 190,000 barrels per day of crude oil by early next year. Specifically, the project involves a new 42-inch pipeline, again from Superior to Delavan, Wisconsin and complimentary increases of pumping capacity on existing two pipelines to complete to Roche, [ph] Chicago.

Stage 2 will extend the new 42-inch pipeline from Delavan to Flanagan, Illinois, to provide an additional 210,000 barrel per day of capacity in early 2009. From Flanagan, crude oil will be able to access Cushing via the Spearhead pipeline or Chicago, because the Partnership will buy and reverse the northern piece of the Spearhead segment between Flanagan and Chicago.

We are in pretty good shape on Stage 2, since pipe has been contracted, and we were granted combination rights by the Illinois Commerce Commission. With also in excellent relations with a number of experienced construction contractors, we are working with.

As capacity is added, tariffs will be adjusted for a full cost-of-service tolling model. As a reminder, the key provisions of the tariff agreement include: a third year term that provides a 90% real return on equity, and assumes 55% equity financing. The annual inflation adjustments to keep the ROE in current dollars is added to rate base and collected over the remaining term of the agreement. The tax allowance will be collected to further describe the regulatory rate and this is subject to change if the regulatory rate changes.

Finally, 87.8% of the project cost will form the initial rate base. We will like to recall that the partnership is funding a 12.2% portion, which is related to the upsizing to a 42-inch pipeline in anticipation of future expansion opportunities.

Slide 13 shows the Alberta Clipper expansion, hence our project to add capacity upstream of Superior. Initially to move an additional 450,000 barrels per day through the Lakehead System with expandability up to 800,000 barrels per day. Partnership is responsible for the US portion, which is estimated to cost $1 billion in 2007 dollars, excluding capitalized interest, while Enbridge will add equivalent capacity to the Canadian mainline.

In late June, commercial terms for Alberta Clipper were finalized with shippers. As expected, the terms provide a fair return for relatively modest risk. In particular, the partnership is protected from crude oil supply risk over which it has no control. Other key terms include a 15-year term with an ROE equal to the NEB multi-pipeline rate plus 2.25% and with 55% equity, 45% debt capitalization.

Operating costs will be recovered under an index methodology using, be ready for this, PPIFG plus one half of the increment allowed by FERC, so today that would be PPIFG plus 0.65%. Costs will be rebased every five years. Tax allowance will be as permitted by FERC. The Alberta Clipper project has already started including placing a firm order -- firm pipe order based on the backstopping agreement with the shippers. Finalizing commercial terms help to stay on schedule to complete the new line by mid-2010.

Slide 14 overlays plans for incremental pipeline capacity on our forecast for growth in crude oil exports from Western Canada. It illustrates that the ongoing stages of Southern Access and Alberta Clipper is only part of the solution to move growing exports. Even assuming the Keystone pipeline proceeds on schedule, and with the committed volumes response are currently indicate, additional pipeline capacity will likely be required by the 2013 to 2014 timeframe. Of course, Clipper and Southern Access could readily provide the next trench of capacity to 350,000 barrels per day, could be activated by powering the lines to their maximum. This could be done at relatively low cost and on relatively short lead time.

On the demand side of the equation, slide 15 highlights a number of announcements by refiners of plans to increase their take of Canadian crude oil. While some of the announcements are preliminary, the trend is pretty apparent. We also note the announcements have been predominantly from refiners that have the necessary pipeline connections in place or in the region. Many other refiners are interested in Canadian feedstock, and we believe it's a matter of developing cost effective transportation solutions in order to capture a share of these new markets.

As shown on slide 16, those transportation solutions have started to appear. Enbridge and ExxonMobil both reversed pipelines last year to move Canadian crude oils to Cushing and to the Gulf Coast, respectively.

Enbridge is now expanding capacity of the Spearhead line and the success of both ventures spark the prospect of other pipeline reversals. For instance, BP recently indicated it was considering reversing its Cushing to Chicago line.

On a larger scale Enbridge and ExxonMobil announced that they are jointly reviewing the feasibility of a new line from Patoka to the Gulf Coast. They have significant shipper interest in the project could be a natural compliment to Enbridge's Southern Access extension which will connect our Lakehead System to the Patoka pipeline hub. In fact, all of these projects will be expected to draw additional volumes through the Lakehead System.

On slide 17, the final project I'll mention is our $76 million expansion in the North Dakota system, which is on track to add 30,000 barrels per day of capacity by late this year. We also announced the binding Open Season that will conclude in early August to ascertain support for expanding the system by a further 45,000 barrels per day. And for converting 80% of the capacity to contract service, subject to tenure commitments.

I'll open by saying we are pleased with the second quarter financial results, additionally the positive developments, I've just run through, bode well for our future results. We Certainly have challenges ahead in project execution, financing and other areas, however, my confidence is that we are on the right path to deliver long-term value for our investors and that path is as strong as ever.

Next, we have Mark review the Q2 financial results and then we'll be ready to take your questions. Mark?

Mark A. Maki - Vice President, Finance, General Partner

Thank you, Terry. Let's start with slide 18. Slide 18 we saw the Partnership's earnings on a non-GAAP basis with volatility caused by FAS 123R market valuations removed. Terry, indicated that we are pleased with the future results just after the quantification of that statement.

We note that our adjusted operating income for the quarter was within $5 million of an all-time high, during the second quarter of last year. And adjusted EBITDA was within $3 million of an all-time high. A reason we did not established new highs is the gas processing margins were strong, but they did not hedge the extraordinary level of the second quarter of last year.

As you move further down in our income statement, comparisons to the prior year become a little bit more difficult and that's because we are carrying an increasing amount of financing related to the assets that are under construction. For instance, net income includes $7.4 million of additional capitalized interest this quarter, which is more than offset at the EPU level by the impact of 20.6 million additional Partnership units that we issued to provide equity financing for the ongoing capital expansion program.

Of course, we expect this to become less a factor as projects are completed and start to generate revenue, but in the interim, we will focus a little more on results from operations than usual. Two other items to mention before I move onto operating segment performance are: first, operating income or other income, sorry, last year included $4.4 million of business interruption insurance related to the settlements we received from our insurance companies with respect to the second quarter business interruption outage in 2005.

And second, the income tax line related to the new Texas margin tax which is bona fide as an income tax in our statement of earnings.

Turning to slide 19; there we focus on the liquid segment which showed a decrease of $4.9 million in operating income to $44.8 million for the quarter. Operating revenue improved by about $4.5 million primarily attributable to higher transportation rates that went to affect on July 1, of 2006 on our three liquid systems, an increase in contract storage fees generated by the Cushing terminal also contributed to the revenue increase. However, we are not quite firing on all cylinders. Liquid deliveries were flat to the prior year, but they were about 8% lower than we had hoped for the quarter. This was a modest disappointment in the quarter.

The good news is that completion of maintenance at major oil sands plants and refineries in the first of this year should benefit us in the second half. Although overall deliveries were down modestly, power expense increased 3.1 million due to higher utility rates that were charged by our power suppliers.

Operating and admin costs increased $5.5 million, primarily due to higher costs incurred in connection with our pipeline activity management program. Secondary causes were modest oil measurement loss after a small hurdle [ph] last year as well as workforce related costs.

Turning to slide 20, in our natural gas segment; its contribution to adjusted operating income decreased slightly to $41.8 million. Gross margin or revenue less cost of gas sold was up $14.8 million or 13.4%, as it benefited from nearly 14% increase in volumes on our three largest G&P systems.

The $10.9 million increase in O&A expenses was primarily attributable to variable operating costs including workforce costs, materials and supplies, repairs and maintenance of the gathering and processing assets. These increases were inline with higher system throughputs and expansion of our natural gas systems.

The 4.5 million increase in depreciation expense within these assets [ph] as over the past year had a revision to depreciation rates or a portion of our asset effective on July 1, 2006. For the marketing segment, our operating income was up $1.7 million and will take some credit for the improvement since we expected to add infrastructure, so that more of our gas volumes could be taken to premier markets, which was a key driver behind our Level B expansion, the North Texas link and the Clarity projects. We also benefited from a narrower basis differentials in the Texas markets.

On slide 21, the breakout of our Keep Whole Natural Gas processing for the Anadarko and East Texas System, processing had a gross margin after hedging a $13.5 million in the natural gas segment compared to $17.4 million in the second quarter of 2006. Volumes processes under Keep Whole contract increased by about 150 million cubic feet a day compared with a year ago volumes, and could have been higher except for the Xindak plant of our peers and Hidetown plant just starting service in the second quarter. However, the volume increase was more than offset our lower processing spread, which were strong in the second quarter but do not reached the record levels with the year ago.

On slide 22, we lay out for you, our distribution coverage, and this slide shows our calculation as detailed. For the first half of the year coverage was 1.02 times on an as-pay basis and 0.95 times on a more conservative as-declared basis. The as-declared calculation is essentially an accrual method which compares all the units eligible to receive the declared distribution on the payment day. The as-pay calculation is essentially a cash method that includes distributions actually paid in the period.

Switching to my earlier comments, pertaining to earnings per unit, we expect distribution coverage will start to improve after our CapEx spending peaks and it's going to sneak new assets, excuse me, compared to generate revenue. Our target coverage ratio is periodically reviewed and based on the assets mix and other risk factors. Our current target is 1.15 times.

On slide 23 we show our investment enhancement projects totaled approximately $475 million in the second quarter excluding sustaining CapEx. For six months CapEx totaled $865 million with the two largest portions being $416 million for Southern Access and 180 million for the East Texas Expansion. Maintenance capital expenditures were $17.2 million in the quarter and $26.4 million for the first half of the year, and as is typical, we expect maintenance CapEx will be somewhat heavier in the second half of the year compared to the first half.

Construction work in process balance was $1.4 billion at the end of the second quarter up from the $1 billion at March 31. Slide 24 shows book capitalization and interest rate as of June 30 total debt to total cap was 43%. This calculation excluded Other Comprehensive Income or OCI, primarily due to the credit rating considerations, and how we calculate the ratios for those purposes. We are trying to maintain leverage close to 50%, which requires us to fund projects as we go.

At quarter end, $395 million of commercial paper was outstanding at a weighted average interest rate of 5.5%, and $90 million in letters of credit were issued. As Steve mentioned in his comments, we increased the credit facilities from $1 billion to as much as $1.5 billion and these increases our interim financing capability for financing our ongoing CapEx program.

With that that covers my prepared remarks, and Joey, I'd like to open the line up for questions.

Question And Answer

Operator

Thank you. [Operator Instructions]. Our first question is from Ross Payne with Wachovia Securities. Please state your question.

Ross Payne - Wachovia Securities

Thank you. First question on East Texas, I might have asked this in a prior conference call, but just to refresh my memory. What can we expect in terms of EBITDA contribution to that, and what kind of multiple of EBITDA was that project based on?

Mark A. Maki - Vice President, Finance, General Partner

Well the contribution this year Ross, will be fairly modest, especially in the first three quarters, and that's because the thing is largely under construction, and the first couple of phases. To really get the bang for the buck, as Terry said in his prepared remarks, once the final leg into the front line, and cones is completed. As far as the multiple of EBITDA, we would be expecting the assets, again, in the order of eight to nine multiple of EBITDA would be our expectation, maybe a little bit better, depending on how utilization goes. As far as the contribution this year, in terms of net income, on the order of $12 million, again, a partial year effect on the project. We can comment more when we get to our guidance for 2008 as to what we expect to see on our project going forward.

Ross Payne - Wachovia Securities

Okay. The second question I've got is the processing plants that you guys are building right now, are those primarily to handle your equity gas and NGLs as part of your contract or is it fee based or what's driving the economics and what kind of return you are getting there?

Terry L. McGill - President

Yes, it really depends which location you are referring to, but we've got plants under construction in North Texas, those contracts typically are either percentage of leverage or percentage of proceeds type contracts, it's not so much our equity link, as the reason we are making or building those plants. It's ... the gas requires processing, so we are making the investments to be able to deliver Type 1 quality gas downstream into plants and then we will take our fee, either by taking commodity in one of those two structures, POP or POL or we will do a few based arrangement, as well. Anadarko, there you see, particularly, a POL contract and Keep Whole East Texas is a some people, some POL, and some fee based arrangement.

Ross Payne - Wachovia Securities

Okay. This might be a tough question but do you have a number for the debt that's associated with projects currently under construction that's not contributing to EBITDA?

Mark A. Maki - Vice President, Finance, General Partner

Well we have sitting in CWIP right now. We have any order $1.14 billion or capitalization right now. Probably a way to look at it, Ross, would be, we're pretty close, we have a little more equity now than we are targeting. What I give you ... just take to see where the balance times 43%. So, that's how much debt at the moment is not affectively being covered off, that's a reasonable calculation.

Ross Payne - Wachovia Securities

Great, great. All right, thanks guys.

Operator

Our next question is from Yves Siegel with Wachovia Securities. Please state your question.

Sharon Lui - Wachovia Securities

Hi, actually this is Sharon Lui. I was wondering if you guys could just give a little bit more color on the cost creed related to Southern Access and the Alberta Clipper. It seems like a pretty big jump from those costs of $1.3 billion and $800 million?

J. Richard Bird - Executive Vice President, Liquids Pipelines

Sure. It's Richard Bird. I'll address that question, and it is a pretty significant cost increase that the timing of Southern Access was such at the time when it was approved that it was done on a relatively open-ended cost estimate subject to finalization of scope and finalization of contracts and materials and so forth, because it was pushed to a decision in a relatively short period of time. And unfortunately we are in an era where cost pressure is pretty significant. So, we've had significant wage escalation on the part of the various trades that the contractors that construct the pipeline have to take into consideration in their pricing to us. Another factor is the whole permitting and regulatory approval for us, that's exactly the tool both in terms of the rate of the start of the construction, which meant we have construction crudes on standby and couldn't get started. And also in terms of some pretty stringent permit restrictions, which have increased the costliness of the construction.

So, about the only thing that's been counterbalancing that is we did very well in our acquisition of line pipe and actually got that at significantly lower costs than what we had originally estimated. However, I think, it's pretty critical in understanding the implications of those cost increases to recognize that this is effectively a rate base driven, rate making structure, and 88% of those cost increases do flow through into the rates that we will charge for service on the pipelines. So, in affect, that additional capital is still earning an attractive rate of return and will still contribute additional accretion in distributable cash flow per unit over and above that which would have been contributed by the original capital costs.

Yves C. Siegel - Wachovia Securities

This is Yves Siegel. Good afternoon. Mark, I just wanted to ask a follow-up question to your targeted distribution coverage ratio of 1.15, I think is what you said. And you said you based that on the business mix. Can you just ... maybe just elaborate on that, because I would submit that ... I think that's a very conservative number given the nature of the pipeline and given the nature of how you guys hedge your commodity price risk, and your exposure to interest rate?

Terry L. McGill - President

Theway to look at Yves, is we've got two different business, so you've got a clearly pretty low risk proposition with the Liquid Systems and especially the Lakehead Systems but they are ... that asset by itself maybe could draw an NLP by itself as apposed to have a coverage ratio as low as 105. The gas business, on the other hand, has a little more inherent volatility with a little more commodity exposure in it. So, it should carry thicker coverage. And we think in the order of 125. So, when you sort of average the two off you come to the 115. And we said it before, you don't necessarily have to get to 115, it's just ... that is our long-term coverage target. That help with your understanding how we get there?

Yves C. Siegel - Wachovia Securities

Yes. Now, we certainly be able to conservative view as far as gathering and processing goes. Thank you.

Terry L. McGill - President

Thanks Yves.

Operator

The next question is from Sam Arnold with Credit Suisse. Please state your question.

Sam Arnold - Credit Suisse

Hi. Happy Friday, guys.

Terry L. McGill - President

Hey Sam.

Sam Arnold - Credit Suisse

Hey. Couple of quick questions for you; on -- I guess, Southern Access expansion, where exactly are you guys with the project? I assume you are just trying to link higher for now?

J. Richard Bird - Executive Vice President, Liquids Pipelines

Yes. Richard Bird, again, and actually as Steve Letwin mentioned in his introduction we had our Board yesterday touring the construction. So, we are laying pipe. The pipe is ... by the end of the month will all have been delivered to the right of way, it's stockpiled in pipe yards along the way. And a fair bit of it, at this point, is strung out, a good part of that's welded and a fair part is also in the diction. Being covered back over and that's the spring program. We did construct some pipes through the winter as well. So, we are on schedule, maybe even a touch ahead of schedule, at this point, not withstanding the fact that we were about three months late in getting started. And when I say on schedule; target completion for Stage 1 which will be the first significant increment to cash flow is end of the first quarter next year.

Sam Arnold - Credit Suisse

Okay. And how are those guys, the contract you are working is like time in materials or is it the lump sum?

Stephen J. J. Letwin - Executive Vice President, Gas Transportation and International

That project is what's called a target price, I don't know if you are familiar with how that works.

Sam Arnold - Credit Suisse

Not, really, actually?

Stephen J. J. Letwin - Executive Vice President, Gas Transportation and International

Well basically a price is negotiated with the contractor and --

Sam Arnold - Credit Suisse

Oh, then you share any up or down.

Stephen J. J. Letwin - Executive Vice President, Gas Transportation and International

You share variances according to a predefined formula.

Sam Arnold - Credit Suisse

Yes, got it. Okay. So, I guess at this point you have enough ... you've been laying enough line that you're pretty comfortable at that $1.8 billion now?

Stephen J. J. Letwin - Executive Vice President, Gas Transportation and International

That's right.

Sam Arnold - Credit Suisse

Okay. And all most of your materials have been prepared, so that line issue, it's all just a labor factor which drove the cost up?

Stephen J. J. Letwin - Executive Vice President, Gas Transportation and International

Yes. I think we've got a pretty good handle on costs at the moment with the perhaps, the open areas which still be on Stage 2. On Stage 1, I think, we've got a very good handle on. Stage 2 is still in initial estimate and is subject to some refinement, particularly in the land acquisition area because we do have some right away you acquire in Stage 2. So, that would be the area ... remaining uncertainty. I think the 1.8 is still a good estimate but it will be some time into the fall --

Sam Arnold - Credit Suisse

How much is Stage 1 of the 1.8?

Stephen J. J. Letwin - Executive Vice President, Gas Transportation and International

Stage 1 of the 1.8, I am not sure if we've disclosed that externally or not.

Sam Arnold - Credit Suisse

I think you know, because I have ... 5% --?

Stephen J. J. Letwin - Executive Vice President, Gas Transportation and International

Stage 1 would be more than half.

Sam Arnold - Credit Suisse

Okay. That helps. Okay, and then I guess kind of going into that; maybe, Terry, that's a question for you with this Enbridge-ExxonMobil proposed potential line. Given that land costs were very difficult, given the permits and everything, would you assume that that process would be greatly accelerated working with ExxonMobil, would you try to use the same corridor of their reverse line, Pegasus line, if you will?

J. Richard Bird - Executive Vice President, Liquids Pipelines

It's Richard Bird. I'll tackle that one, again, that's in the Liquids pipeline.

Sam Arnold - Credit Suisse

Okay.

Terry L. McGill - President

Well I could have, Sam, but I'll let Richard do it.

Sam Arnold - Credit Suisse

Okay, thanks.

J. Richard Bird - Executive Vice President, Liquids Pipelines

You are right one of the big ... one of the big values that ExxonMobil does bring to that relationship is the fact that they do have existing right-of-way that with multi-line rates that covers most of the distance from Patoka down to Beaumont, so that would certainly be something that would reflect favorably on both the cost timing and overall feasibility of that project.

Sam Arnold - Credit Suisse

Okay. And it's still on ENB project right now, right?

J. Richard Bird - Executive Vice President, Liquids Pipelines

Yes, it is.

Sam Arnold - Credit Suisse

Okay. That is all I have. Good quarter. Thank you.

Terry L. McGill - President

Thanks Sam.

Operator

[Operator Instructions]. The next question is from Kyle Vernoni with Aagon [ph]. Please state your question.

Unidentified Analyst

Hi, guys.

Terry L. McGill - President

Hi.

Unidentified Analyst

You know with some of the other pipelines coming on in the area, I'm just trying to get a better feel of some of the competitive advantages you have on your volume sensitive pipelines, i.e., Lakehead. Another tariff based or any relationships you might have with the producers in that area, and also if you could comment on what you are hearing around additional pipeline projects or reversal targeting Canadian crude and how that might affect you going forward?

J. Richard Bird - Executive Vice President, Liquids Pipelines

It's Richard Bird; I'll tackle that one if I can parse out the different components of it. So, competitive advantages that we would have ... I think, probably the most significant one would be the corridor that already exists with five lines across most of that distance from Alberta down into the US, the fact, that it carries about 70% of the crude that's produced in Western Canada into the US market, and so pretty significant economies of scale and ability to manage incremental capital expenditures as part of an overall capital expenditures base. We certainly do have very good relationships with the shippers, you asked about relationships with the shippers, we do have very good relationships with the shippers according to any of the industry surveys that have been done. And, I think, basically we are state-of-the-art in terms of our ability to develop and construct these projects. In terms of the some of the other projects to ... I think, you said to reverse?

Unidentified Analyst

Well, different pipelines that are ... but just kind of the environment that you are seeing out there whether additional pipeline projects are being contemplated or reversal of different things. Just kind of what you are seeing in that area?

J. Richard Bird - Executive Vice President, Liquids Pipelines

Yes. And we are certainly seeing competition for the business. The most significant and obvious one of those would be the Keystone line and the fact that they just announced additional commitments and additional upsizing of their plants to construct that line, but at the moment the industry has endorsed both Keystone and Alberta Clipper and the expectation that it will need the capacity for both ... and our extension cost on Alberta Clipper for the second trench are very, very economic. So, I think it's pretty well preordained that the next incremental expansion out of the basin will ... after Phase I of Clipper and after Keystone would be the next phase with Clipper.

Beyond that in terms of other projects that I am aware of, BP is in the process of looking at reversing a line that they own and operate to run from Chicago down to Cushing, which would facilitate the Lakehead System just by providing additional takeaway capacity from the Chicago area. Enbridge is expanding the Spearhead pipeline by another 65,000 barrels a day up to 190 a day. That's been subscribed for. What else.

Terry L. McGill - President

Seaway, I mean, let's go and talk about Seaway --

J. Richard Bird - Executive Vice President, Liquids Pipelines

But, I don't think that they --

Terry L. McGill - President

Diameter is not big enough to moving up the volume.

J. Richard Bird - Executive Vice President, Liquids Pipelines

As far as I am aware of.

Unidentified Analyst

No, it's good, that's good, that's helpful, guys. I appreciate it.

Operator

The next question is from Robert Lane with SMH Capital. Please state your question.

Unidentified Analyst

Hi, actually this is Paula Dresnok [ph], I work with Mr. Lane. I have a question. Just as a refresher, would you mind reminding us as to what the maintenance CapEx was for the first half of 2006?

Terry L. McGill - President

2006 first half maintenance CapEx.

Mark A. Maki - Vice President, Finance, General Partner

Yes. I don't have that at our fingertips. We can get that for you.

Unidentified Analyst

Okay. Perfect. Thank you so much. Great quarter, guys.

Mark A. Maki - Vice President, Finance, General Partner

Thank you.

Operator

At this time, there are no further questions in queue. I would like to turn the floor back over to management for closing comments.

Tracy Barker - Manager of Investor Relations

Thanks Joe. And just a few concluding reminders then, in the supplemental slides to our presentation, you will find reconciliations for all of the non-GAAP measures that we made reference to. Materials in the call are posted on enbridgepartners.com/q, which we mentioned is a one step stop webpage for all of our earnings release materials. We will be adding the call's transcript and a downloadable audio replay which we would expect would be available over the weekend or early on Monday and we will post those to the q page as we said. As usual we are available for any follow-up questions that you may have and we all now, we thank you for joining us on the call. Have a great weekend, and we'll look to the analyst research notes created early on Monday. Thank you.

Operator

Ladies and gentlemen this does conclude today's teleconference. You may disconnect your lines at this time. Thank you for your participation.

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Source: Enbridge Energy Partners Q2 2007 Earnings Call Transcript
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