Enbridge Energy Partners LP Management Discusses Q1 2013 Results - Earnings Call Transcript

May. 1.13 | About: Enbridge Energy (EEP)

Enbridge Energy Partners LP (NYSE:EEP)

Q1 2013 Earnings Call

May 01, 2013 10:00 am ET

Executives

Sanjay Lad - Former Director

Mark Andrew Maki - Senior Vice President of Enbridge Energy Company Inc, Director of Enbridge Energy Company Inc and President of Enbridge Management

Stephen J. Neyland - Vice President of Finance - Enbridge Energy Company Inc and Vice President of Finance - Enbridge Management

Stephen John Wuori - Executive Vice President of Liquids Pipelines - Enbridge Energy Company Inc, Director - Enbridge Energy Company Inc, Executive Vice President of Liquids Pipelines - Enbridge Management, President of Liquids Pipelines of Enbridge and Director - Enbridge Management

Douglas Montgomery

Darren Julian Yaworsky - Treasurer - Enbridge Energy Company Inc and Treasurer of Enbridge Management

David K. Wudrick - Former Treasurer of Enbridge Energy Company Inc and Treasurer of Enbridge Management

Analysts

Brian J. Zarahn - Barclays Capital, Research Division

Theodore Durbin - Goldman Sachs Group Inc., Research Division

TJ Schultz - RBC Capital Markets, LLC, Research Division

Sharon Lui - Wells Fargo Securities, LLC, Research Division

Louis Shamie

Stanley Ross Payne - Wells Fargo Securities, LLC, Research Division

Chuck Goldblum

John Edwards - Crédit Suisse AG, Research Division

Operator

Good day, ladies and gentlemen, and welcome to the Q1 2013 Enbridge Energy Partners LP Earnings Conference Call. My name is Stephanie, and I will be your operator for today. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes. And now I'd like to turn the call over to Mr. Sanjay Lad, Director of Investor Relations. Please proceed, Sir.

Sanjay Lad

Thank you, Stephanie. Good morning, and welcome to the 2013 first quarter earnings conference call for Enbridge Energy Partners.

This call is being webcast and a copy of the presentation slides, supplemental slides, condensed unaudited financial statements, and news release associated with it can be downloaded from our website at www.enbridgepartners.com. A replay will be available later today and a transcript will be posted to our website shortly thereafter. As a reminder, the partnership’s results are also relevant to Enbridge Energy Management or EEQ. I will be available after the call for any follow-up questions you may have.

Our speakers today are Mark Maki, President; and Steve Neyland, Vice President, Finance. Available for the Q&A session, we also have Steve Wuori, President, Liquids Pipelines, Enbridge, Inc.; Leon Zupan, Chief Operating Officer, Liquids Pipelines, Enbridge, Inc.; Terry McGill, Senior Vice President, Operations and Engineering; Darren Yaworsky, Treasurer; and Bill Ramos, Controller.

This presentation will include forward-looking statements. The risks associated with forward-looking statements have been outlined in the earnings release and the partnership’s SEC filing, and we incorporate those by reference for this call. This presentation also contains certain non-GAAP financial measures. The reconciliation schedules for these non-GAAP measures to comparable GAAP measures can be found in the Investor section of our website.

Please turn to Slide 3. I will now turn the conference over to Mark Maki, President.

Mark Andrew Maki

Thank you, Sanjay. Good morning, and welcome to our First Quarter 2013 Earnings Conference Call. Before outlining this morning's agenda, the partnership's management team would like to congratulate Leon Zupan on his recent appointment to the role of Chief Operating Officer for Enbridge's Liquids Pipelines business. Leon is a tremendous leader, and his 25-plus years of experience in Enbridge, predominately in the Liquids Pipeline organization, position him as the natural to assume the COO role. We thank Leon for his leadership here in Houston, and we look forward to continuing our close working relationship with Leon in his new role. As it relates to our agenda for this morning, I will provide an update on the partnership's growth program, along with our long-term growth outlook and then pass it along to Steve Neyland to present our financial highlights. Please turn to Slide 4.

The partnership has made visible progress on our growth program this quarter, and we are pleased to announce the Bakken Pipeline Expansion Project and the Bakken Berthold Rail Project were both placed into service. The Bakken Pipeline Expansion Project provides an incremental 120,000 barrels per day of take away capacity from Beaver Lodge, North Dakota to Cromer, Manitoba, where the pipeline connects to the Enbridge main line. This project has 79,000 barrels per day of ship-or-pay volumes in 2013 and it ramps up to 100,000 barrels per day in 2014.

Our Berthold rail facility can accommodate unit train movements and will ramp up to provide 80,000 barrels per day of takeaway via rail over the next couple of quarters. These projects provide incremental takeaway for growing crude oil production from the Bakken region and ultimately enhance the flexibility for our customers. Additionally, we anticipate our Bakken Access project will enter service this quarter and will offer 100,000 barrels per day of gathering and truck-end loading facilities into our system.

Next, we are working diligently to secure the future of the partnership, while delivering in our commitment to achieve industry leadership in the key objectives of system integrity and safety. Through these efforts, we are significantly enhancing the integrity of our Line 6B. Portions of our Line 6B's 75-mile replacement project were placed into service in April, with the remaining portions entering service over the next couple of quarters.

As it relates to our Eastern Access projects, the 220-mile Line 6B replacement is progressing well and will phase into service in early 2014, and this will expand the line's capacity from 240,000 to 500,000 barrels per day between Griffith, Indiana and Sarnia, Ontario. Next, our Line 5 expansion is scheduled to provide an incremental 50,000 barrels per day of capacity from Superior, Wisconsin into Sarnia this quarter. Finally, our Line 62 Spearhead North Pipeline Expansion project will increase the line's capacity from Flanagan, Illinois to the terminal at Griffith, Indiana, by 105,000 barrels per day by the end of 2015.

Turning to our mainland expansions. The first phase of our mainland expansions, specifically the upsizing of both Line 67 and Line 61 by adding pump stations, is progressing on schedule and will enter in service in conjunction with Enbridge's expanding corridor to the U.S. Western Gulf Coast via the Flanagan South and Seaway twin expansions.

Moving on to the Sandpiper project. In late March, the FERC denied the partnership's petition for declaratory order on procedural grounds related to the partnership's objective of achieving rate certainty for the cost of service parameters of the project. The project is an integral component of our lighter oil market access strategy, which links North Dakota supply with the demand pull of the eastern and southern markets. We plan to refile our petition with the FERC to address their concerns. The pipeline is expected to begin service in early 2016, subject to obtaining regulatory approvals and finalization of scope.

Turning to natural gas. The partnership's natural gas projects are also proceeding on schedule. Our $150 million cubic foot a day Ajax cryogenic natural gas processing plant is mechanically complete, and we plan to begin commissioning the plant once the associated NGL takeaway infrastructure is up and running. The Texas Express NGL pipeline and gathering project is progressing well and is on track to begin service in the third quarter of this year. The pipeline will provide 280,000 barrels per day of much-needed NGL takeaway capacity from the liquids-rich basins in the Mid-Continent, Texas and the Rockies through interconnected pipelines to the premier NGL market at Mont Belvieu, Texas. As you can see, we're very pleased with the progress of our -- on our organic growth platform, and we are focusing on delivering these projects on time and on budget.

Let's move on to Slide 5. The partnership is pleased to announce that it's expanding its natural gas footprint in East Texas with plans to construct a $150 million cubic foot a day cryogenic natural gas processing plant near Beckville in Panola County, Texas. The new plant will offer incremental processing capacity for existing and future customers in the 10-county Cotton Valley Play region, a very productive gas-rich region. The addition of Beckville plant will expand the partnership's processing capacity to approximately 820 million cubic feet a day in the East Texas area. The Beckville plant project will integrate very well with our existing infrastructure and our extensive East Texas gathering and gas processing system.

In addition to Cotton Valley, there are other liquids-rich zones in the region. We have already procured the cryo plant equipment and construction of the East Texas Beckville plant is expected to begin late in 2013 with an anticipated service in early 2015.

Let's move on to Slide 6. The Market Access Programs announced by Enbridge and the partnership are a key strategic initiative we have collectively undertaken to open access to the best markets along the U.S. Gulf Coast, the U.S. East Coast, the U.S. Midwest and Eastern Canada. Our pipeline projects will match growing North American supply to markets that have traditionally been served by foreign offshore imports. We have previously discussed the current market environment of price dislocations for crude oil between inland crude and the waterborne equivalent. North American supply is priced at a discount to imported Brent, Mayan and similar barrels due to current infrastructure constraints and supply and demand imbalances. Collectively, Enbridge and the partnership's Gulf Coast Market Access Program, Eastern Access and Lighter Oil Market Access initiatives will match growing North American crude oil supply to the key refining centers, and this should improve producer netbacks and refiner supply access.

There is a lot of detail on this slide, but I'd like to focus on one key point. The key difference between Enbridge and other pipelines is the diversity of premium markets that the partnership's Lakehead system and the connected Enbridge systems are positioned to access. Our North American pipeline system is ideally positioned to provide light crude oil capacity to the east, increase heavy capacity to Midwest and serve markets as far south as the Western and Eastern U.S. Gulf Coast. Transportation and market access constraints have resulted in large crude oil price differentials between certain domestic supply basins and key refining centers, and this has led to the emergence of rail as a meaningful transporter of crude oil. Consistent with the views of some of our peers in the industry, in the medium-term, we expect rail will satisfy refining demand to the U.S. West and East Coast markets. And once our secured Market Access Programs are completed during the 2016 time horizon, we believe the current environment of historically wide crude oil price differentials will be alleviated. We will be able to deliver substantial volumes of crude oil to new markets. The cost to access these markets by pipe will be significantly more competitive than by rail.

Moving on to Slide 7. The chart presented on this slide provides an overview of the partnership's organic growth program in respect to project in service states. Our growth projects will provide the partnership with visible, long-lived stable cash flows, which are secured by commercial structures that control key risk elements of volume and commodity price variability. The partnership's distributable cash flow will grow as these projects ladder into service beginning now through early 2016. Project execution is a key priority for the company, and our major projects group is diligently focused on delivering all the projects on time and on budget.

Please turn to Slide 8. The substantial growth on the Liquids side of our business will shift the partnership's earnings and cash flow profile heavily weighted towards crude oil over the coming years. As depicted on the chart, collectively, these Liquids Expansion projects are transformative, and they will progressively move the partnership to an even lower risk business model. The long-term, low-risk commercial frameworks underpinning this project, such as cost of service and take-or-pay, will provide visible and sustainable stream of cash flows to the partnership and our unit holders.

Let's move forward to Slide 9. I'll turn the call over to Steve to review our financial results.

Stephen J. Neyland

Thank you, Mark. First quarter adjusted net income of $95.7 million was $13.5 million lower than the same period of 2012. Higher revenues on our liquid pipeline systems were more than offset by the impact of lower natural gas liquids prices in our natural gas business. The main items eliminated from these adjusted results include unrealized noncash mark-to-market net gains and losses, additional environmental costs net of insurance proceeds associated with the Line 6B incident and other items noted in our supplemental slides.

Adjusted earnings per unit for the first quarter was $0.21, compared to $0.28 for the same period of 2012. The first quarter of 2013 saw lower adjusted earnings and a higher number of weighted average number of units outstanding when compared to the first quarter of 2012. Our as-declared coverage ratio for the quarter was 0.79x, which was in line with our guidance range and consistent with last year.

Please turn to Slide 10. For our Liquids segment, adjusted operating income of $154.3 million for the first quarter was $4.7 million lower than the same period for 2012. Also, first quarter 2013 adjusted operating income was $21.3 million higher than the fourth quarter of 2012. When comparing to last year, first quarter operating revenues increased due to an increase in index transportation rates on our systems, as well as increased revenues associated with our Cushing storage facilities. This increase was more than offset by the decrease in volumes transported on our North Dakota system, in addition to higher operating and administrative expenses attributable to higher property and business taxes and higher workforce-related costs.

With the recent environment of high regional crude oil price dislocations and rail transportation emerging as an alternative method of shipping crude oil to key markets, rail has become a stronger competitor to our North Dakota system and decreased our system utilization over the past couple of quarters. Fundamentally, the emergence of rails tied to transportation constraints and bottlenecks that we expect will be alleviated as future pipeline expansions enter service, enhancing market access to Canada, PADD II and other markets.

Volumes on our Lakehead system were strong at 1.84 million barrels per day during the first quarter, which was 5.7% higher when comparing current quarter over the fourth quarter of 2012. We expect Lakehead volumes to increase as the year progresses due to strong North American crude oil supply and demand fundamentals. Volumes on the North Dakota system declined in the first quarter relative to the fourth quarter due to rail competition, although the North Dakota revenue decline was slightly offset by ship-or-pay commitments from the Bakken Pipeline Expansion project, which came into service at the very end of the first quarter at -- on March 1.

During the first quarter, we increased our cost estimate related to the Line 6B incident by $175 million to $995 million, in response to the recent order received from the EPA in March for us to pursue additional containment and recovery of submerged oil. We are working with the EPA on the work plan for this additional remediation work. We have collected $505 million of insurance recoveries to date and expect to collect the remaining $145 million that is covered under our insurance policy in future periods.

For our natural gas -- excuse me, please turn to Slide 11. For our Natural Gas segment, adjusted operating income of $26.4 million for the first quarter was $26.1 million lower than the same period in 2012. The decrease in the first quarter Natural Gas adjusted operating income over prior year was primarily due to lower NGL prices, in addition to ethane rejection experienced at some of our plants predominantly situated in the Mid-Continent.

Natural Gas lines on our East Texas system were slightly higher than the previous quarter. Lines on our Anadarko system decreased modestly over the fourth quarter of 2012, due in part to periods of unfavorable weather conditions impacting producer drilling activity during the first quarter. Additionally, we are seeing producers targeting oilier zones which produce less gas but higher NGL content.

Let's move forward to Slide 12. We continue to make progress on our organic growth capital program, as the Bakken expansion pipeline and the Bakken Berthold project were both placed into service during the fourth quarter -- excuse me, during first quarter. Additionally, we expect our Line 5 expansion and Bakken Access projects to begin service in the second quarter.

We reduced our 2013 capital expenditure forecast by $125 million to $2.16 billion. The impact of funding our long-term construction projects and the lag in cash flow generation have resulted in elevated credit metrics. Additionally, in March, we increased our total cost estimated related to Line 6B incident by $175 million, as previously noted. As a result of these factors, management anticipated an elevated leverage ratio in excess of our covenant in each of our credit facilities. In late March, the partnership received waivers from our lenders under each of our credit facilities, leaving our compliance with a consolidated leverage ratio determined as of March 31, 2013. We expect our credit metrics to improve in future periods as our assets continue to ladder into service and as we are able to access capital markets or other sources of financing.

Financial execution and timely access to capital to fund our attractive organic capital growth program remained key focus areas. We enhanced our liquidity during the quarter and are evaluating actionable opportunities to secure capital as part of our funding plan, while maintaining our strong investment grade rating. Recent actions to enhance our liquidity and secure capital, include: first, in February we closed on an underwritten public offering and a sale of $10.35 million listed shares of Enbridge Energy Management or EEQ as it's better known, including an over-allotment option yielding net proceeds of $273 million. Also, in February, we upsized our 3-6-4 day credit facility by $425 million to a new limit of $1.1 billion, providing an aggregate of $3.1 billion in committed credit facilities.

I want to remind you that the partnership holds separate options to reduce its funding requirements by over $700 million, pursuant to the Eastern access and Mainline Expansion Joint Funding agreements with our general partner, by pairing back its economic interest in associated funding of these liquids expansion projects from 40% to 25%. We continue to evaluate this option and have until June 30 of 2013 to make a decision. Additionally, the partnership holds separate options to increase its economic interests in these projects by up to 15 percentage points 1 year after the last project in service date of each of the respective projects. Lastly, as discussed at our Analyst Day in March, we continue to evaluate a number of opportunities to secure capital and enhance our financing flexibility pursuant to our funding plan.

For further details, our financial results for the quarter, I encourage you to review our supplemental slides that are posted on our website.

Moving forward to Slide 13. The graph provides perspective as to how these previously discussed secured projects will improve our distribution coverage and enable the partnership to achieve this distribution growth target. With our large capital program, current-year distribution coverage is expected to be below 1x. The green part of the bar represents the potential range of outcomes in 2013 depending on various economic and operational factors. Our track record demonstrates our commitment to manage through these robust expansion periods as we did in 2008 and 2009. The long-term low-risk commercial underpinnings of our accretive growth projects, in addition to visible distribution cash flow growth, provide us with a high level of confidence in improving distribution coverage and strengthening credit metrics.

Please turn to Slide 14, and I'll turn it back over to Mark to address the key takeaways.

Mark Andrew Maki

Thank you, Steve. Just a couple points of emphasis in closing before the Q&A period. Long-term outlook for the partnership remains strong. Our $8 billion organic growth program is proceeding on schedule and will progressively transform the partnership towards an even lower-risk business model as the cash flows are secured by long-term, low-risk commercial frameworks. We remain focused on safety integrity of our pipeline systems and managing the execution of our growth program. The partnership's distributable cash flow will increase as our growth projects ladder into service, which will secure our long-term distribution growth outlook. And with that, Stephanie, can you please open the lines for Q&A?

Question-and-Answer Session

Operator

[Operator Instructions] Okay, the first question comes from Brian Zarahn from Barclays.

Brian J. Zarahn - Barclays Capital, Research Division

On the East Texas processing plant project, can you give a little color on the contract mix, and some commodity price assumptions you have regarding your EBITDA multiple -- expected EBITDA multiple?

Mark Andrew Maki

Sure. The contract mix is going to be a mix of fee-based and, largely, percentage of liquids-type arrangements, and very similar what our existing plants up there have. The -- as far as EBITDA assumption, traditionally we look at this sort of thing recognizing there is variability to the commodity component. We're talking some place in the 6 to 8 kind of range is a pretty good EBITDA multiple. The commodity price assumptions that we use in evaluating a project like that are really heavily weighted towards forwards in the near-term. And then over time, what we do is we work in weighting with a series of external forecasters, folks you would recognize if I told you the names. And we tend to weight that out maybe 50% forwards-50% these analysts in the future years. I would say our expectations for commodity prices, generally, we would expect the ethane to start showing some improvement in that '16 kind of '17 timeframe. In the meantime, it's going to be relatively soft. Propane, we do expect to improve, as you've seen of late, and that should continue with the work that's been done by Enterprise and Targa and others to enhance export out of the U.S. So that gives you a little bit of color as far as what we -- how we look at commodity pricing and price deck, and I think, covered off [ph] the key components of your question. If anything else, just follow up.

Brian J. Zarahn - Barclays Capital, Research Division

And then on the North Dakota system, do you think pipeline volumes are sort of bottom at these levels, or do you think -- do you expect a little improvement, given your gathering system, should help drive potentially more volumes through your pipes?

Mark Andrew Maki

Steve Wuori, can you fill that? I think you want to catch that one?

Stephen John Wuori

Sure. Okay. I think we have seen the bottom. Now that's always hard to tell and a lot of factors can go into it, I guess. Certainly, our nominations for May are up about 20% or so from the prior months, so that's encouraging. There's really 3 routes out of North Dakota on our system. Now there's the North Dakota Classic system, the North Dakota mainline and there's the Bakken expansion program that both Mark and Steve have talked about. And then there's the Berthold rail. And the Berthold rail really takes advantage of capacity we have all the way in from Montana and Western North Dakota into that rail facility, I think, as we've discussed previously. But we are seeing volumes come back. We've seen differentials at Tidewater markets start to tighten in as we expected would start to happen, and we'll just see if that's -- it's a little early to call that a strong trend, but certainly the early indications are good.

Douglas Montgomery

A final one from me. Should we read anything into your lowered expansion CapEx in terms of the -- your option to downsize your stake in Eastern access and mainline?

Stephen J. Neyland

Brian, this is Steve. The change in the CapEx, I don't think there's a lot to read into it. It's just timing. As we move through these projects, the profile, the spend, becomes more and more refined as better information comes into play. So it's really just fine tuning of the estimates.

Operator

The next question comes from Ted Durbin from Goldman Sachs.

Theodore Durbin - Goldman Sachs Group Inc., Research Division

I want to start with the Sandpiper project, and you mentioned how the FERC asked you to come back and reconfigure it. I'm just wondering what are your options? How you're thinking about you'll go back to the market with that? Does it change the return profile? I think you talked about a 6x multiple. Does it change the contract terms you'll go for? I think 15 years is what you're looking for. Maybe just a little bit more on your plans on the Sandpiper.

Mark Andrew Maki

Yes, this is Mark, Ted. I'll let Steve catch the details in the question. I don't think we had a 6 multiple on that project. You may be thinking of some other North Dakota initiative, but a mainline project like that with additional cost-to-service sort of underpinning would be more in the 8 kind of range, maybe a little higher than that. But Steve, do you want to talk about the strategy as far as the FERC filing?

Stephen John Wuori

Yes. Ted, you mentioned contracts. But actually this isn't a contract pipeline, it's a common carrier add-on to the North Dakota common carrier system. So what we're doing is analyzing what the FERC came back with when they denied the petition for a declaratory order and we're going to address those things and refile. I think Mark mentioned that there certainly were strong letters of shipper support. There were 15 letters that were submitted in support of the project, but there were 5 that were submitted in opposition or expressing concerns. And I think the FERC took that into account, so we'll be working on those folks and working with them. And generally, just looking at what the sensitivities may have been around their decision, the sense we have is that we were very close to having a successful application, however, there is some tweaks that need to be made when we refile. But we'll still refile it as a common carrier addition to the North Dakota system.

Theodore Durbin - Goldman Sachs Group Inc., Research Division

Okay. That's helpful. The 6 multiplier, was just referring to your Analyst Day slide, so maybe I missed that but I just -- anyway, just wanted to check on that. The other thing was just on the cleanup costs here, these continue tick up. I guess we're now close to $1 billion. Can we get some confidence that we're done with the cost going up there? Is there -- kind of, what else is left in terms of the cleanups? And then can you just remind us on the recovery there? I think you said in the past that you'll get recovery, just the sort of cost of service tariff changes. Is that still true here with the higher costs?

Mark Andrew Maki

Well there are a couple components to your question. We'll go to Steve, as far as the overall cost and kind of where we stand with the process. But going to the cost of service comment first, the amount of the leak cost over our insurance coverage, which -- our coverage is about $650 million for the incident. So basically, we have to absorb that cost above the insurance coverage. With respect to recovery of -- we can't recover that $350 million, or don't intend to recover that $350 million through tolls. What we are recovering through tolls is the work we've had to do on Line 6B as it relates to the -- effectively, the replacement of the pipeline. So that the company is recovering through tolls along with the -- some of the work we've done on the old 6B pipeline. But the cost of the leak above the $650 million, that's the company's cost. The integrity program and the replacement of Line 6B, that is being recouped through a cost of service mechanism. Steve, do you want to talk about the -- where we stand as far as the leak cost estimate?

Stephen J. Neyland

Sure. Well I think the estimate represents our best estimate of all current and future costs associated with that leak. And of course, we review that whenever there's any new development like the EPA order. We're down to just 5 specific areas that were named in the EPA order out of the entire cleanups that started in 2010. And the truth is, there's not much left to do there other than address those areas that the EPA has pointed to, which we are in the process of doing. The river has been reopened. The first section was reopened last April and the river was fully reopened for all recreational use, including swimming and everything else, last July. So that's been a real positive in the Marshall and Battle Creek, Kalamazoo area. And these specific areas we'll just continue to work on in conjunction with the EPA and the Michigan Department of Environmental Quality. And when we're finished, we're finished.

Theodore Durbin - Goldman Sachs Group Inc., Research Division

Okay. And then if I could just do one more here -- I appreciate that. In terms of the mix, as you think about your financing plans of EEQ versus EEP for your equity needs, I guess, how are you thinking about that? You've obviously -- if you use EEQ, it reduces the upfront cash payouts but it also increases the dilution over time. So kind of that balance between the 2, how are you thinking about that?

Mark Andrew Maki

Darren, you want to field that question, please?

Darren Julian Yaworsky

Certainly. I think we look at the 2 vehicles as providing us options that we probably didn't have a year ago, with the reintroduction of EEQ into the marketing increasing liquidity in that vehicle. But I don't think there is any publicly disclosed preference between the 2 vehicles, but it does give us a funding option that we didn't have about a year ago, in that EEQ is available to us.

Operator

The next question comes from the line of TJ Schultz from RBC Capital Markets.

TJ Schultz - RBC Capital Markets, LLC, Research Division

I guess, if I could just go back to Sandpiper, just unclear. I think the filing did note some protest to the contractual structure and some of the routing. Is this relatively standard, or does this imply some pressure on the terms? And just to be clear, because this is a pretty sizable project, I think you all did imply a 6x return, maybe this year an 8x return. But just to be clear, as you move through this process, is that still a range that you're comfortable with on Sandpiper?

Mark Andrew Maki

The filing we had with respect to Sandpiper had a lot of specifics in it that the FERC generally doesn't deal with until the pipeline effectively is in service, and so we tried to get as much certainty in the process as we could. And of course, as far as some of the intervenors go, they've got their own issues and as Steve pointed out with his comments, we hope to address some of those over the next little while before we file the next go-round of this. We may have to have less specificity in terms of returns and so forth. But generally speaking, the FERC model is pretty predictable in terms of the returns you're going to get. We tried to nail down as many of these factors as we could, and we -- certainly in an area that's not charted particularly well. And I guess Steve pointed out we expect to be able to deal with some of those in the near future TJ. Now Steve, anything else you want to add to that?

Stephen J. Neyland

No. I think, Mark, you've covered it well. I mean, seeking the specific rate inputs through the PDO process hasn't been done before. We certainly did that -- didn't do that out of the dark. We had consulted with FERC staff before doing that. But that does reach, as Mark said, to really nailing down the rate parameters that typically the FERC doesn't deal with until 60 days in advance of a project going in service, so we'll work with that. You mentioned routing concerns. There actually aren't routing concerns. I think the concerns expressed by those that wrote in objection or expressing a concern really were mostly around the commercial issues as it affects them specifically. So let's say there was a refiner who is benefiting from low North Dakota crude prices, there'd be little incentive for that company to want to see the toll rise, which it will on behalf of everyone when Sandpiper is built and greater capacity to other markets is achieved. So I think you have to look at each individual submission and why they submitted it and that's what we're doing right now.

TJ Schultz - RBC Capital Markets, LLC, Research Division

Just kind of moving onto Line 5. I think this was initially pegged to come on last quarter, maybe it looks like it's still to come. So any update there on kind of timing? And then once Line 5 is up, maybe if you could just expand or try to quantify what you would expect on that impact on North Dakota volumes, as I think that would pull more volumes out of the original pipe over to Eastern Canada?

Stephen J. Neyland

Yes, TJ...

Mark Andrew Maki

Steve, go ahead and take it.

Stephen J. Neyland

Okay. I'm overeager this morning. Sorry, Mark. So TJ, that's -- it's very close. I think there's one valve we're waiting for or something like that. So it's basically ready to go, and that's a 50,000-barrel a day expansion. And it's pretty hard to say that that will hardwire to an exact 50,000-barrel a day increase on the North Dakota system because, of course, Line 5 carries light crude from North Dakota, Saskatchewan and Alberta, for that matter. But notionally, having a 50,000 barrels a day of light crude market that didn't exist before by pipe is a very important dynamic and there's no question, I think, that it will draw at least a strong proportion through the North Dakota system. It really ought to as, generally, the Bakken barrel is seeking a barrel that is not in Cushing or Houston. So that -- we should see the effect of that as we put that into service this quarter and then watch how the volumes generally react on North Dakota. I wouldn't want to predict though that it would be one-for-one.

Operator

The next question comes from Sharon Lui from Wells Fargo.

Sharon Lui - Wells Fargo Securities, LLC, Research Division

Just wondering if you've had recent discussions with the rating agencies about your debt metrics? And, I guess, maybe if you could just touch on, I guess, the waivers that you received on your debt covenant? Is that only applicable for the first quarter? And do you plan to seek another waiver for the second quarter?

Mark Andrew Maki

Darren, do you want to field that, please?

Darren Julian Yaworsky

Certainly. Maybe I'll address your second question first and your first question second. The waiver was specifically for Q1 and the waiver was not secured for Q2, but we anticipate, as Steve mentioned in his piece, that we will be correcting that breach as it's tested for Q2. Your first question, we have discussed both the waiver and the debt levels with the rating agencies, and they haven't given us any concerns to believe that their current rating perspective on us has changed.

Sharon Lui - Wells Fargo Securities, LLC, Research Division

Okay. And, I guess, with regards to improving the metrics for Q2, is that based on, I guess, an anticipated improvement of the dial levels from projects, or, I guess, a reduction in, maybe, the Q2 level of capital spending?

Darren Julian Yaworsky

We're advancing a number of initiatives that haven't reached the point of public disclosure, but those initiatives will be addressing the Q2 covenant. Steve or Mark, do you want to expand on that at all?

Mark Andrew Maki

No. That as good answer as you can give.

Stephen J. Neyland

Yes. I would say -- I'll just add that, additionally, the projects laddering into service we've talked about, the Line 5, Bakken expansion and so forth, are also complementary to other initiatives. So all those things are working in unison.

Sharon Lui - Wells Fargo Securities, LLC, Research Division

Okay. And then I guess for the Natural Gas segment, were adverse weather conditions a major negative impact in the first quarter results?

Mark Andrew Maki

There was an effect on the gas business in the first quarter because of weather. We've seen that from some of the folks that are in the MLP space that are producers in the Mid-Continent region. They made a point of it. We did see some effects as well, but I wouldn't call them significant in the quarter. It was a factor, but I wouldn't say it's enough to call out.

Operator

The next question comes from Louis Shamie from Zimmer Partners.

Louis Shamie

Just had a couple of questions. First off, I just wanted to follow up on the Sandpiper questions from Ted and from TJ. From what I understood from what the FERC commissioners wrote was that they found that because you hadn't secured actual contracts for the capacity and you're looking to just kind of get a surcharge on your existing rates for existing shippers, and not all of those shippers were supportive of the project, it sounded like the commissioners had trouble with just kind of that basic structure. Are you planning to change your method of return recovery on the project to address that? Or how do you get around those obstacles?

Mark Andrew Maki

Steve, can you take that?

Stephen John Wuori

Yes. Well we're developing that response and refiling right now, so I don't have a definitive answer as to exactly what's going to be in that filing. But it's clear that there are some shippers for whom pipeline scarcity is actually a benefit. And so, therefore, we have that factor to consider. But for the vast majority, and for the state of North Dakota, for the industry generally, and, I think, in view also of the FERC, pipeline capacity additions are a good thing and that's why they are generally supportive. And if you look at the -- at the split on FERC as to who assented to the decision and who dissented, there clearly are differing views on even the specific rate inputs that we sought. Generally, a contract pipeline, should a project go that way, has the advantage of certainty for certain shippers but it also effectively denies access to small shippers, those who can't put up the credit requirements that a contract pipeline demands, the long-term balance sheet impairment and so on. And that's why generally, our feedback over the last 2 years as we've discussed the Sandpiper project with the hundred-and-some shippers that we have or could have, we generally find a strong desire for a common carrier, very much like on the Enbridge and Energy -- Enbridge Energy Partners mainline system, which is a common carrier. And the industry very much supports common carriage. However, on Sandpiper, we were seeking for certainty of rate inputs, which as I said earlier, the PDO has not previously been used to provide. And there are certain shippers that have structural advantages by not having pipeline capacity added. So therefore, we will be balancing all of those as we consider a refiling with the FERC. And then the FERC will take into account all of the various points of view and all of the various motivations and ultimately, what's best for the public and for the producers and the shippers. So that's about all I can say at this point. We're certainly looking at what was in the FERC opinion and what was behind it, and we'll be addressing each of the elements as best we can.

Louis Shamie

Great. And in a worst-case scenario where, for some reason, FERC -- you're not able to get past the FERC, and for whatever reason they don't approve your refiling, does this pose any risk to the other projects that you have downstream of Superior?

Stephen J. Neyland

Well I think I'm going to start with the premise that when we refile, knowing what the first filing look like and the response, we should have a successful conclusion. Sandpiper is very much a needed project. I think there is near-universal agreement on that. There are no other large pipeline export projects out of the Bakken, except potentially Keystone XL on the very west side that would take a certain amount of crude to a market that we do not view as attractive for Bakken expansion production, or the expansion of Bakken production. So we really feel that there is the need for a pipeline project to increase export capacity generally to Eastern markets and Eastern PADD II markets. So that's why our determination, after studying this for a long time, is to ensure that we've got a project that moves forward. If it has to be a contract pipeline, I guess that's another possibility. Again, for the reasons I mentioned and the feedback from shippers, generally, we'd prefer not to go that way and we are not at the moment. However, I can tell you there are shippers who would be willing to make commitments to a contract pipeline if that's the way it were to go. But right now, I think the better course clearly is to make sure that we pursue common carriage to the full extent that we can.

Louis Shamie

I see. That's a really good explanation. And then my final question, just kind of is a follow-up to Sharon's question on leverage and funding your capital needs. What factors are you considering in terms of exercising the option to put some of the projects back to the parent? And when you talk about the possible plans that you have to improve the credit metrics this quarter, what kind of things are on the table?

Mark Andrew Maki

Well we can't get any more specific on the last part of your question, Louis, than we already have been. So you understand the formula and there's -- you either raise EBITDA or you change debt effectively. So going to the -- as far as other things we're considering with respect to the option, one of the key drivers that we're going to look at is the amount of capital the partnership needs to raise and the nice thing about the option from the parent is it does give us a very certain lever we can exercise to mitigate, or -- some of the financing burden that is on EEP, so that option is very valuable. Not in any hurry to exercise until we have to. And -- but certainly, recognize we've got a lot of great projects that we're working on. And if, to mitigate the amount of capital we have to raise, exercising the options seems like the most prudent thing to do, then that's what we'll do.

Operator

The next question comes from Ross Payne from Wells Fargo.

Stanley Ross Payne - Wells Fargo Securities, LLC, Research Division

Steve, obviously, with your leverage metrics a bit stretched at this point, but hopefully moving down as some of these projects come online, can you speak to where you are with the rating agencies? Are you comfortable that you'd be able to maintain your BBB, or what are your thoughts there?

Stephen J. Neyland

Yes, we remain confident in our investment grade rating that we have currently. Staying in contact with them and keeping them close in the process remains key to it. And as noted earlier and also in our Analyst Day discussions, there's a number of options we have. And as we see these -- as Mark noted in his open comments, with all of these projects coming into service, we're starting to see those show up. That's helpful. And so that combination together says, "Hey, we're bringing our projects in service as we expected," And I think that's a positive for the rating agencies. So we remain confident in our current rating.

Operator

The next question comes from Chuck Goldblum from Hurley Capital.

Chuck Goldblum

Just looking at, sort of, EEP overall, we've got high debt metrics, low coverage ratio, extra costs from the store mediation, none of this stuff is new. High capital costs, high yield on the units. And you guys have the best assets in the world and a ton of great projects ahead of you. Isn't there something you guys can do to relieve the pressure from the partnership, high funding costs at the high yield, to the betterment of unitholders like us?

Darren Julian Yaworsky

Well one of the things, I think, that has historically been very -- if we look at that, Chuck, what the partnership has done in terms of its relationship with the parent company is the parent has been there when we've had periods of large capital raise for great projects like the ones we've got in front of us. The joint funding arrangement, as an example, with options up and options down is a very powerful mechanism where the parents agree to take a lot of the burden off the partnership so we can execute on the projects. And that way, we would participate in them and they become candidates for dropdowns later on. I think that's a tremendous advantage that this partnership has versus others. Certainly, parent has been historically very supportive of EEP. I would expect it to be very supportive in the future. And if you look at the past, they've been either invested directly in units, they've provided credit facilities to the partnership, the joint funding arrangement now, joint venturing in certain projects, I think that is the thing I would point to as being -- and there's certainly other things that can be done in that area. And definitely the management is very focused on trying to moderate the amount of capital the partnership needs to raise and -- so we can realize the benefits from these great projects.

Chuck Goldblum

I know the parent has been supportive, almost like -- and I don't want to say it on a recorded call, but almost like how we support my indigent aunt. Once she's on the brink of being poor, we feed her [ph]. And I feel like there's so much more, and as it relates to these refinery-based MLPs who are basically selling their truck racks and are yielding 3%, you guys are building giant liquid pipelines and yielding 7%, 8%. So is there some way that the parent can support, perhaps to be a dropdown for units, that would enable EEP to develop these expansions at a lower cost of capital? I mean there is plan for you dropdowns down the line. Just -- why wait till the party's over?

Mark Andrew Maki

Well we certainly look at -- we have lots of ideas. We look at lots of different options in terms of funding. It is a little bit of -- too much, perhaps, of a good thing. We've got great organic projects. And organic projects don't especially fit all that well inside of MLP, especially the size of the ones that we have here. Historically, we've been very good about getting these projects online, on time, very close to budget, under budget, at best slightly over budget, if you go back through our history -- Southern Access, Alberta Clipper and others -- and they basically do what we say they're going to do. So patience, I guess, to a degree we are asking for. But the partnership is always looking at other alternatives to try and fund these programs in the most cost-effective fashion that we can. And there has been a heavy reliance, historically, on the partnership. As far as dropdowns, right now, a dropdown would be probably more harmful than helpful because what you're adding to is the already large financing burden the partnership has. So I just don't see that as a fix right now. But certainly, down the road, as organic growth opportunities play out and we've got less of those and a much bigger partnership, we're absolutely then in a position I think to take those from the parent.

Operator

The next question comes from John Edwards from Crédit Suisse.

John Edwards - Crédit Suisse AG, Research Division

Just a follow-up, I guess, some questions or maybe comments you made earlier. Looking at Slide 11, just the sequential decline in the gas segment the last couple of quarters while volumes have been relatively flat. And you -- -- we were a little bit surprised by this because we thought you'd pretty much hedged the cost out on the Natural Gas side. So we're just trying to -- was this a kind of a squeeze on margins because of lower natural gas liquids prices? But we were sort of expecting that as well. So we're just -- if you can you give a little more clarity on that, it would help.

David K. Wudrick

Sure, John. Yes. So I think there was a combination of smaller things that are not helpful to Q1 in 2013 for the gas segment. Mark mentioned some of the weather impacts in the area. Additionally, just some true-ups of some of our margin estimates also factored into the numbers. So there are couple of aspects, as well as we're rejecting ethane to an extent in the Mid-Continent. Of course, you get those molecules back as natural gas, so there's some push and pull in there, but that's another aspect. So you're right, though. On our hedging, as noted, we're in excess -- we're in the 70%, 75% hedged range for the year. And so we remain in that position as we move forward on a rolling 12-month basis.

John Edwards - Crédit Suisse AG, Research Division

Okay. So I guess -- so the summary -- a comment -- so it wasn't just commodity price squeeze? There was some other...

Stephen J. Neyland

Yes. There are elements certainly of commodity price in the pushdown also.

Operator

The next question comes from Scott Pergamum [ph] from Credit Suisse.

Unknown Analyst

Just a -- kind of a housekeeping on the Bakken expansion that was just placed in is a take-or-pay. You mentioned it was -- is it 50,000 currently and it'll go up to 100,000 next? Or is it 100,000 incremental next year?

Mark Andrew Maki

It's -- the increment is the difference between the 100,000 and the 79,000 or so. I think the contracted capacity is about 79,000 barrels a day in '13 and it steps up to 100,000 in '14. But it's not an incremental 100,000 on top of the 79,000.

Unknown Analyst

Okay. Okay. And just -- I mean what was the thought process? With your plate so full that you're even doing this East Texas natural gas? I mean, that's commodity price exposure to your overall business mix, and quite frankly, it's even -- even at a wonderful EBITDA multiple, it's not going to really move the needle considering the size of your other holdings. It just seems to me that you're just adding more CapEx without -- when you're already a little bit stretched, something that's not in the direction of where your company is going.

Mark Andrew Maki

Yes. I hear you on that question. It's a very good question, Scott. I'll tell you, we've -- East Texas system for us is a very important part of our future down the road. And if you don't take care of the assets that you've got, you're going to see value deteriorate there, and we didn't want that. So when we look at a gas investment right now, we're very, very picky about what we're looking at. We're not off looking at areas we currently are not in or we don't see a benefit to our existing platform. So you don't see us marching around the Marcellus looking to do something or in the Niobrara or wherever. We're very much focused on our existing footprint and making sure that we improve the strength of the existing footprint. In our financial planning, capital that we're raising for the business, we do provide for some of these, kind of, smaller scale projects that in our view enhance the strength of the existing business. So this was already effectively in our financial plan by and large, and that's how we look at it. So I hear you. It's a good question. We see this is a very important strategic step for us in the East Texas area.

Operator

Thank you. There are no more questions. And I would like to turn the call over to Mr. Sanjay Lad for closing remarks.

Sanjay Lad

Thank you, Stephanie. We have nothing further to add at this time. However, I would like to remind you that I will be available for any follow-up questions you may have. Thank you and have a good day.

Operator

Thank you. Ladies and gentlemen, that concludes your conference call for today. You may now disconnect. Thank you for joining and enjoy the rest of your day.

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