Good day, ladies and gentlemen, and welcome to the Fourth Quarter 2011 National Fuel Gas Company earnings conference call. My name is Larry and I’ll be your operator for today. At this time, all participants are in listen-only mode. Later, we will conduct a question-and-answer session. (Operator Instructions) I would now like to turn the conference over to your host for today Mr. Tim Silverstein, Director of Investor Relations. Please proceed.

Thank you, Larry, 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'll open the discussion to questions. We’d 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, we'll begin with Dave Smith.

Thank you, Tim, and good morning to everyone. The fourth quarter kept an outstanding year for National Fuel. Recurring earnings for the quarter were up $0.06 per share or 15% over the prior year’s fourth quarter. Seneca had another strong quarter, posting a 3.8 Bcfe or 29% quarter-over-quarter increase in production, which in turns over $0.04 per share increase in E&P results. Earnings in the regulated segments were up $0.02 per share for the quarter, thanks in large part to a great job by our employees in controlling costs and driving operational efficiencies across our regulated business units. In the field, we had a good quarter, as we continue to execute on our plans for growth in Appalachia and Western Pennsylvania. Seneca continues to build momentum particularly in the Marcellus. During the quarter, Seneca had five rigs operating, which combined to spud another 23 horizontal wells, while EOG initiated an additional 13 horizontal wells. Our daily production rate from the Marcellus at the end of fiscal 2011 was nearly triple from last year’s rate. In addition, even after the sale of our offshore Gulf of Mexico properties, Seneca’s proved reserves at September 30 increased by 34% to 935 Bcfe. Simply put, overall, we are very pleased with the results we’ve achieved in the Marcellus. Turing to the regulated businesses, the pipeline and storage segment saw a reduction of its transportation revenues due primarily to the persistently strong pricing basis at Niagara, which make selling input capacity from Canada difficult. As you know, this was not a surprise, it was consistent with our expectations and consistent with our forecast. Fortunately, but also consistent with our expectations, net revenue erosion stabilized and moving forward, pipeline and storage revenues will increase significantly. Last month, Supply Corporation placed its line in expansion project and…

Thanks, Dave, and good morning everyone. As Dave said in addition to our good financial performance for fiscal 2011, it was a good year from an operations point of view, and we’ve started off fiscal 2012 in great shape. In the utility, we were on track with all our major capital maintenance projects and our $58 million in spending in our utility pipeline was pretty much right on budget. Going into the winter heating season, the utility have 97% of its gas storage capacity filled, which is just where we planned to be. Assuming a normal winter, we’re projecting that our average customers’ winter heating bills for the entire winter will be about $719 in our New York jurisdiction and $663 in our Pennsylvania jurisdiction. The estimate for New York is slightly less than last year and the Pennsylvania estimate is about 1.5% lower than last year because it was about 2% colder than normal in our Pennsylvania jurisdiction last year. In the pipeline and storage segment, all our pipeline integrity and maintenance work that we had planned for the year was also substantially completed, but some storage field work was moved into fiscal 2012. All the work that was done came in pretty well on budget and on page 20 of last night's release, where we show $129.2 million of spending in the pipeline and storage segment, $33.6 million of that total was for maintenance CapEx and the rest was for expansion projects including our Bowen Compressor Station, Line N and Buffalo Compressor Station expansion, the Tioga County extension, Northern Access and some work West to East. With respect to those projects, the Bowen Compressor Station has been running since July and Dave already covered the Line N and Tioga extension projects in next year's pipeline projects. In addition…

Thanks, Ron. Good morning, everyone. For the fourth quarter, Seneca produced 16.8 Bcfe, a 29% increase over last year's fourth quarter. For the year, production was 67.6 Bcfe, an increase of 18 Bcfe or 36%, despite the fact that we sold our Gulf of Mexico assets. In California, we produced a total of 3.2 million barrels equivalent in fiscal 2011. We drilled 32 wells at our South Midway Sunset field and added 740,000 barrels of reserves. Production is now up to 810 barrels of oil per day at South Midway, and we expect production to continue to increase as we see the impact of the increased steam injection. Last week, we saw first production from a new non-operated Monroe Shale well in California. The well came on at about 90 barrels of oil per day and is leveled off at about 60 barrels. While Seneca only have a 12.5% interest, there could be hundreds of follow-up wells. We’re excited about this initial well test and anxious to see how it holds up. Moving on to the East division, fourth quarter Marcellus production was a bit lower than anticipated due to some delays in bringing on new wells from temporary shut-ins and disappointing initial production from our second to last Covington well pad. Fourth quarter production from the EOG joint venture was down three-tenths of a Bcf due to natural decline with no new wells brought online. EOG is actively fracking now and we expect the joint venture production to jump up soon. The final Covington well pad came on at good rates such that average Marcellus production in October was approximately 142 million in cubic feet per day or 126 million net after royalty. I expect Marcellus production to stay at about that rate for the first quarter or about…

Thank you, Matt, and good morning every one. From an earnings standpoint, fourth quarter was a good one for National Fuel. Our consolidated earnings of $0.45 per share for the quarter and $3.09 for the fiscal year were towards the high end of our range of expectations. Yesterday’s release does a good job explaining the major variances in earnings, but I wanted to add some color to a few items. First is operating expenses in the E&P segment. As you saw in last night’s release, Seneca’s G&A expense for the quarter was $14.2 million, up sequential from the $11.3 million for the third quarter of fiscal ’11. This uptick was mostly attributable to one time relocation and other expenses associated with the opening of Seneca’s new Pittsburgh office. Going forward, we are still comfortable, with our $54 million to $56 million range for fiscal 2012 G&A expense at Seneca. Seneca’s per unit LOE expense for the quarter of $1.16 was a bit higher than our annual rate of $1.08 per Mcfe. The increase for the quarter was attributable to several factors including an increase in LOE on our non-operated EOG joint venture wells and higher steaming costs at our California oil properties. In addition, an out-of-period adjustment to LOE expense added a few cents to the rate for the quarter. Looking forward, as we continue to add low cost Marcellus production, we expect our LOE rate will decline into the $0.85 to $1 range that’s baked into our fiscal 2012 earnings assumptions. Turning to the regulated segments, the fourth quarter is usually a fairly quiet quarter, and this year was no exception. A bright spot though was the utilities bad debt expense. As in prior years, we take a pretty conservative approach to our bad debt accruals for the first…

(Operator Instructions) And our first question comes from the line of Andrea Sharkey of Gabelli & Company. Please proceed. Andrea Sharkey – Gabelli & Company: Hi, good morning.

Hi, Andrea, good morning. Andrea Sharkey – Gabelli & Company: So I guess first question, I was wondering if you could maybe go through the Western acreage delineation if you don't mind, in kind of what back backs, and I think maybe missed some stuff, and I don't know if you gave maybe IP rates or anything related to some of those, I guess you gave, not do it. But…

Mt. Jewett is only one, only new area that we tested in the past quarter. Andrea Sharkey – Gabelli & Company: Okay. Great.

That’s one with rates. And if you want to kind of think about how we classify the acreage, I’d define Mt. Jewett it’s still in the delineation phase, we need to get those wells online, and get a little bit of production history. Andrea Sharkey – Gabelli & Company: Okay.

Will be at Boone Mountain or at Boone Mountain, now fracking it, we should have results from that in a month or so. And then we’ve got a rig moving to Rich Valley in about a week, and then we will drill a 3 well pad at Rich Valley and we’ll test those wells. Andrea Sharkey – Gabelli & Company: Okay. And then it looks like your F&D cost for the year may be went up a little bit from last year, and I was wondering if maybe you could just address, what’s going on there, is it more just like timing, I know you spent a lot more CapEx this year than you did last year and may be timing before that sort of pays off?

Yeah, I think one big factor in the way the timing of the reserve booking worked. This year a lot of our capital went to developing Covington and basically that was drilling up PUD reserves. So those wells tend to not to add reserves, but rather just convert the PUDs to PDP. So that’s certainly a factor in what the F&D looks like. It didn’t really up a lot, it did go up a bit tough. Andrea Sharkey – Gabelli & Company: Okay. That’s helpful. And then I guess maybe just looking at different possibilities to fund a lot of the development in the western acreage, I thought – Chesapeake last night – did the – a Utica JV and then also created a different Utica company, it seems like it sort of almost like royalty interest, have you guys considered or would you think about what it make sense to do some sort of maybe royalty interest, first on that eastern acreage where soon you will have the kind of more development in Covington, it’s pretty much finished being developed and then you got track 595, starting and was that, the sort of up and running, maybe would that make sense to try to bring in some extra capital to split towards the western acreage?

Yeah, Andrea we've certainly talked about the concept of a royalty trust in our Marcellus drilling, I'm not sure that we are at a level of maturity on the western acreage for that selling makes sense. But we consider options such as the royalty trust or even a consumable at royalty trust on our California properties is a way to provide additional funding beyond what we can get from that market.

Yeah, at this point Andrea, we are pretty comfortable with our plan to lever off these debt to be able to handle those drilling needs and then our forecast, we forecast Utica development as well. Andrea Sharkey – Gabelli & Company: Okay. Great. I will turn it back. Thanks.

Our next question comes from the line Kevin Smith of Raymond James. Please proceed. Kevin Smith – Raymond James: Good morning gentleman. Matt, would you mind giving us some additional information on the, I guess the pad at Covington, it didn’t perform up to expectations, maybe some variability of what expectations were and how much were off?

Sure, it was an 8-well pad, and those wells came on more in the 2 million a day rate rather than the 5 million a day rate that we've had a most of the well pads at Covington. So it is impactful to our production numbers, but it’s one pad, I mean the next pad was that came on at 5 million a day rates again. So it was on the kind of the edge, the eastern edge of our acreage. I think when you’re looking at overall production expectations, we’re going to occasionally have a pad that’s a little weak and we probably have other pads that are stronger than expected, and we’ll completely count our assets. Kevin Smith – Raymond James: Gotcha. Can you give us, I know you touched on your opening remarks when are we expecting to see I guess next well reserves from (inaudible).

It will be a little while, we’re acquiring 3D seismic as we speak, we have a rig there in January, then we’ll have to drill pads and frac and then get them online, so it’s probably not until third quarter. Kevin Smith – Raymond James: Okay. And then lastly, before you have I guess started the calendar year like Homing stuff coming on, do you have one more well or one well pad in Covington, or what’s the new well production look like over the next three months?

Covington is fully developed, so new wells bringing on at Covington. We’ve got three rigs now on track 595, so we’ll have new well pads coming on, on 595 in January, track 100 will initiate production probably maybe more like early February for track 100, we’ll have a lot of new things coming on in the second quarter. Kevin Smith – Raymond James: Gotcha. Okay, that answers all my question, thank you.

Our next question comes from the line of Craig Shere of Tuohy Brothers. Please proceed. Craig Shere – Tuohy Brothers: Hi, couple of questions, first following up on Andrew’s question Royalty Trust kind of require certainty of service costs for whatever drilling commitment might be made, can you quickly speak to your certainty of that on the Marcellus area a couple of years?

You're asking about Marcellus Royalty Trust that we haven’t put together, so I am not really sure. I think Craig, to the extent we look at our Royalty Trust it’s far more likely we are going to look at that in California than it would be in the Utica or the Marcellus because of that kind of consideration because of the maturity and predictability associated with California. To the extent that we utilize that as a vehicle to raise capital, it would very likely be, we would very likely look to California before we look elsewhere. Let’s put it that way. Craig Shere – Tuohy Brothers: Fair enough. And realizing that we are still early on in the (inaudible) and kind of what’s still there, but as you work towards more liquids rich part of the Marcellus and even into the Utica and Geneseo, can you comment about all the ability to handle what gas processing in NGL off take from your properties?

Well, Craig, as we develop these properties that are in the oil gas window, we will build the processing facilities that we need to handle it. Those processing facilities aren’t in existence today. Craig Shere – Tuohy Brothers: Right. And would you be planning to do that internally or kind of partner, or how do you see that kind of rolling out?

More likely it would be with some third party. Craig Shere – Tuohy Brothers: And do you think enough infrastructure will be there say in the next 24 months where they continue to delineate that as in main economic sense, you wouldn’t be limited by the infrastructure?

I think there is potentially a need for the ethane solution to be in place, but that’s really the, that’s probably the only true limiting factor that can be solved by building the facilities that are needed. Craig Shere – Tuohy Brothers: Okay. Great. Thank you.

Our next question comes from the line of Mark Barnett of Morningstar. Please proceed. Mark Barnett – Morningstar: Hey, good morning, everyone.

Hi, Mark.

Good morning. Mark Barnett – Morningstar: Couple of just quick questions, you had discussed at the Analyst Day a couple of various, I didn’t hear much about today, and I was wondering you are expecting completions September, October-ish in the Boone Mountain and the Rich Valley area, so I was wondering if maybe those were areas where you were a little bit delayed on completions or if you had any detail to add on those areas?

No. Those are pretty much on schedule. Mark Barnett – Morningstar: Okay. So that’s just going to be something we will hear about more maybe in first quarter of ’12?

Yeah. Boone Mountain, we will be, we were fracing it as we speaks. So that’s what we said at Analyst Day, we might have said November completion. Mark Barnett – Morningstar: Okay.

We are just – we are just at the point of starting to drill those wells. Mark Barnett – Morningstar: Okay. And if I look at your total well costs from the Analyst Day presentations, basically is this mostly attributed to moving a little bit further west, I know that well costs for instance in Southwestern Pennsylvania are much higher than in the East, but is that kind of what’s driving this movement or?

Which movement are you talking about? Mark Barnett – Morningstar: Just over the course of 2011 and from – and also 2010, I mean the well costs had grown pretty substantially on an average basis and you said that they are coming down in the last couple of quarters here, so I’m just wondering....

Sure. Yeah, yeah, really the way to look at that is service company costs increased for a period of time and I guess that pretty quite odd. We are going to drive the cost down through efficiencies, through drilling efficiencies, drilling and completion efficiencies. And while our well cost in sort of second half of 2011 was a little over $6 million per well. We expect that in the next 18 to 24 months we are going to drive that down below five. Mark Barnett – Morningstar: So there is nothing fundamental to your more western acreage that might be driving that number up?

No, if anything the western acreage is probably a little cheaper than the eastern acreage. Mark Barnett – Morningstar: Okay. I appreciate the details. Thanks guys.

Our next question comes from the line of John Abbott of Pritchard Capital. Please proceed. Mr. Abbott, your line is open for questioning at this time. John Abbott – Pritchard Capital Partners, LLC: Hey, good morning.

Good morning. John Abbott – Pritchard Capital Partners, LLC: Just quickly here, looking at the quarter, it looks like your oil price realization came in at $101.45 on the West Coast. Why are you seeing for differentials out there right now?

We are basically at a premium to WTI and the oil is trading more at a discount of brand than it is on any kind of index to WTI now. John Abbott – Pritchard Capital Partners, LLC: And has that been factored into your earnings per share guidance?

This is Dave, we have taken a more conservative approach to the basis numbers that we use for 2012 and are basically at a NYMEX flat by assumption. The thing to keep in mind when you’re modeling our oil revenues after hedging is that we are pretty fairly well hedged on the oil side for 2012. John Abbott – Pritchard Capital Partners, LLC: I appreciate it, and then just my final question, could you remind me, have you said what the cost of that horizontal Utica well is going to be at, approximately?

We have not, and I guess I’m hesitant to just throw out a number, about 70 million. John Abbott – Pritchard Capital Partners, LLC: I understand.

It’s going to be more than Marcellus well. John Abbott – Pritchard Capital Partners, LLC: It’s an exploration well, understand.

Exploration well into deeper. John Abbott – Pritchard Capital Partners, LLC: Yes. All right, I appreciate it thanks.

Yeah.

Our next question comes from the line of Timm Schneider of Citigroup. Please proceed. Timm Schneider – Citigroup: Hey guys my questions have been answered thank you.

Good talking to you, Timm.

Our next question comes from the line of Carl Kirst of BMO Capital Markets. Please proceed. Carl Kirst – BMO Capital Markets: Here we go, I could just say ditto because my questions were answered too. Maybe just one quick, just looking at the fiscal fourth quarter in Marcellus you guys had mentioned sort of three things, or a bit of a delay, the temporary shutting, the second last well pad at Covington, was one of those I mean given that the Covington pad was coming in at two rather than five, was that primarily or was it kind of fair to say in the third or just as we kind of (inaudible).

Let’s see, I think you can probably characterize it as maybe 50% that pad and 50% the other two factors. Carl Kirst – BMO Capital Markets: The other two. Great, thanks guys.

Yes.

Our next question comes from the line of Becca Followill of U.S. Capital Advisors. Please proceed. Becca Followill – U.S. Capital Advisors: Good morning, guys. Two questions for you.

Hi. Becca Followill – U.S. Capital Advisors: Hey. On the Monterey Shale is that – does that change your perspective on what you think California production is going to do, does it allow it you to grow or does it just stabilized a little bit further out?

These were just not there yet, Becca Becca Followill – U.S. Capital Advisors: Okay.

It’s just one well, and keep in mind, we only have one-eighth interest in this so. Even if we drill a couple of 100 wells out here, we would have a one-eighth interest in wells making 60 barrels a day, it’s meaningful to us, but it’s not a substantial change in our production. Becca Followill – U.S. Capital Advisors: Okay. Great. Thank you. And then the other question is on, Dave you said your global share was to delineate acreage, so if look at page 30 from your presentation at you analyst meeting it sounds like in the areas of western development that we have a time on amount to it in Rick Valley, and then to window that acreage, but what additional acreage do you plan on delineating, how much additional acreage do you plan will be delineated in 2012?

I’m flipping to the page you are asking about. As you look at this list, we are going to delineate, if you look kind of at the top it, we will delineate 007 and 001 with some additional drilling. And we’ve got the wells producing on 001 now, we’ll further delineate Jewett, we’ll likely delineate James City, Boone Mountain, Rich Valley and very possibly some of the other areas in the Western development area. And then in addition, there will some additional delineation drilling done on the EOG joint venture acreage as well.

With that Utica?

Well, I thought she was asking significantly about Marcellus, we will be drilling wells in the Utica at Mt. Jewett, one in probably in Tionesta, which is kind of eastern Venango County and we’re very likely to drill a well at Owl’s Nest as well in the Utica. Becca Followill – U.S. Capital Advisors: Great. Thank you.

And our last question comes from the line of Josh Silverstein with Enerecap Partners. Please proceed. Josh Silverstein – Enerecap Partners: Hey, good morning, guys.

Hey, Josh.

Hi, Josh. Josh Silverstein – Enerecap Partners: You talked previously about looking for some potential oil acquisitions, whether they be in (inaudible) or elsewhere, just given that the outspend you guys have over the next few years. How aggressive could you be there?

I like the kind of bolt-on Ivanhoe acquisition that we did in California, and we have a person that really is focused on looking for those kinds of acquisitions. To the extent, we are looking at some big acquisition in another play. It would have to be something that what I would regard as bargain or pretty compelling to do it, we have a lot under plate, right now in the Utica, the Marcellus, California. So I don’t think we’re looking at a company changing event. Let’s put it that way. Josh Silverstein – Enerecap Partners: Gotcha. Okay, then the – below that you’ve talked about in the fourth quarter, was that more related to getting infrastructure in place of getting a frac where to complete your wells?

You mean the delays in bringing the wells on line? Josh Silverstein – Enerecap Partners: Right.

There is couple of factors. It was more related really though to getting a frac crew setup and the wells fracked and brought on line, but I guess really the other factor is, in the joint venture with the OG, they just made a conscious decision to delay some of their fracking and they are now getting after it. Josh Silverstein – Enerecap Partners: And then, lastly from me, you talked about a jump in the second quarter regarding the production there. I guess, where would you think you would go from, you talked about getting another, I guess $15 million per day jump over this past quarter. So that will take you from 140 to 150, up to 200 or is that too much of a jump to expect?

For an average for the second quarter, that’s too much. And I guess, I’m – I don’t think we really disclosed an estimated rate at the end of the quarter. But I expect that the end of the second quarter will be substantially higher than where we are today. Josh Silverstein – Enerecap Partners: That’s it from me.

Thanks, Josh.

With no further questions, I’d like to turn the conference back over to Mr. Tim Silverstein.

Thank you, Larry. 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 PM Eastern Time on both our website and by telephone. And we’ll run through the close of business on Friday November 11, 2011. To access the replay online, visit our investor relations website at investor.nationalfuelgas.com, and to access by telephone, call 1-888-286-8010 and enter passcode 92486219. This concludes our conference call for today. Thank you and good-bye.

Ladies and gentlemen, that concludes today’s conference. Thank for your participation. You may disconnect at this time. Have a great day.