National Fuel Gas Co (NFG) 2014 Q2 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the quarter-two 2014 National Fuel Gas Company earnings conference call. My name is Carolyn 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 like to turn the call over to Tim Silverstein, Director of Investor Relations. Please go ahead.

Thank you, Carolyn, 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'll turn it over to Dave Bauer.

Thank you, Tim. 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 the major business segments contributing to the increase. On a GAAP basis, earnings were $1.12 per share, up $0.10 per share or 10%. Included in that amount were a few nonrecurring items that I'd like to highlight.

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 nonqualified deferred compensation arrangements. Earlier this year, a former executive passed away at the age of 90. The death benefit from his policy exceeded the cash surrender value we had recorded on our books, which led to the gain.

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 associated with the 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 cost to plug and abandon the wells on the lease.

We became aware of this item late in the first quarter of fiscal 2014, and recorded an initial $800,000 after-tax accrual for it. This past quarter, after receiving bids from contractors, we upped our accrual to match the updated cost estimates. 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 we will be filing this afternoon does 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's 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 are narrowing Seneca's production guidance to a range of 155 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 curtailments 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. Stronger-than-expected commodity prices were also a factor in the quarter. Seneca's before hedging natural gas prices averaged $4.52 per Mcf, well above our guidance of $3.50 to $3.65 per Mcf. Looking to the remainder of the year, we are increasing our NYMEX gas price assumption to $4.50.

We are also updating our pricing basis assumptions. For the last six months of fiscal 2014, we are 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 $100 per barrel for the quarter before hedging. On the basis of the current strip pricing, we are increasing our WTI oil price assumption 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 -- about $0.04 per Mcfe -- was caused by the higher transportation expense Seneca pays 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 the East Division, the exceptionally cold weather during the second quarter temporarily increased our operating costs, due to the injection of hydrate inhibitors and the use of diesel line heaters to keep our gas flowing 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 are reiterating the midpoint of our LOE guidance of $1.00 per Mcfe, and narrowing the full-year range to $0.95 to $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 2014 DD&A expense will be in a range of $1.85 to $1.95 per Mcfe, which is down from the prior range of $1.90 to $2.00.

Turning to our Midstream businesses, as in the first quarter, our regulated pipelines have seen terrific demand for capacity, and our marketing team has done a great job selling 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 as cold in New York, that jurisdiction has a weather normalization clause 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 bitterly cold winter, residential volumes increased by 20% over last year. That, combined with the modest increase in gas cost, has caused our Accounts Receivable balances to increase. As of today, our Accounts Receivable aging still looks good, but it's something we will be keeping an eye on as we move through the summer.

Switching to earnings expectations, we are increasing and narrowing our fiscal 2014 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 are 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 2015 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 gas swap positions in the earnings release. Last night's release now presents those positions in MMBtu's instead of Mcf's. We made this change to be more consistent with our firm sales disclosures and with the way the derivative contracts actually sell.

With regard to capital spending, we've made 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 of $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 to our earnings and capital spending guidance should have a modest impact on our financing needs for fiscal 2014. 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 shortfall.

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'll 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 year to a current net daily rate of over 10,200 barrels of oil equivalent per day. Notably, this is 1100 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 on our Kansas acreage produced at seven-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 the variability of the play over short distances, we will likely need better oil production rates, and, more importantly, more running room to make this a meaningful development for Seneca. As we evaluate our next steps, we will not drill any additional wells this year, which reduces our fiscal 2014 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 at 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 5100 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 to date, 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 to have that pad producing sales by the end of July.

In the Clermont 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 two later. And in Tioga County, at Tract 595, we will complete and turn on a 6-well pad in August. Adding it all up, that's 31 new wells coming on in our first -- in our fiscal fourth-quarter.

With this new production, I expect our East Division fiscal 2014 net exit rate will exceed 0.5 Bcf per day. Given our recent results and our confidence in meeting our timeline for new production, we are raising the bottom end of our production guidance to 155 Bcfe, with no change to the top end at 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've 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 are 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 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 spot price was $3.07; second quarter was $3.66; and April averaged $3.87. And while daily spot 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're getting our 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. And our latest pad may be the best yet. At the same time, we have driven down costs faster than we anticipated. I feel very good about our ability to achieve returns that equal 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 we'll turn it over to Ron.

Thanks, Matt, and good morning, everyone. Well, once again, we had another solid quarter, with every one of our segments performing well. I would like to take a minute to acknowledge and publicly thank all of our employees that kept the gas flowing throughout our system this past winter.

In our utility service territory in New York and Pennsylvania, we had the coldest winter in the last 50 years. Our service men and women in the field, our customer response representatives on the phones, our dispatch operators and compression engineers, all kept the gas flowing to all of our customers with only minor exceptions. Even in those instances, our crews had those outages fixed, usually in a matter of hours.

On the exploration and production side, our employees and contractors were just as dedicated, as evidenced by the 28% increase in production over last year. We had great financials and operating statistics for the quarter and for the first six months, and I am excited about our future. We are continuing to drive down drilling and completion costs at Seneca. We are 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, the top two questions that are on everyone's list during our analyst and investor meetings are -- commodity pricing and basis differentials. Our teams are hammering away at both issues. And we regularly update our investor deck to lay out as transparently as possible our approach to pricing and selling Seneca's production. Given that the Street consensus earnings estimate came right in on top of our quarterly results, I would say people seem to understand our approach.

For the future, Seneca is being proactive and signing up for the necessary takeaway capacity to assure that the bulk of its production has firm capacity to be shipped 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 are 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 at the steady rig count, the efficiencies we've 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. When we find a way to pick up additional capacity and firm pricing that can lock in attractive economics, or when volatility in the spot market settles down, we will look to increase our rig count.

The supply dynamics in the Appalachian Basin, the variability in weather patterns, and the increasing reliance on natural gas as a fuel for electric generation have presented the entire natural gas industry with plenty of opportunities. We are busy working to take advantage of those opportunities to maximize the value of our collection of integrated assets. We are 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 continues to be strong.

Yesterday, the New York State Public Service Commission formally approved a settlement that we achieved in our rate proceedings that began in April of 2013. That settlement, among a number of other things, approves a 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. I think it's worth noting one of the points that the former PSC Chairman made during the approval of our settlement agreement, the Commission instituted the preceding 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.

One of the main drivers of those efficiencies is our integrated model -- whether it's the shared employees and service centers in the fields 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 ratepayers. This is best evidenced by both the earnings we have 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 12 months, we've seen some companies spin-off or sell their utility operations at what appear to be attractive multiples. Each situation may be a little different and those companies are facing different considerations. And some analysts suggest that a pure play model may be more attractive to investors than an integrated model. Well, we are 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, look at them on a regular basis.

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

(Operator Instructions). Christine Cho, Barclays.

In your Gathering segment, quarter-over-quarter, volumes were down a little, yet revenues were up, implying that your gathering rate is inching up. Can you explain what's going on here? Do your Covington and Trout run systems charge different rates then, depending on where the incremental production is coming from, the overall rate moves 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's -- 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 will get that out there.

And are these, like, transfer rates? Or are these -- 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 costs, the day-to-day operating costs, and then assume a cost to capital, and using those inputs, derive the rates. -- to charge those same rates to a third-party customer once we land them.

Okay, perfect. Your EDA spot sales and WDA production is what's really exposed to basis differentials since your firm sales essentially eliminates your basis risk if you hedge that correctly. Is that how I think about it?

Yes.

And then -- so can you talk about the pricing point you're 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 they're a Leidy -- a Leidy basis. The WDA production is -- it's a different point. It's into Tennessee 300, but it's probably most closely reflects Station 219.

Okay. And is it literally spot? Or this really big repricing?

It's swing, 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're thinking for rig plans in 2015? Are you going to stay at three or add some? And is this all a function of what you think you can get in firm sales and firm transport to better price markets? Or is it something else?

Our intents for 2015 is to stay at three. And those three rigs will be primarily in the WDA, mostly in that Clermont/Rich Valley area. 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 $4.00 in Mcf for a significant period of time. And that's the realized price, not a 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 why we're putting these firm transportation deals into place.

Okay. I mean, because of the basis concerns in the Marcellus, would you rather deploy your Capital into more Midstream projects?

Well, I mean we're -- 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 on out into the future. The typical way we do that is, obviously, signing up customers for -- creditworthy 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 only been in that situation.

Okay. This is the last question for me. You talk about your per-unit LOE cost being higher, due to the higher transportation costs associated with production from Tract 100 in Lycoming. Can you talk a little bit about what's going on there?

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.

And hey, can I get -- 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're going to see our LOE trend downward.

Right, 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. No.

Thank you.

Carl Kirst, BMO Capital Markets.

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 is 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 scuttle 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 on the associated transportation to the actual market in Canada.

Considering that's not going to reach settlement or not, the NEB is probably not going to rule on that until the end of the year, does that have to be a -- is that a precondition before getting this done?

No, no, the -- obviously, you're right. The rate aspect of that contract will still be subject to the final settlement of the -- of their rate case. But we are working with them -- or Seneca is working with them to actually get the physical transportation volumes and those terms set, obviously, with a little bit of uncertainty in the rate. But to the extent we are able to get a precedent agreement done with TransCanada that matches up with Northern Access 2016, we are 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 generally tend to think of it as a later 2016 event, so correct me if I'm wrong there. But I hear you guys now with Atlantic Sunrise have a great asset as far as capacity on the East. And historically, you all have assigned sometimes that capacity to work with marketers. Is there a merit to perhaps assigning that capacity such that it might help bridge the 2016 basis out East?

Well, yes. Those are all options. First of all, going back to the Northern Access project, you're right. It is coming on later in the year. As a matter fact, I referred to it as our fiscal 2017 year, because we are looking at November of 2016 for that. That is a tight timeframe, to the extent we don't have the details worked out just yet. But, as I mentioned, we are 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's always the opportunity to work with a 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 sales today, to match that up together.

Any -- not to push it too much, but are those types of negotiations are something that perhaps might be more 2015 events than 2014? Or any sense of how that bakes?

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

Great. And then just last question -- and I apologize if this was mentioned as I was taking down notes -- but I believe I heard that, in April, there were no curtailments. And I didn't catch then if there were any curtailments actually in the fiscal second-quarter.

No. There --.

Okay.

Yes, I -- not significant, anyway, in the fiscal sense.

Okay. No, I understand. Nothing material that's standing out. Okay. All right, thank you, guys. Appreciate it.

(Operator Instructions). Chris Sighinolfi, Jefferies.

I was just wondering if we could dig in on the pipeline for a moment. Obviously, you've had a lot of projects in pipeline & storage the last couple of years. But as I looked at the quarter, it did quite nice performance, I was curious if there was any granularity provided to how much either weather benefited acutely in the quarter, or some of the basis situations that Matt has spoken about, and folks wanting to get on your system maybe contributing to some upside that might not always repeat? Could 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 exceed 1 Bcf a day. Historically, if we had one or two days where throughput was more than 1 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, again, 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 more, 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 are attempting, the best we can, to turn that into long-term firm services.

Okay, great. And switching gears, perhaps for Matt, we saw some activity in California on the -- on sort of the fracking banned front, if you will. And I was 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 the political winds out there of any sort of transcending views on that, that might impact the operations for you for Seneca out in Cali?

We -- Chris, we don't see any significant impact to us. Now, I will tell you that the new state fracking regulations have caused some delay in permitting the fracs of our two horizontals at Southwest Hills. But it's a delay; it's not a -- it's not going to keep us from getting it done. And I guess I would say that because of the fracking banned in some of these communities, it's 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.

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

Thank you, Carolyn. We'd like to thank everyone for taking the time to be with us today. A replay of this call will be available at approximately 3 p.m. 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 investor.nationalfuelgas.com, and to access by telephone, call 1-888-286-8010 and enter pass code 28597692.

This concludes our conference call for today. Thank you and good bye.

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