Tim Silverstein - Director of Investor Relations Ron Tanski - President and CEO Dave Bauer - Treasurer and Principal Financial Officer Matt Cabell - President of Seneca Resources Corporation.

Christine Cho - Barclays Carl Kirst - BMO Capital Chris Sighinolfi - Jefferies.

Good day, ladies and gentlemen, and welcome to the Quarter Two 2014 National Fuel Gas Company Earnings Conference Call. My name is Caroline, and I will be your operator for today. At this time all participants are in listen-only mode. We will conduct a question-and-answer session towards the end of the conference.

(Operator Instructions) As a reminder, the call is being recorded for replay purposes. And now I would now like to turn the call over to Tim Silverstein, Director of Investor Relations. Please go ahead..

Thank you, Caroline, 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 in Houston, 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 begin with Dave Bauer..

Thank you, Tim, and good morning, everyone. As you saw in last night’s release the second quarter was another great quarter for National Fuel. Consolidated EBITDA was up more than 10% over the prior year with all of the major business segments contributing to the increase. On a GAAP basis earnings were $1.12 up $0.10 per share or 10%.

Included in that amount were a few non-recurring items that I would like to highlights. First was a $3.6 million or $0.04 per share gain on corporate owned life insurance, which is reflected in other income in the corporate segment.

We use life insurance policies on our senior executives as a funding vehicle for certain non-qualified deferred compensation arrangements. Earlier this year, a former executive passed away at the age of 90. The death benefit from this policy exceeded the cash surrender value we had recorded on our books, which led to beginning.

Going in the other direction, Seneca recorded a $2.4 million after-tax or $0.03 per share charge for well plugging and abandonment costs associates with its former offshore Gulf of Mexico program. Several years ago, Seneca had farmed out a shallow water lease to another operator. That operator recently filed for bankruptcy.

As the original lessee, Seneca is now responsible for a portion of the costs to plug and abandon for wells on the lease. We begin to [wear] this item late in the first quarter of fiscal ‘14 and recorded an initial $800,000 after-tax accrual for us.

This past quarter, after receiving bids from contractors, we have to accrue the match fee updated cost estimates. Our work is expected to be completed this summer. Lastly, there were two non-cash deferred tax adjustments that impacted our earnings for the quarter.

One related to a change in New York tax law, the other to our growing level of activity in Pennsylvania. The 10-Q will be filing this afternoon, because a good job describing the adjustments, if you are interested in more details.

At the bottom-line, the impact of these two adjustments increased our effective tax rate for the quarter to 41%, which reduced earnings by $0.04 per share. For the full year, I expect our effective tax rate will be closer to 40.5%. Excluding the net $0.03 per share impact of these items, operating results were $1.15 per share.

Each of our major operating segments had very strong results during the quarter. Seneca is nearly 37 Bcf of production, which was up 28% over last year was right in line with our expectations. Looking to the rest of the year, we're narrowing Seneca's production guidance to a range of 155 Bcfe to 165 Bcfe.

Matt will have additional details on the drivers of this change later on the call, but I'd like to emphasize that our production guidance assumes we don't experience any pricing related curtailment for this summer.

While we have been seeing improved realizations since the winter and have approximately 70% of our remaining Marcellus volumes under firm sales agreements, the spot market is still highly volatile. Broader than expected commodity prices were also a factor in the quarter.

Seneca's core hedging natural gas prices averaged $4.52 per Mcf, well above our guidance of $3.65 per Mcf. Looking to the remainder of the year, we're increasing our NYMEX gas price assumption to $4.50. We're also updating our pricing basis assumptions.

For the last six months of fiscal ‘14, we're assuming Seneca's pre-hedging natural gas prices will average between $3.80 and $3.95 per Mcf. Crude oil prices were also strong, averaging just under a $100 per barrel for the quarter before hedging.

On the basis of the current strip pricing, we're increasing our WTI oil price assumptions for the last six months of the year to $95 a barrel. Seneca's per unit expenses saw some variability this quarter. LOE for the quarter was $1.08 per Mcfe, up from $0.95 in the first quarter.

A portion of this increase of about $0.04 per Mcfe was caused by the higher transportation expense Seneca phased to NFG Midstream on the Trout Run Gathering System in Lycoming County, which is now operating with compression. However most of the LOE increase was attributable to two items that were unique to the second quarter.

In each division the exceptionally cold weather during the second quarter temporarily increased our operating cost due to the injection of hydrate inhibitors and use of diesel line heaters to keep our gas going to sales on the very coldest days.

And in California, a significant portion of the well workovers that we have planned for the year occurred in the second quarter. As Seneca's Appalachian production increases in the second half of the year, we expect consolidated per unit LOE will decline.

Therefore we’re reiterating the mid-point of our LOE guidance of $1 per Mcfe and narrowing the full year range to $0.95 to a $1.05 per Mcfe. Seneca saw a slight uptick in its per unit G&A expense which was $0.46 per Mcfe for the quarter. This was largely a timing issue related to when certain expenses fall within the fiscal year.

For the full year, we expect Seneca's G&A will range between $0.40 and $0.45 per Mcfe. Seneca's quarterly DD&A rate continues to improve. Strong performance from our eastern development area properties allowed us to record a modest upward revision to our reserves which caused our DD&A for the quarter to drop to $1.88 per Mcfe.

Looking forward, we now expect our fiscal ‘14 DD&A expense will be in a range of $1.85 to a $1.95 per Mcfe, which is down from the prior range of $1.92.

Turning to our midstream businesses as in the first quarter, our regulated pipelines have seen traffic demand for capacity and our marketing team has done a great job settling all available space on our system. As a result, revenues for the quarter were a few million dollars higher than we had planned.

For the full fiscal year, we now expect pipeline and storage revenues will be in a range of $275 million to $280 million, up from our previous range of $270 million to $275 million.

As was described in last night’s release, colder weather in our Pennsylvania service territory was the primary driver behind the Utility’s strong second quarter performance.

While it was equally cold in New York, that jurisdiction has a weather normalization pause that both insulates our margins from the impact of weather and helps to lower our customers’ bills. Through March customer bills were approximately $4.2 million lower because of that mechanism.

As a result of the bit early cold winter, residential volumes increased by 20% over last year. That combined with the modest increase in gas cost that caused our accounts receivable balances to increase. As of today, our accounts receivable aging still looks good, but it’s something we’ll be keeping an eye on, as we move through the summer.

Switching to earnings expectations, we're increasing and narrowing our fiscal ‘14 earnings guidance to a range of $3.40 to $3.55 per share. The increase reflects our strong second quarter results in the pipeline and storage guidance revisions, I mentioned earlier.

We're very well hedged for the remaining six months of the year with firm sales agreements in place to cover about 70% of our expected Appalachian production. We also have financial hedges that lock in benchmark pricing on about 75% of our forecast natural gas production and about two-thirds of our forecast oil production.

We continue to monitor both the firm sales and futures markets and are focused on adding new positions for fiscal ‘15 and beyond. On a side note, I want to make sure you are aware of a slight change we made in the way we present our natural swap positions in the earnings release.

Last night’s release now presents those divisions in MMBTUs instead of Mcfs. We made this change to be more consistent with our firm sales disclosures and with the way the derivative contracts actually settled. With regard to capital spending we have a few small revisions to our estimates.

On a consolidated basis we now expect capital spending will be in the range of $850 million to $1 billion at the midpoint a $20 million decrease from our previous guidance. Details on a segment basis can be found in the new IR deck we posted on our website this morning.

With respect to our financing plans the revisions for our earnings and capital spending guidance should have a modest impact on our financing needs for fiscal ‘14 we now expect our CapEx and dividend will exceed our cash from operations by about $175 million.

As of today we have more than $100 million in cash on our balance sheet and access to more than $1 billion in short term credit lines. So we don’t see any issues funding that short fall.

In summary it was a great quarter for National Fuel, our earnings and cash flows are growing steadily, our balance sheet is strong and we are well positioned for continued growth. With that I will turn it over to Matt..

Thanks Dave and good morning everyone. Total production for the quarter was 36.9 Bcfe or 28% higher than last year’s second quarter and essentially flat versus first quarter 2014. With average daily production actually up slightly from 404 million cubic feet equivalent per day to 410 million cubic feet equivalent per day.

In California, production was up 10% versus last year’s second quarter. More importantly our production in California has been growing all the year to a current net daily rate of over 10,200 barrels of oil equivalent per day. Notably this is 1,100 BOE per day or 12% above our daily rate in April of last year.

Primarily due to continued drilling success at South Midway Sunset and East Coalinga. Our first two Mississippian wells are in Kansas acreage produced at 7 day rates of 180 BOE per day and 300 BOE per day, with the better of the two about 35% oil. Currently both wells are shut in as we evaluate the results and consider next steps.

While we believe a portion of our acreage position is in a relative sweet spot given variability of the play over short distances, we will likely need better oil production rates and more importantly more running room to make this meaningful development for Seneca.

As we evaluate our next steps we will not drill any additional wells this year, which reduces our fiscal ‘14 CapEx by about $20 million. In the East division production was up 31% as compared to last year’s second quarter. And essentially flat from first quarter 2014 as no new wells were brought online.

Last month however, we initiated production on Pad R and Tract 100. The seven Pad R wells came on at rates ranging from 17 million a day to 22 million a day. The average lateral length was 5,100 feet with 34 frac stages and well cost averaged about $6 million. If we look at IP rate versus well cost, this is our best Pad today.

And furthers our status as the most successful operator in Lycoming County. Our total Lycoming County production is now 310 million cubic feet per day. We have just begun to drill out and run tubing on another Tract 100 Pad, the 10 well Pad T. We expect that pad producing to sales by the end of July.

In the Claremont area, we are completing our first 9 well pad. We expect to bring this pad online when the gathering system is fully installed likely sometime in July. A second 6 well pad will come on a month or to later. And in Tioga County, the Tract 595 we will complete and turn on a six well pad in August.

Adding that all up that's 31 new wells coming on in our fiscal fourth quarter. With this new production, I expect our East division fiscal 2014 net exit rate will exceed half a Bcf per day.

Given our recent results and our confidence in meeting our timelines for new production, we are raising the bottom end of our production guidance to a 155 Bcfe with no change to the top end at a 165 Bcfe. We are also lowering the top end of our CapEx range by $25 million to a new range of $550 million to $625 million.

Due to the reduced spending in Kansas and a slower spending pace in California. At our last earnings call, I spent some time explaining how we are addressing basis differentials through a combination of firm transportation and firm sales.

We have continued to solidify our position and now we have over 340,000 dekatherms a day of firm sales for the remainder of fiscal 2014 and approximately 280,000 dekatherms for 2015, much of which continues through 2016 and beyond.

We're also working with our sister company on a potential 350,000 dekatherm firm transportation project that will go into service in late 2016.

This potential new project combined with our other executed firm transport and long-term firm sales arrangements would provide Seneca with takeaway capacity in a excess of 750,000 dekatherms by fiscal 2018, giving us confidence in our long-term growth plans.

Despite all the concern about basis differentials, spot pricing to date has been better than one might think and has been improving through the year. Our fiscal first quarter stock price was 307, second quarter was 366 and April averaged 387.

And while daily stock prices are now starting to weaken considerably as we enter the [shoulder] season, we are cautiously optimistic we will avoid significant price related curtailments. It is also important to note that where our production will be growing the fastest in fiscal 2015, our Clermont area.

We are getting the best spot prices with April averaging approximately $4.25 per MMBtu. In all areas we will continue to vigilantly watch the market and opportunistically secure additional firm sales. In summary, our Marcellus program continues to surpass all expectations.

Our per well production rates in Lycoming County are approximately double those of any other operator, in our latest pass maybe the best we had. At the same time, we have driven down cost faster than we anticipated. I feel very good about our ability to achieve returns that echo or exceed our assumptions from just a few months ago.

Meanwhile on the oil side, our California production is at its highest level in 10 years. So, in conclusion, I am confident in our ability to continue our double-digit production growth and also achieve returns that are competitive with any of our peers. Now I will turn it over to Ron..

Thanks Matt and good morning everyone. Well once again, we had another solid quarter, for every one of our segments performing well. I’d like to take a minute to acknowledge and publically think all of our employees that kept the gas flowing throughout our systems this past winter.

In our utility service territory in our New York and Pennsylvania we have a coldest winter in the last 50 years. Our service men and women in the field, our customer response representatives on the phones are dispatch operators and compression engineers, all kept the gas flowing to all of our customers with only minor exceptions.

Even in those instances, our crudes have those outages fixed usually in a matter of hours. On the exploration of production side, our employees and contractors were just as dedicated as evidenced by the 28% increase in production over the last year.

We had great financials and operating statistics for the quarter and for the first six months and I’m excited about our future. While continue to drive down drilling and completion cost in Seneca, we're getting our gathering systems in place to get Seneca's completed wells flowing as safely and quickly as possible.

And we’ve got our interstate pipeline folks working on projects to get Seneca's production to market. With respect to our flowing gas production that tap two questions that are in everyone’s list during our Analyst and Investor meetings are; commodity pricing and basis differentials.

Our teams are hammering away of both issues and we regularly update our investor deck to layout as transparently as possible our approach to pricing and selling Seneca's production. Even that the street consensus earnings estimate came right at top of our quarterly results; I’d say people seem to understand our approach.

For the future, Seneca is being proactive and signing up for the necessary take away capacity to assure that the bulk of its production has firm capacity to be shift to market. Currently Seneca and our midstream companies are teaming up on a 350,000 dekatherm per day project to move gas from our WDA to Canada beginning in fiscal 2017.

We're hoping to get those project details finalized this quarter. Seneca’s near-term plan is to stay at our current activity level of three drilling rigs, two are active in the Western development area and we’ll keep one busy in the Eastern development area at least through September before moving it to the WDA.

Now even if the steady rig count, the efficiencies we have gained will allow us to drill more wells with those same rigs and we fully expect that our production volumes will easily fill the pipeline capacity that Seneca is committing to for the next 15 years.

We find a way to pick up additional capacity and firm pricing that can lock in attractive economics, growing volatility in the spot market settles down we’ll look to increase our rig count.

The supply dynamics in the Appalachian basin, the variability and weather patterns and the increasing reliance on natural gas is a fuel for electric generation that presented the entire natural gas industry with plenty of opportunities.

We’re busy working to take advantage of those opportunities to maximize the value of our collection of integrated assets. We’re regularly reconfiguring and expanding our midstream pipelines to move additional volumes of gas to market. And demand for future projects from producers and other shippers continue to be strong.

Yesterday the New York State Public Service Commission formerly approved the settlement that we achieved in our rate preceding that began in April of 2013.

That settlement among a number of other things approves our pilot expansion program for us to extend our mains to reach some of the few remaining households in our service territory that don’t use natural gas as their fuel for space heating.

Thing is worth noting; one of the points that the former PSE Chairman made during the approval of our settlement agreement.

The commission instituted the proceeding last year because they were concerned about the utility exceeding its target rate of return, largely as a result of us running an extremely efficient operation and controlling our operating expenses.

For the main drivers of those efficiencies is our integrated model, whether it's a shared employees and service centers in the field at our regulated operations or the close working relationship between Seneca and our midstream companies, I firmly believe our integrated model has added value for both our shareholders and rate payers.

This is best evidenced by both the earnings we've been able to deliver year-after-year and the rate stability our customers have enjoyed for more than half a decade. Now over the last twelve months we’ve seen some companies spin-off or sell their utility operations in what appear to be attractive multiples.

Each situation maybe a little different and those companies are facing different considerations. And some analysts suggest that a pure-play model maybe more attractive to investors than an intergraded model. But we're constantly asking ourselves those same questions.

We continue to examine our operating model and we manage our balance sheet to assure our access to the capital markets for the funds needed for our capital expenditure programs to grow the earnings of the company and we always look to maximize the value of our assets. There are always new ideas to consider. We do and we will on a regular basis.

Now operator, we like to open up the line for questions..

Thank you. (Operator Instructions). The first question comes from the line of Christine Cho from Barclays. Please go ahead..

Good morning, everyone..

Good morning Christine..

Good morning Christine..

In your gathering segment, quarter over quarter volumes were down overall, yet revenues were up, implying that your gathering rate is inching up.

Can you explain what's going on here? Did your Covington and Trout Run systems charged different rate than depending on where the incremental production coming from the overall rates move around? Also when your new gathering system is up in 4Q, is that going to charge something different?.

Yes Christine, the different systems have different rates. What you see is a dynamic of the Trout Run system A, having a higher rate than Covington and then B, also reflecting compression services this quarter, which if you look last quarter compression wasn't on for the entire quarter. So, that gets to the dynamics that you were seeing.

When we get to our Rich Valley Clermont system later in the year that will still have a different rate than the other systems. We haven't settled on a final rate yet. But once we do, we'll get that out there..

And are these like, like transfer rates or are there -- because I don't think you guys are getting much third-party volumes now.

So are you charging market rates or is this really a transfer rate?.

The intent is for it to be a market rate. So we look at the capital cost, the day-to-day operating cost and then assume a cost of capital and using those inputs drive the rates to charge those same rates to a third party customer once we [lend] them..

Okay, perfect.

Your EDA spot sales and WDA production is what really exposed the basis differentials since your firm sales essentially eliminate your base effect as you hedge that correctly, is that how I think about it?.

Yes..

And then, so can you talk about the pricing points you are exposed to and what firm transport you have for the EDA spot sales and WDA production?.

Yes. Christine, the EDA, most of the EDA spot sales are at Transco, so there are (inaudible) places. The WDA production is -- it’s a different point; it’s into Tennessee 300, but it’s probably most closely reflects Station 219..

Okay, is it literally spot or is this really big re-pricing?.

It swings, so it’s -- yes, it’s more of a spot price..

Okay. This might be premature but can you give us any insight into what you are thinking for rig plants in 2015.

Are you going to say at three or add some, and is this all a function of what you think you can get in firm sales and firm’s transports better price markets or is this something else?.

Our plan for ‘15 is to stay at 3..

Okay..

And those 3 rigs will be primarily in the WDA, mostly in that Claremont Rich Valley area..

Okay..

I think Christine, the thing to keep in mind is what we want to see and Ron kind of laid this out in his comments, what we want to see before we add rigs is some high degree of confidence in achieving a price say greater than $4 an Mcf for a significant period of time and that’s at realized price, not an NYMEX price..

Okay.

So it sounds like you have to go beyond firm sales because firm sales you can only do like a year-out or something?.

Yes, and that’s where we're putting these firm transportation deals in to place..

Okay.

I mean because of the base of concerns in the Marcellus, would you rather deploy your capital in to more midstream projects?.

Christine, we're always looking at midstream projects. And as I mentioned, we've got one that we are working on with Seneca and we have further plans to add more projects going out in to the future. The typical way we do that is obviously signing up customers for credit worthy customers for long-term contracts and we will continue to do that.

At the same time, Seneca moves along with its drilling program. I've said a number of times that the best thing we can do to prove up the value of all of our acreage to the outside world is to continue to drill in the legacy WDA area and so we intend to work at both of those consecutive or concurrently..

If I could add to that Ron, I think that Christine, the thing to understand is we haven't yet found ourselves in a situation where we had projects in the midstream and projects in the E&P that are competing for the same capital where we have to decide to do one or the other because we don’t have enough funding, we have not been in that situation..

Okay. This is last question for me.

You talk about your per unit LOE cost being higher due to the higher transportation cost associated with production from Tract 100 and Lycoming, can you talk a little bit about what’s going on there?.

Yes, it’s largely the new compression services that were added in well late in the first quarter of the fiscal year when those compression services went in, the rate went up..

Okay, thank you..

Yes. If I can add to that Christine, the thing to keep in mind is while that’s up a little, overall our LOE in the East division, so in the Marcellus is substantially lower than it is in California. So as you see our East division production grow relative to California, you are going to see our LOE trend downward..

Right. I just wanted to make sure like you didn’t have some contract rollover and it got renewed at a much higher rate or something like that..

No..

Thank you..

Thank you for that question. The next question we have comes from the line of Carl Kirst from BMO Capital. Please go ahead..

Thank you. Good morning everybody.

Just a couple of actually follow-ups from Christine and maybe thinking about the Northern Access, the 2016 project and understanding that the way these are structured to be set up as to be more market based pricing, is there -- to the extent that we haven’t seen that get the green light just yet is that just a matter of sort of the negotiations if you will internally as far as set pricing or is there any other gating factor or risk that could potentially [stop] that from happening..

It’s a combination Carl, it's still working out details internally, but in combination with that it's getting things settled with TransCanada of the associated transportation to the actual market in Canada..

Considering that's not going to reach settlement or not any of these [putting] not going to roll in that till the end of the year.

Does that have to be a, is that a pre-condition before getting these done?.

No, no, obviously you're right. The rate aspect of that contract will still be subject to the final settlement of their rate case. But we are working with them or Seneca's working with them to actually get the physical transportation volumes and those terms that obviously with a little bit of uncertainty in the rate.

But to the extent, we're able to get a proceeding agreement done with TransCanada that matches up with Northern access 2016, we're ready to move forward..

Excellent. And then maybe one other question on that because in part it speaks perhaps to the timing of when Northern Access would come in and I've generally tend to think of it as a later 2016 event. So correct me if I am wrong there.

But here you guys now with Atlantic Sunrise have a great asset as far as capacity on the East and historically, you all have a sign sometimes that capacity to work with marketers.

Is there any merit to perhaps assigning that capacity such that it might help bridge the 2016 basis out East?.

Well yes, those are options. First of all going back to the Northern Access project, you’re re right; it is coming on later in the year. As a matter of fact I referred to what is our fiscal 2017 year because we're looking at November of ‘16 for that.

That is the timeframe to the extent we don't have the details worked out just yet, but as I mentioned we're looking to get that done this quarter, we can be in shape to get that flowing.

And yes with respect to the capacity on Transco and even the capacity on Northern Access there is always the opportunity to work with the marketer under asset-management arrangements to kind of leverage that not only for the future, when the pipelines are in service, but with respect to current sale today to match that up together..

Okay.

Any lots and lots of pushes too much, but are those types of negotiations or something that perhaps might be more in 2015 announcement 2014 or any sense of how that bakes?.

Well, 2014 we're well into it already, but there is, let's put it this way. There is ongoing discussion all the time to maximize the pricing we can get. So, it can be any combination, you are absolutely thinking about it the right way the same way we're thinking about it..

Great.

And then just last question and I apologize if this was mentioned (inaudible) but I believe I heard that I April there were no curtailments and I didn’t catch if there were any curtailment actually in the fiscal second quarter?.

No, not significant anyway in the first quarter..

I just say nothing material that is standing out, okay. All right, thank you guys. I appreciate it..

Yes..

(Operator Instructions). We have another question and it comes from the line of Chris Sighinolfi from Jefferies. Please go ahead..

Hey Ron, how are you?.

Good, Chris.

How are you?.

I am well. I was just wondering if you could dig in from the pipeline for a moment, obviously you’ve had a lot of projects in the pipeline towards the last couple of years, but as I look at the quarter, it’s quite nice performance.

I was curious if there was any granularity to provide to how much either weather benefited acutely in the quarter or some of the basis deteriorations that Matt spoken until to get on your system, maybe contributing to some upside that might not always; can you just talk about that for a moment?.

Yes. I guess first of all for the quarter, it was primarily weather because of the volatility and the variation in the weather this past quarter, I think we had 10 days that we saw throughput on our system exceeded Bcf a day. Historically, if we had one or two days where a throughput was more than one Bcf, that was a lot.

So this year, it was customers and all shippers and marketers looking to scramble and get gas moved around to their particular market. So, there is some, let’s say exposure moving on to next year that we don’t see that completely filled.

So, it was a lot of short-term firm business that we did but more and Chris, our sales folks are being seen as the go-to folks to actually be able to provide that service to a bunch of shippers. So we're attempting the best we can to turn that in to a long-term firm services..

Okay, great. And switching gears perhaps from that, we saw some activity in California on sort of the fracing [dam] front if you will.

And I was just curious if there was any impact, it seems geographically there wouldn't be, given where that action has taken place versus where you are but just wondering as you might be closer to put up wins out there of any sort transcending views on that that might impact the operations for you for Seneca and [Elk County]?.

Chris, we don’t see any significant impact to us. Now, I will tell you that the new state fracing regulations have caused some delay in permitting the fracs are too horizontals at South Lost Hills, but it's a delay; it's not going to keep us from getting it done.

And I guess I would say that because of the fracing ban to some of these communities, it is probably a cause for some concern but we think it’s very unlikely to affect our operations..

Okay, great. Thanks a lot for the time here..

Thank you. We have no further questions. And now I would like to turn the call back over to Tim Silverstein for closing remarks..

Thank you, Caroline. 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, May 16, 2014.

To access the replay online, visit our Investor Relations website at investors.nationalfuelgas.com; and to access by telephone, call 1 (888) 286-8010 and enter passcode 28597632. This concludes our conference call for today. Thank you and goodbye..

Thank you for your participation in today's conference. This concludes the presentation. You may now disconnect. Have a good day..