National Fuel Gas Co (NFG) 2011 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to your first quarter 2011 National Fuel Gas Company earnings call. My name is Tanya, and I will be your coordinator for today. At this time, all participants are in a listen-only mode.

(Operator Instructions)

We will be accepting audio questions after the presentation. I would like to advise all parties that this conference is being recorded for replay purposes. I'd now like to hand the conference over to your host for today, Mr. Tim Silverstein. Go ahead, please.

Thank you, Tanya, and good morning, everyone.

Thank you for 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 Dave Smith, Chairman and Chief Executive Officer; Ron Tanski, President and Chief Operating Officer; and Dave Bauer, Treasurer and Principal Financial Officer. Joining us from Seneca Resources Corporation is Matt Cabell, President. At the end of the prepared remarks we will open the discussion to questions.

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 in which they are made, and you may refer to last evening's earnings release for a list of certain specific risk factors. With that we begin with Dave Smith.

Thank you, Tim, and good morning to everyone.

As you know from last night's release, National Fuel's earnings for the first quarter were $0.70 per share, down $0.08 per share from last year's first quarter. The decrease was consistent with our expectations, it was consistent with our forecast, and was primarily attributable to a decrease in natural gas prices realized by our Exploration and Production segment; more than a dollar per Mcf after hedging.

Also contributing to the decrease, lower earnings from our Pipeline and Storage segment, as a result of rising operating costs, primarily pension expenses and expensed expansion projects, and also turnback capacity at Niagara, due to relatively strong gas prices at the Canadian border, which, as you know, we've been talking about and we've anticipated.

Turning first to our E&P segment, and putting aside the impact of natural gas prices, Seneca had another outstanding quarter, particularly with regards to its efforts in the Marcellus. During the quarter, Seneca brought an additional 14 net Marcellus wells on production. As of the end of the quarter, over 30 net wells were producing 90 million a day from the Marcellus, up from 57 million a day at the beginning of the quarter.

First quarter production from the Marcellus was 5.9 Bcf, a more than 12 times increase quarter-over-quarter, and more than two times our 2010 fourth quarter Marcellus production. We're very pleased with this growth, and as we add two additional rigs by this fall, we're anticipating continued significant growth in the quarters to come. Matt will provide a full update on Seneca's operations later on in the call.

Before leaving the E&P segment, let me say just a few words on the status of a potential Marcellus joint venture. We opened the data room in late November, a number of parties signed Confidentiality Agreements, visited the room, and had access to the information, which is extensive. Some parties have only recently signed Confidentiality Agreements and are scheduled to visit the data room in the next few weeks. It's fair to say that we remain encouraged by the level of interest that has been expressed to-date, and we are presently in ongoing discussions with multiple and diverse potential partners. Overall, things are proceeding according to plan, and we're -- are really going pretty well.

Now that said, it's important to understand that we're in the fortunate position of not being compelled to do a joint venture out of a need to solve some significant problem. We're not capital-constrained or, given our extensive mineral fee interest, up against lease expirations. So with or without a joint venture, we will continue to grow for years to come. Thus, as I've said before, we'll do a joint venture only if it adds significant shareholder value.

Turning to our Pipeline and Storage segment, we continue to make great progress on a number of expansion projects. These projects take advantage of the geographic position that is; one, smack in the middle of the Marcellus; two, in close proximity to growing East Coast markets and the pipelines that serve them, and; three, one of the very few gateways to eastern Canadian markets. While strong gas prices at the border present our Pipeline and Storage segment with the short-term challenges I mentioned previously, they also provide us with a tremendous opportunity to transform our system from one that imports gas from Canada to one that is bidirectional; one that can also move gas into Canada. Much of that gas will be Marcellus gas. Ron will update you on these efforts and on the status of a number of Pipeline and Storage projects we have on the table.

Finally, during the quarter, we continue to make progress on our plan to divest our smaller, non-core businesses and focus our attention and our capital on our main segments. In that regard, we entered into an agreement to sell our interests in two landfill gas-electric generation projects, and we expect to realize a significant gain on the sale. While these are good businesses and were profitable investments for National Fuel, they are relatively small, are unrelated to our other businesses, and have limited upside, particularly compared to our opportunities in the Marcellus. Proceeds from the sale, which is expected to close within the next few weeks, will be used to fund Seneca's recent acquisition of acreage in Tioga County.

In closing, fiscal 2011 is off to a good start as we continue to execute on our growth plans in Appalachia. With that, I'll turn the call over to Ron.

Thanks, Dave, and good morning, everyone.

We're in the middle of our heating season here in western New York and northwestern Pennsylvania, and our system is holding up fine. Temperatures during the first quarter were 3.8% colder than last year in New York, and 5.5% colder than last year in Pennsylvania. As a result, we saw our Utility throughput increase by a Bcf year-over-year.

Pipeline and Storage throughput was also up almost eight Bcf year-over-year, mostly related to the deliveries that started on our Empire Connector in 2010. The average delivered gas price for our utility customers for the heating season in New York is projected to be approximately 3% lower than prices last year, and about level in Pennsylvania, and we're not expecting any major increase in our overall receivables.

The cold weather continued through January, where we saw temperatures that were 4.7% colder than last year in New York and 5.9% colder in Pennsylvania. So far this winter, we had our peak-day deliveries on the Utility system of just over one Bcf in one day. That peak day occurred on January 23 when the temperature averaged five degrees for the day. Our overall system performed quite well, and we only had some minor pressure issues on small pockets of our system that were dealt with immediately.

Today, our storages are still 60% full, and we don't see any problem meeting delivery requirements for the rest of the winter. I'd like to acknowledge and thank our operating and customer service crews that do a great job all year, but perform under extraordinary circumstances during the winter months.

During some of the recent cold snaps and weather issues that have affected the whole East Coast, we have been able to take in additional interruptible volumes of gas from Canada, when there have been some capacity constraints or price spikes under traditional south-to-north pipeline routes. But as Dave pointed out, over the last year or so, the price for Canadian gas has increased and now generally ranges between $0.20 and $0.40 per decatherm higher than other available Appalachian supplies. That situation caused a turnback in some long-term fixed capacity, which has decreased the earnings in our Pipeline and Storage segment, and that's why we've been talking about the various expansion projects to counteract that earnings decrease. Those projects continue to move along on schedule.

In January, we received from FERC our notice to proceed on the compressor station for our Line N Expansion Project designed to move Marcellus production through our system to an interconnection with Texas Eastern. Our contractors are beginning to move on site and will break ground any day now. We expect to receive our FERC notice to proceed for the pipeline phase of that project this month, and we plan to have right-of-way crews ready to start work immediately. We're planning to have both the compression and pipeline phases of this project in service in September or October of this year.

Another project that we will be busy with this year is our Tioga County Extension Project. We expect to get our FERC authorization and construction permits this month, and will be ready to get construction underway in the spring, and have the pipeline ready to accept gas for delivery in September of this year. The capacity for both the Line N project and Tioga County Extension project are fully subscribed, and we expect to begin collecting annual reservation fees beginning in September and October. Those reservation fees will start out at about $26 million per year and ramp-up over an 18-month period to $36 million annually.

Our other major projects have a longer time horizon, but are also moving along. For our Northern Access project, that has a late 2012 projected in-service date, we have had our preliminary public meetings, where we got a pretty good reception, and we expect to be submitting our FERC permit application this quarter. The West-To-East project has the longest time horizon, and we're waiting for more Marcellus production from the area to provide more support for the project. We continue to work with landowners and state agencies regarding route logistics and waterway crossings, so that we can be ready to go with our FERC filing as soon as we get the necessary capacity commitments. To date, we have commitments for about 30% of the project capacity.

Now, I'll turn it over to Matt Cabell to update us on Seneca.

Thanks, Ron, and good morning, everyone.

Seneca had another good quarter with overall production of 15.7 Bcfe, up 4.1 Bcfe versus last year's first quarter. That's a 36% increase, and indicative of our expectations for this entire fiscal year. Also, it is important to note, that our production is shifting significantly to the East Division, which accounted for 52% of the Company's first quarter production.

Gulf of Mexico production for the quarter was 2.7 Bcfe, down 26% versus a year ago. Some of this is due to natural decline, but a substantial portion is related to a workover of one well at Ship Shoal 189, our largest producing field. That well has been repaired, and Gulf production was up to 30 million cubic feet per day for December and January.

Moving on to California, production was 4.9 Bcfe, down 5% versus a year ago. Ongoing drilling operations should help to bring production back up later this year. We have drilled 17 wells at South Midway-Sunset, which is the area that we acquired from Ivanhoe a year and a half ago. With 16 additional wells planned, results have been very encouraging. We've begun steaming these new wells and expect to see a significant production increase within six to nine months. Our Sespe drilling program, which includes two five-acre down-spacing wells, will begin in April.

In the East Division, production for the quarter was 8.1 Bcfe, up 184%. Marcellus Shale production reached 90 million cubic feet per day at the end of the quarter. As we brought on additional wells in the Covington area and completed an acquisition of EOG's minority interest in our Tioga County operations. The $23 million acquisition adds 42 Bcf of proved reserves and increases our anticipated fiscal 2011 production by five Bcf. We continue to be very active in Tioga County with three rigs currently drilling. Thirty-five wells have been drilled to TD, 22 wells are hooked up to sales, and nine more are in the completion stage.

Meanwhile, at the EOG-operated Punxsy development area in Clearfield County, 30 wells have been drilled, 18 are producing, and we expect to have 10 more completed over the next three months. We are now getting consistent IP rates in this area of seven to nine million cubic feet per day. Further West at our Owl's Nest location, we have three horizontal wells drilled with varied landing depths. We expect to begin fracking those wells later this month. One of our goals at this location is to optimize our frac design. We will be experimenting with tighter spacing between stages, as well as frac stage placement based on measured rock properties.

We drilled our first Seneca-operated Marcellus horizontal well only 18 months ago. And since then, we've completed 32 Seneca-operated horizontal wells and added 90 million cubic feet of Marcellus production. While results were very good from the beginning, we continue to learn, refining our frac design and improving our drilling and completion efficiency. We have increased our expected average EUR per well to four Bcf for our Western acreage and six Bcf for our Eastern acreage. Much of this increase is the result of longer laterals and better completion design.

On the cost side, we're drilling wells faster and completing them more efficiently with multi-well pads and centralized water facilities. However, longer laterals and service company increases have more than offset the gains. Such that current well costs are approximately $5 million per completed well, assuming a 12-stage frac. So, while well costs have been running higher than we once expected, results have been substantially better as well. Such that, at $5 million per well, our expected pre-tax internal rate of return at a $4 gas price, ranges from 28% for our four Bcf wells, to 53% for our six Bcf wells. Over time, we expect to drive this cost down to $4 million or less, but fiscal 2011 well costs will be higher than originally forecasted.

Looking forward for the remainder of fiscal 2011, we're expecting continued growth in our Marcellus Shale production, and anticipate hitting 100 million cubic feet per day sometime in the current quarter. By the time of our next conference call, we should have some results from our three-well frac job at Owl's Nest, and we'll have sidewall core samples from a vertical well through the Utica Shale. While exploration and evaluation of the Utica is still in its infancy, our mapping indicates that much of our acreage is prospective, and we are anxious to determine how much additional value this play might add to our overall shale potential.

With that, I'll turn it over to Dave Bauer.

Thanks, Matt, and good morning, everyone.

As Dave said, the first quarter was a good start to our fiscal year. Both Seneca's 15.7 Bcf of production and our consolidated $0.70 per share of earnings, were right in-line with our expectations for the quarter. There were no special or one-time items, and all of the earnings drivers are covered in yesterday's release, so I won't repeat them here. Instead, I'll focus on our updated earnings and cash flow projections for the rest of the fiscal year.

As you read in last night's release, we've updated our earnings guidance for fiscal 2011 to a range of $2.75 to $3.00 per share. In addition to reflecting the $0.34 per share gain we expect from the sale of our landfill gas generation assets, this range considers three additional items that essentially offset each other.

The first is an increase in expected production at Seneca, as a result of the additional Tioga acreage we acquired during the quarter. As Matt said, that acquisition caused us to increase our production guidance by 5 Bcf to our new range of 65 to 75 Bcfe. However, going in the other direction is a $3 million increase in Seneca's G&A budget to reflect the cost of opening our Pittsburgh field office and re-locating dozens of our staff to that area this summer. As a result of this increased spending, we now expect Seneca's G&A expense for the full fiscal year will be in the range of $41 million to $44 million. Also going in the other direction, is a further $3 million reduction in Supply Corporation's transportation revenues, due to capacity turnbacks at Niagara, which ended up being greater than we had expected. Previously, we had forecast capacity turnbacks impacting 2011 revenues by $4.5 million. We now think it will be more in the area of $7.5 million.

Our earnings guidance assumes flat NYMEX commodity prices of $4 for natural gas and $80 for crude oil, which are a bit lower than the current strip for each commodity. As always, we've included an updated Sensitivity Table in yesterday's release to give an idea of the impact of changing commodity prices on earnings. You'll note that the impact of a $1 change in natural gas prices is proportionately less than it was a quarter ago. Since our last earnings call, we've added 5.7 Bcf of natural gas hedges for the last nine months of the year at a weighted average price of $5.06 per Mcf. Considering these new trades, we're now about 55% hedged for the last nine months of the year.

One last comment on our earnings guidance. Our range assumes normal weather in the utility's Pennsylvania service territory. As you read in last night's release, weather in the first quarter in Pennsylvania was nearly 4% colder than normal, and that trend has continued through January, which was a little more than 8% colder than normal. Though weather impacts throughput in the New York Division of our utility and in the Pipeline and Storage segment, earnings are not significantly impacted in those jurisdictions, due to the New York Division's weather normalization clause and the straight-fixed-variable rate design employed by our pipeline companies.

Turning to our spending plans, last month we updated our capital budgets to reflect our recent Tioga County acreage acquisition. Not much has changed since that update, so we're still comfortable with the $665 million to $800 million range for our fiscal 2011 consolidated capital budget.

Our balance sheet continues to be in great shape. At December 31, our equity-to-capitalization ratio was 62%. In November, we repaid $200 million of long-term debt using cash from our balance sheet. At quarter-end, we were in a small short-term borrowing position, which was not unexpected given our capital spending, and the fact that December is typically a low-point in our working capital cycle. Using the mid-point of our earnings guidance and capital budget, we expect to be in a short-term borrowing position in the area of $50 million to $75 million by fiscal year end, which is consistent with the level we included in our Analyst Day presentation last November.

Though we're spending more at Seneca as a result of the Tioga acreage acquisition, proceeds from the sale of our landfill gas generation assets should be adequate to fund that increase. Our next long-term debt maturity is $150 million in November of 2011. At this point, I expect we'll refinance that maturity and any short-term debt that's outstanding at the time with a new long-term issuance sometime this fall. However, the amount and timing of any issuance is largely dependent on the outcome of the JV process. If we do a JV, it's quite possible the up-front consideration we receive in the deal will be sufficient to fund the maturity.

With that, I'll close and ask the operator to open the line for questions.

(Operator Instructions)

Our first question will come from the line of Kevin Smith with Raymond James. You may proceed with your question.

Good morning, gentlemen, and congratulations on a nice quarter and strong production in the Marcellus.

Matt, I wanted to ask you, the lateral links of the Owl's Nest and also how much -- you mentioned you're varying the depths of those wells, how much are they are from each well to well moving around?

The laterals are all over 4,000 feet, and under 5,000. I don't recall exactly what their lengths are. In terms of the landing depth, Kevin, it's -- let me put it this way, at least -- at least two of them are separated by the Cherry Valley Limestone, if that means anything to you. There's two members to the Marcellus, the Union Springs and the Oatka Creek. So two of the wells are in the -- are in one of those intervals and one is in the other. In terms of total footage, I don't think I can tell you that off the top of my head. It's-- you know, since it's within the Marcellus, it's not -- not a huge difference.

Okay. Is it fair to say it's still a science project as far as trying to figure out which one is the best and -- and trying to -- still trying to figure out which way to develop it?

Well, yes. And there's a lot more to it than what I'm able to explain on the conference call. But recognizing that what we want to do is have our well bore in the portion of the rock that has the best rock quality and also have those frac stages in that best rock quality, as well.

Fair enough. One last question. Any updates on Clearfield and the Midstream bottlenecks?

Oh, I think we're in good shape now on the ability to get that gas to sales. Now's just a matter of getting wells fraced and hooked up and online.

Okay. So, no gathering bottlenecks right now that you know?

No.

Okay, thank you very much.

You're welcome.

Our next question will come from the line of Jonathan Lefebvre with Wells Fargo. You may proceed with your question.

Good morning, guys.

Hi, Jonathan.

Realizing that you're limited on what you can say about the JV and it's a very sensitive topic, I appreciate the comments earlier. But, was wondering if maybe you could give us a little more granularity just around numbers of people who visited the data room, how many people have signed confidentiality agreements and maybe what the profile looks like, if it's more majors, independents, internationals, who are you talking to at this point?

Jonathan, your instincts were good in the beginning, in that we really -- not only are the confidentiality agreements, but it really wouldn't be wise for us to get into any of the particulars regarding any of the discussion. So I think I'll leave it at multiple and diverse. And, as I said, we're pretty happy with where we are. And I don't think I want to go much further in terms of talking about the parties or the numbers.

Okay. Fair enough. And then if I can just try my luck here one more time, the three to six-month timeline you laid out for us, what's the probability in your mind that we get something to the finish line in that type of time frame?

I guess in part -- the three to six-month time frame is when we expected to have potentially an answer on whether or not we're moving ahead with the JV. I don't think we anticipated we'd close one in that period of time given the complexity of it. And that's still a very achievable time frame. I think there's no reason for us to change that. We said that in November. But, by saying that, recognize it is complex. The data room's extensive. I mentioned there are some parties that are yet to go through the data room. And so, at the end of the day, if it slipped a month or two, it's more important for us to get the best partner, to get the best deal, as opposed to, as opposed to meeting some -- some self-imposed deadline.

But, yes, overall, we're still -- our expectation is that -- that's an accurate time frame.

I appreciate that. Then just as a follow-up. If you don't do deal, should we assume that you'll -- you'll develop the acreage on your own? What other options might you pursue?

We have a pretty aggressive growth plan if we decided not to do a joint venture. Yes, we'd aggressively pursue it on our own.

I would say the same thing, Dave. We'll aggressively pursue it on our own. And, of course, not doing a deal this year doesn't preclude us from doing one five years from now, or three years from now.

Understood. And then Matt, just final question here. On the Utica, when do you think we'll get more detail around that? When do we know more on the vertical test?

It will be a while. All we're going to get in this first vertical are some sidewall cores that we'll analyze. I'm not sure that we'll say a lot about it. I wouldn't be expecting anything significant on the Utica for a while.

So nothing in '11?

Possibly something more in '11, but I think the way you asked the question is right. It would be -- what you shouldn't be thinking is we're going to be making some announcement about Utica in the next several months.

Fair enough, understood. Thanks for the time, guys.

Thanks, Jonathan.

Our next question will come from the line of Carl Kirst with BMO Capital Markets. You may proceed with your question.

Thanks. Good morning, everybody. Just a couple of quick micro questions, most of the bigger ones have been asked. But, first, on the E&P -- and I appreciate all the color around the cost here -- I'm just curious, does the Pennsylvania move to increase the fracking rules, regulations, multicasing , does that have any impact on what you guys were doing before, after, and I guess on cost.

No. There isn't anything in what the State's asking us to do that is different from what we've been doing all along.

Okay, that's what I assumed. I just wanted to make sure I clarified.

Secondly, this is for the pipes, but really for National Fuel, overall. With respect to the pension expense, can you refresh my memory as far as what the increase in pension expense for the pipes (Pipeline) is for the year? But also, is that -- are we seeing the pension cost, the higher pension costs, just mainly on the pipes, or is it also being extended to the Utes (Utilities), as well?

Carl, this is Dave. We're seeing it on, mostly on the pipeline side and in the Pennsylvania Division of our Utility. In the New York Division, we've got some pretty good rate treatment on that, and are able to defer that, those increases. In the pipes, we're looking at about a $5 million increase year-over-year and probably a little bit less than that on the -- on the utility side, maybe in the $4.5 million range.

Great. Perfect. Thanks, guys.

Yep.

Our next question will come from the line of Becca Followill with US Capital Advisors. You may proceed with your question.

Good morning. Two questions for you. One, what are net cash proceeds expected from the landfill sale? And then, second, on your leverage, with you paying down the debt, the $200 million debt and the additional debt coming due that you may refinance, what's your target leverage levels going forward?

The proceeds from the -- the sale will be, you know, in the $60 million range. And in terms of target leverage, given our current mix of regulated and non-regulated, our targets are in the 55% to 60% equity-to-cap area. But I'd expect us, as we get more and more E&P, like for that to be at least in the 60% area.

Great. Thank you.

Sure.

Our next question will come from the line of Jim Harmon with Barclays Capital. You may proceed with your question.

Thank you. I know the math looks really compelling when you look at doing a JV. But, what's your assessment of the region's ability to handle a truly stepped-up drilling program in terms of infrastructure? In terms of people cost, equipment cost, gathering costs, all that stuff?

Well, I guess, Jim, I'll take a shot at the infrastructure first. I think that's one of the significant advantages we have really relative to most of the other JVs, given our -- the contiguous nature of our acreage and our -- and no time frames with regard to lease explorations. We're able to, far more I think, efficiently drill than you've seen with most of the other joint ventures that in large part are drilling to old acreage.

As a result of that, we're also able to put the infrastructure in to deal with the production. I know there's a lot of concern in Appalachia about infrastructure, but in our case I think we have one well shut in, and that's way down in Lycoming County and we're building a gathering system to that now.

So, not only do we have the ability to efficiently drill, we also have the appetite to put money in the ground on the Midstream and Pipeline and Storage side. So we'd be taking proceeds and putting it -- putting it back into the ground. Which I think is a terrific benefit to the joint venture, as well. So, we're not terribly concerned about the infrastructure constraints in Appalachia. I'll let Matt talk about the people constraints.

Yes, Jim, if I understood the second half of your question, you're concerned about, is there some limit to how -- how much we can grow in terms of the people we need and the fracking crews, et cetera.

Well, there's that element and there's also an element, everyone decides this is a great idea -- extract capital and goes to work accelerating drilling, but there is a cost issue, I assume, that follows that. And how would you manage cost?

Yes. I think the cost inflation is more a function of the rate of growth than any absolute limit. That said, I guess I look at the current growth of drilling activity in the Marcellus, and you know it's challenging today. I don't think it's going to become substantially more challenging because the service companies are reacting to it.

We have seen an increase in the cost of pressure pumping crews and coiled tubing units. There may be some additional inflation, but I don't think it's -- I don't think it's going to be a major constraint to the growth of the play.

Okay, thank you.

Ladies and gentlemen as a reminder, if you would like to ask a question, please key star-one at this time.

Our next question will come from the line of Mark Barnett with Morningstar. Please proceed with your question.

Hey, good morning, guys.

Hi, Mark.

Just a couple of quick questions. With that -- that EOG purchase, do you have the acreage number? I know you have the cash number, but -- ?

It's a little less than 2,000 acres.

Okay.

That's really -- the better way to look at it is -- since a lot of this was either drilled or had proved undeveloped locations on, it is to look at it in terms of the proved reserves we added which was 42 Bcf.

Yes? Okay. Sorry if I'm a little all over the place. Yes, on the service company cost side, you got a couple questions already. But, where in particular are you seeing that sort of -- those cost increases coming from to drive up well costs to the $5 million range?

Yes, pressure pumping services. It's all on the completion side. All on the simulation side.

Yeah.

The drilling, our costs are falling on the drilling side primarily because we're drilling the wells more efficiently.

Yes.

But the cost to frac the well and drill out the plugs has continued to rise.

Okay. And I guess I missed the additional revenue impact on the Midstream, on the turnbacks, I got the -- I got the volumes number, but just missed the revenue impacts.

Yes, starting out at the end of this fiscal year when we start out, we will start at about $26 million, and then over an 18-month period, it ramps up to $36 million.

Okay. That's enough house keeping for me. Thank, guys.

Our final question will come from the line of John Abbott with Pritchard Capital. You may proceed with your question.

Hey, thank you very much for taking my question. Just out of a curiosity -- I know you're not going to give any big announcement about -- you won't be giving any big announcement about your Utica vertical well. But are you willing to say whether or not that well test will be outside your core area of Potter, Tioga and [Lycoming] counties?

Yes, it's outside of Potter, Tioga, and Lycoming Counties.

That's great. One other quick question. When will we get first results out of Potter County?

We'll have some wells fracked in Potter County sometime I think -- I think certainly should be within this quarter.

All right. Thank you very much.

You're welcome.

There are no additional questions at this time. I would now like to hand the call back over to management for closing remarks.

Thank you, Tanya. 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 2.00 p.m. eastern time on both our website and by telephone, and will run through the close of business on Friday, February 11, 2011. To access the replay online, visit our Investor Relations web site at investor.nationalfuelgas.com; and to access by telephone call 1-888-286-8010 and enter passcode 96062954.

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

Thank you for attending today's conference. This concludes the presentation. You may now disconnect and have a great day.