National Fuel Gas Co (NFG) 2014 Q3 法說會逐字稿

Good day, ladies and gentlemen and welcome to the Q3 2014 National Fuel Gas Company earnings conference call. (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 will 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 a lower priced hedge book, our total realized price after hedging was down $0.62 per Mcf.

With 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 nine 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 2014. 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 cost 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 are narrowing our fiscal 2014 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 have also updated our spot price assumptions and we now expect Seneca's realized gas price before hedging for the last three months of the fiscal year will range between $3.05 and $3.25 per Mcf.

We are pretty well hedged for the fourth quarter. At the midpoint, about two-thirds 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 two-thirds of our oil production is hedged.

Looking to next year, our preliminary earnings guidance for fiscal 2015 is a range of $3.30 to $3.60 per share, at the midpoint flat compared to fiscal 2014. Looking at it from a big-picture perspective, while we are never pleased with flat earnings, particularly when production is expected to grow at about a 20% rate, it is important to remember that weather had a very significant impact on fiscal 2014 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 2015 forecast are realistic in light of what we have seen in the market over the past few months.

So let's look at the key assumptions underlying the forecast. Starting at Seneca, our fiscal 2015 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 56% of our East Division production for fiscal 2015, 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 is becoming less relevant for our spot sales in the Marcellus, which we expect will total 78 Bcf in fiscal 2015. At times, particularly in the summer and shoulder months when there is 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 2015 earnings. For every $0.10 change in the average spot price, earnings are impacted by 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 is likely that Marcellus pricing will remain volatile, so we will 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 our 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 2015, 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 2014. 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 are 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 2015 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 2015. However, that increase will likely be offset by two items. First is weather. As we have said on the past few calls, we have 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 nine months. While we don't expect the short-term business will go away entirely, our forecast assumes normal weather. So we are tempering our expectations 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 2015 will be in the range of $270 million to $280 million.

Lastly, with respect to the Utility, we are expecting a decline in that segment's earnings in fiscal 2015 for two reasons. First, as I just indicated, our forecast assumes normal weather. In fiscal 2014, colder than normal weather contributed about $0.06 to earnings. Additionally, in fiscal 2015, we are projecting incremental O&M costs of approximately $7 million relating 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 2014, 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 2015, our range is now $1.1 billion to $1.3 billion, a $30 million increase. Details on a segment basis can be found in 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 2014. For fiscal 2015, 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 will 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 will 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, six 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 nine 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 rates 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 costs, $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 finding and development costs 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 seven 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 2014 through October of 2017. 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 and firm sales in fiscal 2015, 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 have 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 2015.

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 are 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 and now exceeding 15 billion cubic feet per day and maxing out pipeline take-away capacity, pricing in the basin has been under pressure. As a result, commodity pricing is the one 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 on to 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 Pipeline segment has budgeted $410 million for the project and we are in the FERC prefiling 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 are seeing at Dominion South Point or on the Tennessee system.

In addition to the projects that support Seneca's development program, we are 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 the growth engines for National Fuel and we are 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 a 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 buildouts continuing into 2016 and 2017, along with Seneca's ongoing drilling activities. Because of our desire to maintain 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 have 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 had 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 are 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). Christine Cho, Barclays.

Good morning, everyone. So interesting comments about the MLP. Can you just give us a little more color on what you are 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 have talked about this in the past and really it is what our ultimate financing needs are. When we look at our current balance sheet, we expect that next year we will 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 expect to be receiving a FERC certificate sometime around January 2016. So it is likely that that's a date that will be kind of the pivot point for us and 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 is going on and prices have dipped to as low as I think you said $1.25. How should we think about how you are 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?

Christine, first of all, those 10 wells are online as we speak.

Okay, all of it, okay.

But our entire production volume on Trout Run that feeds into Transco -- we will have times when we will curtail at a price that we believe is lower than we'd like to receive. I am not prepared to say a specific price. I'm not even sure that is 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 would 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 are not thinking that you are just going to curtail it for a week or two.

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

Okay.

Sometimes we are curtailed for a day and then the next day, we are 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 377, 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 is nothing else coming on here in 2015, is that right? Are you guys going to stop --?

In Lycoming in 2015?

Yes.

We have one more pad that will likely come on sort of the end of this quarter or actually I guess it would be more likely into the first quarter of fiscal 2015 and it's five wells. And then we've got two wells down at Gamble that come on kind of end of January, February kind of timeframe and that would be it for new wells in Lycoming in fiscal 2015.

Okay. And then, 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 is total. That is 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 one?

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 will 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. And we will set 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 is a stone's throw from Dawn.

Okay, that was it for me. Thank you so much.

Becca Followill, US Capital Advisors.

Good morning, guys. Just going back to your comments on structure, and I'm sorry, I was surprised by the comments, so I didn't quite digest it all. In the past, you have said that the changes would be driven by need for capital and clearly, you are there. So you are 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 it be the same or you also mentioned corporate structure? Is that related to the MLPs or is there something else in addition to that?

Well, you were breaking up a little bit there, Becca, but, generally speaking, we are looking at a number of things, a number of options, not that we are going to use all of them. One of the big issues is tax efficiency. So what we are 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, 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 PrairieSky structures look interesting to us, too. So we are examining a number of things.

Thank you. But beyond those two structures, would you also consider a split of the Company if it was tax efficient?

You know, that is something that is way, way, way down on the list of options, primarily because of the tax base issues that we have, and also the cash flows from those businesses are pretty much self-sustaining. And because of the efficiencies that would be destroyed through the separation, that is way, way down on the list of options.

Thank you. 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 2018 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. It's closely related to our production volume.

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

Right. Thank you.

Carl Kirst, BMO Capital Markets.

Thank you. Good morning, everybody. Just maybe one final question, if I could, on the structure with respect to alternative funding and again, understanding there is 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 is the pivot point where basically we would now have to act. And I guess what I am trying to perhaps split the hair of is that something where you would look at with the expectation that you would be getting the notice to proceed or is it something where once you get that and it becomes final there perhaps is 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, we've got a lot of dry powder just with respect to our ability to use short-term funding. So keeping that optionality open up until at least through the receipt of the FERC certificate, we have 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 two years, that is 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 is 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 are trying to get third parties, you might not be willing to 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 onto TransCanada and Union as far as that segment?

I believe in our open season documentation, we had about $0.48 on that system. That was -- again, that was in the open season documentation. Obviously, with an anchor shipper, we have the ability to negotiate around that point. I guess that is all I am willing to say at this point. That is about the ZIP Code of what we are 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.

The Chippewa? And then -- I'm sorry?

Yes.

Okay. And then there may be -- apologies, but just -- because it will feed into my second question, is the intent just to get it to the Canadian border to the actual more at what I would say liquid hub of Dawn itself?

Well, 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 is also the opportunity to move the gas directly to the Toronto market without having to go back to Dawn. But it is easy for everyone to understand the Dawn pricing, so that's kind of the point we are 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 at that market in the future? Is it something that you 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?

As we look at it, the more capacity that can be built out of the Marcellus is 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 points. So it is a large market up there and I think, at worst, you are going to see the parity with NYMEX pricing.

Okay, that's helpful. Thank you. 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 is really going down because we've got less of that to do now. You are 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 F&D over there to be sort of the $1.00 to $1.25 range and if you look at our 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 an 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.

Great, that is very helpful. Thanks a lot, guys.

Tim Winter, Gabelli & Co.

Good morning. Ron, it's great to hear you are considering an MLP. I realize you have a lot of options and flexibility and perhaps they 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 CCN 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 are always talking with the financial advisors and have 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 are 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 have got to look at something else. And that is why 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.

Okay, okay, great.

And with respect to the Northern Access, I don't know that it is a slamdunk. 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 is why we have our normal timeline set out there and assuming everything moves along to plan, that will be 2016.

Okay, great. Thanks, Ron.

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

Thank you, Whitley. We would like to thank everyone for taking the time to be with us today. A replay of this call will be available at approximately 3 PM 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.