National Fuel Gas Company (NFG) Q3 2014 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to the Q3 2014 National Fuel Gas Company Earnings Conference Call. My name is Whitley, and I'll be your operator for today. [Operator Instructions] As a reminder, this call is being recorded for replay purposes. I would now like to turn the conference over to your host for today, Mr. Tim Silverstein, Director of Investor Relations. Please proceed, sir.

Thank you, Whitley, and good morning. We appreciate you joining us on today's conference call for a discussion of last evening's earnings release. With us on the call from National Fuel Gas Company are Ron Tanski, President and Chief Executive Officer; Dave Bauer, Treasurer and Principal Financial Officer; and Matt Cabell, President of Seneca Resources Corporation. At the end of the prepared remarks, we will open the discussion to questions. This morning, we posted a new slide deck to our Investor Relations website. We may refer to it during today's call. We would like to remind you that today's teleconference will contain forward-looking statements. While National Fuel's expectations, beliefs and projections are made in good faith and are believed to have a reasonable basis, actual results may differ materially. These statements speak only as of the date on which they are made, and you may refer to last evening's earnings release for a listing of certain specific risk factors. With that, I'll turn it over to Dave Bauer.

Thank you, Tim. Good morning, everyone. The third quarter was another very good quarter for National Fuel, with performance driven largely by our Midstream businesses, which continued their momentum from the first half of the fiscal year. Growth in our Gathering operations, which was fueled by Seneca's production growth, was particularly noteworthy. These operations are becoming a more meaningful part of our system, contributing $0.10 per share to earnings for the quarter. Seneca's production was up 19% compared to last year's quarter and on a sequential basis, up 10% compared to the second quarter of this year. However, natural gas pricing continues to be a significant headwind. For the quarter, Seneca's weighted average natural gas price before hedging was $3.88, down $0.16 from the prior year. Combining that with the lower-priced hedge book, our total realized price after hedging was down $0.62 per Mcf. That drop in pricing, along with the $3.6 million before tax mark-to-market adjustment related to the ineffective portion of our crude oil hedges, impacted earnings by $0.20 per share compared to last year. Offsetting the lower realized prices, on the expense side, per unit DD&A expense of $1.84 per Mcfe was down significantly from both last year and the second quarter of this year. This was driven by substantial reserve adds associated with the 9-well pad we recently completed at our Clermont/Rich Valley development area. In spite of the big jump in Marcellus production, Seneca's $1.08 per Mcfe of LOE expense for the third quarter was flat with the second quarter of fiscal '14. While East Division LOE was in line with our expectations, LOE expense in California was a little higher than we had planned, mostly as a result of higher steam fuel costs at our Midway Sunset field and higher water disposal costs at the East Coalinga field. Earlier this week, we placed in service a new water disposal system at East Coalinga, which will reduce the West Division's LOE by more than $100,000 per month. Switching to earnings guidance, we're narrowing our fiscal '14 earnings expectations to a range of $3.40 to $3.50 per share. Our guidance assumes NYMEX commodity prices of $4 for gas and $95 for oil for the remainder of the fiscal year. We've also updated our spot price assumptions. We now expect Seneca's realized gas price before hedging for the last 3 months of the fiscal year will range between $3.05 and $3.25 per Mcf. We're pretty well hedged for the fourth quarter. At the midpoint, about 2/3 of our natural gas production is committed under firm sales, and substantially, all of those firm sales are backed with financial hedges. In addition, in California about 2/3 of our oil production is hedged. Looking to next year, our preliminary earnings guidance for fiscal '15 is a range of $3.30 to $3.60 per share, at the midpoint flat compared to fiscal '14. Looking at it from a big-picture perspective, while we're never pleased with flat earnings, particularly when production is expected to grow at about a 20% rate, it's important to remember that weather had a very significant impact on fiscal '14 earnings of our regulated businesses, in total, about $0.10 per share. In addition, pricing in the Marcellus continues to be weak, and we think the pricing assumptions we reflected in our fiscal '15 forecast are realistic in light of what we've seen in the market over the past few months. So let's look at key assumptions underlying the forecast. Starting at Seneca. Our fiscal '15 guidance assumes our previously announced production range of 180 to 220 Bcfe. In terms of pricing, our forecast assumes NYMEX pricing of $4.25 for natural gas and $95 for oil. The $4.25 gas price assumption is a little higher than the current strip. But remember that approximately 100 Bcf or about 50 -- 56% of our East Division production for fiscal '15 is committed under firm sales agreements, substantially all of which are either fixed price or backed by financial hedges, so changes in NYMEX should have little impact on the majority of our production. In addition, while the NYMEX is certainly important for the pricing of our firm sales and financial hedges, it's becoming less relevant for our spot sales in the Marcellus, which we expect will total 78 Bcf in fiscal '15. At times, particularly in the summer and shoulder months, when there's less heating load, Marcellus pricing appears to disconnect from NYMEX and instead settles on a market clearing price. There have been many periods where any change in NYMEX has little to no impact on the pricing we see in Appalachia. At the midpoint of our guidance, our forecast assumes spot pricing across our Marcellus production averages between $2.75 and $3 per Mcf for the entire fiscal year. Given our exposure to the spot market, changes in pricing could have a meaningful impact on fiscal '15 earnings. For every $0.10 change in the average spot price, earnings are impacted by about 6 -- a little -- about $0.055 per share. One last point on pricing. When you blend the firm and spot sales assumptions I just described, we expect our average realized natural gas price before hedging will be between $3.35 and $3.50 per Mcfe. It's likely that Marcellus pricing will remain volatile, so we'll continue to evaluate and revise our pricing assumptions in the coming quarters. From an expense standpoint, the expected 20% growth in production should drive continued improvement in Seneca's per unit cash operating costs. We expect combined LOE, G&A and production taxes will decrease to a range of $1.35 to $1.60 per Mcfe. In addition, as we develop the Clermont/Rich Valley area, reserve additions should lower per unit DD&A expense to be within the range of $1.70 to $1.85 per Mcfe. As a result of Seneca's increased production, the Gathering segment's earnings and cash flows will increase as well. For fiscal '15, we expect the Gathering segment's revenues will be between $90 million and $110 million, up from the $72 million to $74 million we forecast for fiscal '14. Operating expenses will increase somewhat as we add compression to the Clermont system, but a large portion of the revenue increase should fall to the bottom line. While we're actively engaged in discussions with other producers, the Gathering segment's forecast is based solely on Seneca's projected volumes and doesn't assume any third-party business. Turning to the regulated businesses. Fiscal '15 will likely be a relatively flat year for the Pipeline and Storage segment. The Mercer project, which is a further expansion of our Line N system, that we expect will come online in November, will add about $5 million in revenues in fiscal '15. However, that increase will likely be offset by 2 items. First is weather. As we said on the past few calls, we've seen terrific demand for short-term transportation service on our system, and much of that demand was driven by weather, which we estimate added about $5 million in revenue for the last 9 months. While we don't expect the short-term business will go away entirely, our forecast assumes normal weather so we're tempering our expectation somewhat. Second, a service agreement with a major shipper on our legacy Empire line expired this year. We did reach a new agreement with that shipper, but it carries a lower rate. As a result, Empire's revenues will be impacted by about $4 million. Considering these items, we expect Pipeline and Storage revenues for fiscal '15 will be in the range of $270 million to $280 million. Lastly, with respect to the utility, we're expecting a decline in that segment's earnings in fiscal '15 for 2 reasons. First, as I just indicated, our forecast assumes normal weather. In fiscal '14, colder-than-normal weather contributed about $0.06 to earnings. Additionally, in fiscal '15, we're projecting incremental O&M costs of approximately $7 million related to the implementation of our new customer billing system. Much of that increase is attributable to training, data conversion and the like, so we expect a large chunk of that incremental spend will be nonrecurring. Turning to capital spending. We made a few minor revisions to our estimates for fiscal '14. We narrowed our guidance to a range of $925 million to $1 billion, at the midpoint, a $40 million increase from our previous guidance. And for fiscal '15, our range is now $1.1 billion to $1.3 billion, a $30 million increase. Details on a segment basis can be found on the new IR deck. There aren't any major changes in our spending plans. The variations you see are mostly attributable to changes in the timing of spending on our various pipeline and gathering expansion efforts. With respect to our financing plans, we now expect our capital expenditures and dividend will exceed cash from operations by about $175 million to $200 million in fiscal '14. For fiscal '15, our projected outspend will increase to about $350 million to $375 million, resulting in a total financing need in excess of $500 million over the next 15 months. With that, I'll close and turn the call over to Matt.

Thanks, Dave, and good morning, everyone. Seneca had another excellent quarter, with production up 19% versus last year's third quarter. California production was up 9%, with continued good results at our East Coalinga field. We expect full year California production to be about 21 Bcfe or 6% higher than fiscal 2013. East Division production was 35.1 Bcfe, up 21% versus a year ago. Absent significant price-related curtailments, which I'll address shortly, the East Division will experience tremendous production growth in the current quarter, with 31 new wells coming online, including 15 wells in the Clermont/Rich Valley area, 6 in Tioga County and 10 in Lycoming County. Nine of the Clermont/Rich Valley or CRV wells are already online, as are all 10 of the Lycoming wells. The 9 CRV wells, as described in our operations update, surpassed our expectations, with IP rates averaging 8.2 million cubic feet per day on relatively short laterals of about 5,300 feet. Remember that we have no royalty on this acreage, so this would be the equivalent of a 10 million a day well with an 18% royalty. While it is too early to provide an EUR for these wells, what I will say is that, given their shortish laterals, on a normalized basis, these IPs exceed the expected initial rate of our 7 Bcf type curve. Our long-term development plan for the Clermont/Rich Valley area has an average lateral length of over 6,000 feet, somewhat longer than this early pad. Regarding well cost, $6.5 million is as expected for this first development pad, but higher than our long-term expectations for this lateral length. Across the entire 230-well Clermont/Rich Valley area, we are anticipating that same average well cost of about $6.5 million to drill and complete longer wells with higher stage counts. As we move forward with our development, we will be experimenting with some modifications to our completion design and spacing. Pad N tested well spacing from 650 feet to 800 feet to 950 feet. We need several months of production data to fully analyze the results of this test. All of these wells used 150-foot stage spacing. On future pads, we will test different stage spacing, as well as higher sand concentrations. Obviously, the goal is to find the ideal bang for the buck that optimizes the completion, while lowering the well cost, leading to the lowest funding and development cost and the highest rate of return. While the CRV results are the most important recent highlight for Seneca, I should also mention the 10 new wells at Pad T on Tract 100. These wells had an average IP of 17.8 million cubic feet per day, with the best well coming on at a peak 24-hour rate of 25.7 million cubic feet per day and averaging 21.1 million over its first 7 days. Moving on to transportation and marketing. We have recently negotiated several new agreements, which are detailed in the July 28 operations update. In particular, I want to highlight the Northern Access 2016 capacity on the National Fuel system. With this project and associated capacity on TransCanada, we will ship an additional 350,000 dekatherms per day into Canada beginning in November of 2016. That brings our total firm transportation into the Canadian market to 558,000 dekatherms in fiscal 2017. I would also like to highlight a firm sales deal we recently executed that provides a fixed price of $3.77 for 50 million cubic feet per day on the Transco system from November of '14 through October of '17. We were able to accomplish this trade by leveraging the value of our future firm transportation on the Atlantic Sunrise system. In total, we have 331,000 dekatherms of firm transportation/firm sales in fiscal '15, increasing every year to 778,000 in fiscal 2018. Please refer to the new IR deck to see all of the firm transportation and firm sales agreements we have executed. On July 31, Transco began critical maintenance at Station 515 on the Leidy line, which reduced capacity by 300,000 dekatherms per day. Prices have dropped to a range of $1.25 to $2.25 on TGP Zone 4 and the Transco Leidy line as a result of this unplanned maintenance. This is a phenomenon we have seen several times, and generally, prices recover once the full pipeline capacity is restored. Transco has indicated that this unplanned maintenance, as well as some additional maintenance, should be completed by August 22. Since July 31, we've curtailed approximately 1.4 Bcf of Lycoming and Tioga production due to this recent weak pricing. While this will dampen our fourth quarter production and full year fiscal 2014 production, we continue to expect robust growth and a great start to fiscal 2015. Next year, production will follow a pattern similar to fiscal 2014. With the growth in production in this year's fourth quarter, we will exit the year over 500 million cubic feet per day. This will drive sequential growth into the first quarter of fiscal 2015. And from there, production will likely be flat until we bring on several new pads at CRV later in fiscal '15. In summary, Seneca's development plan is on track and surpassing our expectations. We have long-term transportation and firm sales deals in place to provide confidence in our ability to market our fast-growing production. While we will have some exposure to spot prices, particularly in the next 12 to 24 months, we have mitigated much of this risk and are well positioned for sustainable production growth at good prices for another 15 years or more. Now I will turn it over to Ron.

Good morning, everyone. Thanks, Dave and Matt, for covering the details of another strong quarter. It was strong on the operations front and from a financial standpoint. Operations in all of our segments are moving along according to plan and without any major surprises. As Dave detailed in his comments, our preliminary guidance for next fiscal year is based on assumptions of normal weather and our current view of the forward strip of commodity prices. Operationally, we're always prepared for a 10% colder-than-normal winter, but our earnings forecast does not currently include any colder-weather adjustments. Seneca's positive results in the Clermont/Rich Valley acreage in our Western development area have set us up very nicely for ongoing development across a large swath of our legacy acreage. However, with overall dry gas production from the Marcellus basin now exceeding 15 billion cubic feet per day and maxing out pipeline takeaway capacity, pricing in the basin has been under pressure. As a result, commodity pricing is the 1 variable that poses a near-term challenge for us. To address that challenge, Seneca continues to enter into firm sales agreements and pick up transportation capacity to mitigate the impact of lower spot pricing. Looking out to fiscal 2015, with 56% of our projected volumes under firm arrangements, we anticipate another successful year of production growth, with year-over-year growth of about 20%. Coupled with that increase in production, we will be increasing our investment in pipeline infrastructure to move both Seneca's and more third-party production to market. We continue to be pleased with the performance of our Midstream businesses. The pipeline construction activities of our gathering company on the Clermont gathering system are highly coordinated with Seneca's pad completions. We have consistently put into service the pipeline systems necessary to get Seneca's production flowing as soon as practicable after the well pads are completed. As set out in the IR deck, we expect to invest an additional $115 million to $160 million building out the Clermont system next year, with additional investments dictated by Seneca's continued drilling. Moving onto activities in our interstate pipeline system. As we detailed in last week's operational update, Seneca is the anchor shipper on our Northern Access 2016 project, taking capacity of 350 million cubic feet per day. Our Pipelines segment has budgeted $410 million for the project, and we are in the FERC pre-filing process now. Seneca is also acquiring corresponding capacity on the TransCanada and Union systems in Ontario, Canada, which will give Seneca the ability to deliver gas to the Dawn Hub. Our strategy is pretty simple. With respect to Seneca's production, we will build our own pipeline capacity to get our gas flowing, and that capacity will be large or expandable enough to accommodate increasing production. Where necessary, we will also take capacity on third-party pipelines. We expect to be moving a growing volume of our production to an alternative market that is quite large and has better pricing than we're seeing at Dominion South Point or on the Tennessee system. In addition to the projects that support Seneca's development program, we're in the early stages of another project for third parties to expand our Empire Pipeline further into Pennsylvania and to increase capacity by 300,000 dekatherms per day. That capacity would flow gas north, and the ultimate delivery points would be split between the TransCanada system and the Tennessee 200 line. Early spending estimates for this project are in the range of $150 million, and most of the spending on this project would likely occur in 2016 and 2017. The Upstream and Midstream businesses continue to be growth engines for National Fuel, and we're well positioned to take advantage of a number of opportunities for the foreseeable future. When we combine those operations with the consistent cash flows generated by both our downstream utility and marketing businesses, we believe that this combination of operations across the entire natural gas value chain will deliver ongoing growth to our shareholders. Dave's capital expenditure forecast highlighted the financing need of more than $500 million over the next 15 months. In addition to those needs, I mentioned that we will have ongoing gathering and transmission system build-outs continuing into 2016 and 2017, along with Seneca's ongoing drilling activities. Because of our desire to maintain [ph] the strength of our balance sheet, while still being able to capitalize on future investments that deliver value to our shareholders, we will likely need to supplement our significant capital needs over the next few years with sources other than leverage. We've had ongoing and active discussions with our board and financial advisors about various tax-efficient financing options available to us to fund our growth, including changes to our corporate structure. We believe the traditional midstream pipeline master limited partnership may be one option. In addition, some recent MLP structures for upstream assets have been very interesting and seem to have hit some early success and merit further examination as we look at our needs. Because of the significant value that we have seen in our integrated model, we have always said that our decisions will be driven by our needs for capital, and that remains true today. To date, because of our strong balance sheet and pretty simple capital structure, we have a number of options available to us, and we will be able to react quickly as our capital needs evolve. In the meantime, we're in great shape to continue the execution of our plans and remain focused on highlighting the value of our assets and growing the company. Now operator, we'd like to open up the line for questions.

[Operator Instructions] Our first question comes from the line of Christine Cho with Barclays.

So interesting comments about the MLP. Can you just give us a little more color on what you're thinking, talk about where you are in the process? And what essentially needs to happen for you to maybe cross that finish line?

Christine, again, we've talked about this in the past, and really, it's our -- what our ultimate financing needs are. When we look at our current balance sheet, we expect that, next year, we'll more than likely be doing a debt financing. As we look forward, the largest capital needs that we have will be driven by the Northern Access 2016 project. And if you look at the calendar that we have for that, we don't -- or we expect to be receiving a FERC certificate sometime during January 2016. So it's likely that, that's a date that will be kind of the pivot point for us in a major change in the financing plans.

Okay, great. And then, I guess, when we think about the 10-well pad that is supposed to be coming on in Lycoming, these wells have been very large and like you guys have said, not all hedged. And as you also mentioned, some of that is with the Transco maintenance that's going on and prices have dipped to as low as, I think you said, $1.25. How should we think about how you're going to bring these on? I would think if you brought it on all at once, you might overwhelm the Leidy market. So kind of as you ease the production into the spot market, at what price would you hold off on and maybe stay on the sidelines? I know you guys have mentioned $2 before. Is that still the right way to think about it?

Yes. Christine, first of all, those 10 wells are online as we speak, in the comments. But our entire production volume on Trout Run that feeds into Transco, we'll have times when we will curtail at a price that we believe is lower than we'd like to receive. I'm not prepared to say a specific price. I'm not even sure that's in our best interest as a marketer of our gas. But I would agree with you that major well pads, be they ours or Cabot's or somebody else's, single major well pads can affect the entire market.

When we think about you curtailing, how long would you -- like, do you think you will have to curtail for it to be worth it for you to curtail at all? Like, I would imagine that when you curtail something, you're not thinking that you're just going to curtail it for a week or 2.

No, we generally make that decision on a day-to-day basis.

Sometimes, we're curtailed for a day and the next day, we're back on.

Okay. And then also with the update with E&P operations a week or so ago, you gave some color on this new firm sales contract that seems very attractive. That 50,000 dekatherms a day that has that realized -- that fixed price realization of $3.77, this is going to be sold at the interconnect of your Lycoming gathering system. Is that right?

That's correct.

And then would you be able to provide how much your Lycoming wells are producing today?

The entire Lycoming volume today is around 300 million cubic feet.

Okay. And there's nothing else coming on here in 2015. Is that right? Are you guys going to stop...

In Lycoming in 2015?

Yes.

We have 1 more pad that will likely come on sort of end of this quarter -- or actually, I guess, it'd be more likely into the first quarter of fiscal '15, and it's 5 wells. And then we've got 2 wells down at Gamble that come on kind of January, February kind of time frame. And that would be it for new wells in Lycoming in fiscal '15.

Okay. And then at this -- today, did I hear you guys correctly when you said you expect 78 Bcf in EDA to be subject to spot sales?

No. No, that's total. That's both EDA and WDA, about half and half EDA, WDA.

Okay. And then on the 350,000 dekatherms per day of firm capacity on Northern Access that you took, how much of that capacity do you expect to be utilizing when the pipeline comes online?

All of it.

All of it, Day 1?

Yes.

Okay. And then just so I understand this correctly, are you delivering into the hub? Or do you have a deal with an end user on the other side of this contract that you'll be providing the gas for?

We don't have the deal with the end user today on the other end, but probably by the time the pipeline is in service, we will.

Okay. And then last...

We'll have some kind of contractual arrangement to sell that gas into the Dawn market, let's put it that way.

Okay. And then last one for me, I saw that you added some MichCon hedges. Did you take some new pipeline capacity to get you there?

No. Our existing contract that we have to sell gas at a Dawn index allows us to take that MichCon hedge, which is essentially a point that's a stone's throw from Dawn.

Your next question comes from the line of Becca Followill with U.S. Capital Advisors.

Just going back to your comments on structure. And I'm sorry, I was surprised by the comment so I didn't quite digest it all. In the past, you've said that the changes would be driven by need for capital, and clearly, you're there. So you're saying that the existing backlog means that you need to do something else. And if you add to it, I guess, it just exacerbates the need for additional capital. So are you guys looking at, in addition to a potential MLP for midstream, also a potential MLP for E&P? Or would they be the same? And you also mentioned corporate structure. Can you -- is that related to the MLPs? Or is there something else in addition to that?

Well, you're breaking up a little bit there, Becca. But generally speaking, we're looking at a number of things, a number of options, not that we're going to use all of them. One of the big issues is tax efficiencies. So what we're studying, and again, it's pretty much tied in with the timing of the large outspend on the pipeline and transmission sides, tying to Northern Access, the -- as we look out there, MLP for the midstream assets looks attractive, but there are other options. Most recently, the Diamondback, Viper and the Encana, Prairie Sky structures look interesting to us, too. So we're examining a number of things.

But beyond those 2 structures, would you also consider a split of the company if it was tax efficient?

That's something that's way, way, way down on the list of options, primarily because of the tax-based issues that we have. And also it's a -- the cash flows from those businesses are pretty much self-sustaining. And because of the efficiencies that would be destroyed through the separation, that's way, way down on the list of options.

And then the other question, on these firm transportation and firm volumes that you have laid out in your operational update on July 28, by '18, you get to 780 million a day of capacity there. How far up the hedge book would you be willing to take? In other words, would you take capacity for 100%? Would you only do 80%? What percent roughly would you go to?

We haven't really made any decisions on that. I mean, we have a hedge committee, and we look at -- we have sort of target ranges for how much we want to hedge going forward. But I don't know that we would necessarily structure it as a percentage of that volume, closely related to our production volume.

Yes. Our policy would let us go as high as 80%.

Your next question comes from the line of Carl Kirst with BMO Capital Markets.

Just maybe 1 final question, if I could, on the structure with respect of alternative funding and again, understanding there's a list of things to do. Excluding the alternative funding, just, Ron, if I understand you correctly, if a final FERC certificate notice to proceed happens in January of 2016, that's the pivot point where, basically, we would now have to act. And I guess, what I'm trying to perhaps split the hair of, is that something where you would look at with the expectation that you'd be getting the notice to proceed? Or is it something where once you get that and it becomes final, then perhaps there's enough time through 2016, meaning enough comfort with the balance sheet through 2016, that you have an ability to wait through to that year to raise alternative funding in whatever way it may be?

Well, if you look at our current balance sheet today, Carl, I mean, we've got a lot of dry powder just with respect to our ability to use short-term funding. So it's keeping that optionality open up until at least through the receipt of the FERC certificate. I mean we've just got plenty of flexibility. Since a lot of the financing needs will also depend on actual commodity prices that we receive over the next 2 years, that's going to impact our overall needs, too. So that is not the firm date that we have to do anything by just because of where we stand with our balance sheet.

Understood. That's helpful color. I appreciate that. Maybe a macro question perhaps and -- well, maybe micro and a macro. With respect to Northern Access 2016, and understanding, if you're trying to get third parties, you might not be willing to kind of give the cost detail at this point. But is it possible to say what you think your -- what the cost of transport would be to Dawn? Or if not, perhaps what is the cost even to jump on to TransCanada and Union, as far as that segment?

I believe in our open season documentation, we had about $0.48 on that system. Again, that was in the open season documentation. Obviously, with being anchor shipper, you have the ability to negotiate around that point. And I guess, that's all I'm willing to say at this point. That's about the zip code of what we're talking about to get that from the Clermont area or basically where the outlet of our Clermont gathering system is all the way up to the border.

To Chippawa? And then - I'm sorry?

Yes.

Okay. And then, there may be -- and as you -- and apologies, but just -- and I'll -- because it'll feed into my second question. Is the intent just to get it to the Canadian border or to the actual more, what I would say, liquid hub of Dawn itself?

Well, the Seneca is also picking up the capacity on TransCanada and Union to be able to do that. Now recognize, however, if you put in your mind the actual locations of those pipelines, there's also the opportunity to move the gas directly to the Toronto market without having to go back to Dawn. But it's easy for everyone to understand the Dawn pricing, so that's kind of the point we're picking to describe the project.

No, that's helpful, and certainly, appreciate the ability to go to the different markets there. Maybe just sort of a broader macro then on that, and understanding that calling basis a week from now, much less a few years from now, is a bit of a fool's errand. But as we look at projects like potentially Northern Access 2016, but NEXUS, Rover going potentially to Dawn, how do you guys look of that market in the future? Is it something that you, say, think ultimately large and liquid enough that it perhaps just kind of maintains parity with Henry Hub? Or is that a market that ultimately could get threatened as well just simply as the Northeast grows?

Well, we think -- yes, I mean, as we look at it, the more capacity that can be built out of the Marcellus, it's just going to benefit everyone to alleviate the basis issues that we see. And again, the projects you mentioned, the ET Rover, NEXUS, those projects have a lot of other flexibility with respect to their ultimate delivery point. So it's a large market up there, and I think it's -- at worst, you're going to see the parity with NYMEX pricing.

Okay. That's helpful. And then last question. Matt, as you look at the perhaps better IP rates of Clermont, well costs where they are, is there any sense of how your F&D shifts or maybe it doesn't shift, as you go more towards -- or from EDA more towards the WDA? Can we maintain this dollar sort of F&D in the East? And I ask that in context of, as we look at 2015 guidance, for instance, the unit DD&A continues to fall down, which is great to see. I was just kind of hoping for some more maybe granularity of, as we go to that shift to the west, if that dollar level can be maintained.

Sure. There are a lot of things that drive that DD&A rate or drive F&D, first of all. Some of it is how much money are we spending on more sort of exploratory delineation type drilling, which that's really going down because we've got less of that to do now. You're absolutely right that we wouldn't expect the pure development F&D at Clermont to be as low as it is in Lycoming County, where the wells are enormous. However, remember that we pay no royalty in our WDA acreage. So I think, maybe think about the F&D over there to be sort of $1, $1.25 range. And if you look at our kind of historical DD&A, it takes time for that to work down because you've got past costs. You've got money we spent in California on projects that were highly economic but yet, because of oil province, they have a higher F&D. So yes, you should expect to see a continued fall in DD&A and very competitive F&D in the WDA.

Your next question comes from the line of Tim Winter with Gabelli & Co.

Ron, it's great to hear you're considering an MLP. I realize you have a lot of options and flexibility and perhaps are early at this point. But I was wondering if you could just clarify a little more the thought process and where you are in the process. Have you hired bankers yet? And I guess I would sort of assume that the FERC 2016 CCM would be likely. So should we sort of -- are you sort of thinking that you'd be ready to move immediately after that?

Well, Tim, we're always talking with the financial advisors, and we've got relationships with a number of bankers. So it's a little early to comment on structure or anything with respect to that. We had regularly looked at, and especially in this day of low interest rates, debt financing to be the most efficient form of funding the growth of our business. But we realize that we're going to reach a tipping point at some point, where that's just not feasible to do that and maintain an investment-grade rating. So we've got to look at something else. And that's why the, structurally, the pipeline MLP, the traditional pipeline MLP structure is very interesting. But recently, we've seen people do creative things with their upstream assets. So we've got a number of things to look at, a number of options. And with respect to the Northern Access, I don't know that it's a slam dunk. One would think that it's a project that makes sense and should have strong support. We certainly have capacity at the Canadian border to move more gas into Canada with the existing connections that we have there, so feeding gas from our Marcellus wells into that system makes perfect sense for us. We still have to go through the permitting process. And so that's why we have our normal timeline set out there. And then, assuming everything moves along the plan, that'll be 2016.

That concludes our Q&A session. I would now like to turn the call back over to Mr. Tim Silverstein.

Thank you, Whitley. We'd like to thank everyone for taking time to be with us today. A replay of this call will be available at approximately 3:00 p.m. Eastern time on both our website and by telephone and will run through the close of business on Friday, August 15, 2014. To access the replay online, visit our Investor Relations website at investor.nationalfuelgas.com. And to access by telephone, call 1 (888) 286-8010 and enter passcode 86485833. This concludes our conference call for today. Thank you, and goodbye.

Ladies and gentlemen, that concludes today's conference. Thank you for your participation. You may now disconnect. Have a great day.