Good day ladies and gentlemen, and welcome to the third quarter 2011 National Fuel Gas Company earnings conference call. My name is Crystal 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). As a reminder, this conference is being recorded for replay purposes. I would now like to turn the conference over to your host for today, Mr. Timothy Silverstein, Director of Investor Relations. Please proceed, Sir.

Thank you Crystal 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. As you read in last night’s release, National Fuel’s earnings for Q3 were $0.56 per share, up nearly 10% from the prior year, largely on the strength of another outstanding quarter from our E&P segment. Seneca’s production grew by 27% over last year, which in turn drove a nearly 20% increase in E&P earnings for the quarter. That growth in production and in earnings is particularly impressive in light of the sale of Seneca’s offshore Gulf of Mexico properties, which closed this past April. Utility earnings remain steady and strong, and earnings in the pipeline and storage segment, while down during this year of transformational projects, were in line with our expectations. Overall, we’re very pleased with our results for the quarter and for the year to date. As you know, over the course of the past several quarters, we set forth a compelling growth story for National Fuel. Looking to the future, as we continue to execute on our plans, we have even greater expectations. In the pipeline and storage segment, construction is presently underway on our two near term projects; Supply Corporation Line N Expansion and the Empire Pipeline Tioga County Extension. Both are on track for in-service dates this fall. Combined, these two projects will add $24 million in revenue for fiscal 2012, and will also ultimately contribute about $35 million annually when the contracts underlying the projects fully ramp up over the next two years. Importantly, both the Line N and Tioga Extension projects are readily expandable, and together with Supply Corporation’s northern access and west/east projects, provide continuing opportunity for earnings growth well into the future. Turning to E&P, our Marcellus program continues to grow at a very rapid pace. We expect capital spending in the Marcellus…

Thanks Dave, and good morning everyone. Operations across all of our subsidiaries are going really well. As Dave mentioned, supply on our Supply Corporation Line N project and our Empire Tioga Extension project are underway. Even though we had some early delays on Line N due to wet weather in the late spring, and a FERC certificate that was later than expected on the Tioga Extension project, both projects are expected to be in service this fall. The increased revenues from those projects will help offset the decline in revenue from turn back capacity at our Niagara Import point, but what’s more important is that these projects set the stage for additional expansion capacity in our system down the road. We already have a further expansion project on our Line N, fully subscribed, and we’ve received strong interest in a project to extend our Empire pipeline further into Pennsylvania. We continue to be bullish on our pipeline growth opportunities. Between June 2009 and June 2011 Marcellus gas deliveries into our legacy Supply Corporation pipelines increased from a daily average of 1.5 million cubic feet a day (MMcfd), to 69 MMcfd. Now that number does not include Seneca’s production in the eastern development area that is currently running at about 100 MMcfd, and is flowing through our Midstream’s Covington pipeline and into Tennessee’s 300 line. And as Seneca gears up its drilling on Tract 100 in Lycoming County, our Midstream Company expects to have its Trout Run gather system completed, so that Seneca’s production from Tract 100 will be ready to flow in the first calendar quarter of 2012. For our maintenance CAPEX, and our spending on new capital projects, we’re three-quarters of the way through our fiscal year, and spending in all of our segments is on track with our budget. Now I’ll turn it over to Matt for a Seneca update.

Thanks Ron. Good morning everyone. Seneca had another good quarter with production of 16.9 Bcfe, up 27% versus last year’s Q3. In California, production was down slightly, however we are expecting California production to increase over the next several months as we new wells at South Midway Sunset begin to respond to steam injection. Also in California, our Sespe drilling program is on the third of six wells planned for this fiscal year. Two of these wells will be five acre infill wells that if successful could lead to a bigger program which would add significant reserves over the next several years. Our Marcellus production for the quarter was 10.3 Bcfe, or 61% of our total quarterly production. At our Covington project in Tioga County, we have drilled all 47 of our planned wells. We are just bringing on an eight well pad, such that by early next week we should have 39 wells online and producing at a combined rate of approximately 120 MMcf. Another three well pad has been fracked and should come on within two weeks, while the remaining wells will be fracked and completed by the end of the fiscal year. Our estimated EUR for the Covington wells is 6.7 Bcf per well, or a total of over 300 Bcf for this area. A few miles to the south of Covington, at DCNR Tract 595, we now have two rigs drilling. Tract 595 has 55 total well locations. The gathering system is in place so that production will come on immediately as new pads are fracked and completed. This area should provide significant production growth in fiscal 2012. Our fifth Seneca operated rig arrived on location last month and is drilling at Tract 100 in Lycoming County. You may recall that our first well on Tract…

Thank you Matt, and good morning everyone. As Dave said earlier, Q3 was another great one for National Fuel. Our consolidated earnings of $0.56 per share were right in line with our expectations and slightly ahead of consensus estimates. There were no unusual items in the quarter, and between Dave’s remarks and yesterday’s release, I think we’ve covered all the earnings drivers for the quarter, so I won’t repeat them again here. As you saw in last night’s release, we’ve increased and heightened our 2011 earnings guidance to a range of $3.00 to $3.10 per share. The increase reflects our strong Q3 results, our updated production guidance of 68 to 71 Bcfe, and NYMEX commodity prices of $4.00 for gas and $90.00 for oil. If you back out the $0.37 per share gain on the sale of our investment and landfill gas generation assets, our recurring earnings for fiscal ’11 are expected to be in the range of $2.63 to $2.74 per share. Looking beyond Q4, we’re initiating preliminary fiscal 2012 earnings guidance in the range of $2.85 to $3.15 per share, mid-point to mid-point, a $0.32 per share increase over 2011. The continued growth of Seneca’s Marcellus program, combined with the pipeline and storage expansion projects which go in service later in the year will be the primary driver of increased earnings in fiscal ’12. Now let’s walk through the major assumptions that are baked into our forecast. Starting with E&P, as Matt said, our 2012 guidance assumes Seneca’s production will be in the range of 87 to 101 Bcfe, which is up slightly from our original forecast. It also assumes flat NYMEX commodity pricing of $4.50 for gas and $95.00 a barrel for oil for our unhedged production. Our flat pricing assumptions were set based on NYMEX script…

(Operator Instructions.) Today’s first question comes from the line of Holly Stewart with Howard Weil. Please proceed. Holly Stewart – Howard Weil: Good morning Gentlemen. I guess Dave, can you start off with the announcement not to pursue the joint venture? A very long process, obviously, over the last nine plus months or so, can you just briefly talk about the process in general and how you ultimately came to that conclusion?

Well, we didn’t come to the conclusion that we’re not going to do a joint venture. I think specifically we said it’s likely we’ll move forward on our own. And this is not black and white, you’re in a situation here where you’re dealing with likelihoods. Through the process we were fairly comfortable – I’m not going to get into any of the specifics, we had some very good, very serious offers. Evaluations were reasonable, the offers we had were very diverse. We had some offers from large integrated oil companies to smaller companies; but at the end of the day we kept balancing it against our own plans. As I said in my comments, we came relatively close twice; we decided not to move forward in large part because our plans for our own growth were so robust. So I really can’t get into any of the details. I know you’d like more color on that, but I really can’t get into any of the negotiating details for a variety of reasons; particularly because there still are some discussions. Holly Stewart – Howard Weil: Sure, absolutely. Matt, can you remind us then just about the recount ramp here over the coming year so we can make sure our models are taking into account your own ramp?

Sure, we’ve just gone to five rigs. We plan to go to six in January. Actually, we’ll probably be briefly at six in September, but we’re adding a rig and dropping one at approximately the same time. We’ll add the sixth rig in January. I don’t think we’ve disclosed anything beyond that in terms of our rig count. I think it’s probably safe to say we will continue to add rigs as we go forward, but a lot of it depends on gas prices and other factors in terms of exactly when we want to add an extra rig. Holly Stewart – Howard Weil: Okay. And then another on the Marcellus; you’ve given kind of the map of the Marcellus fairway as well as your own acreage, but the Utica’s obviously become a pretty hot topic here. Anything outside of this Marcellus fairway that’s in your Appalachian portfolio?

I’m not certain that I understand what you’re asking. Holly Stewart – Howard Weil: Anything else in Pennsylvania that you haven’t pointed out within that 750,000 net acres?

Oh, I think the vast majority of our Pennsylvania acreage falls within the Marcellus Shale fairway. Perhaps when we’re drilling this upcoming Utica, which is kind of western Venango, that may be on the feather edge of the Marcellus fairway. Holly Stewart – Howard Weil: Okay, perfect; thanks guys.

Our next question comes from the line of Andrea Sharkey with Gabelli & Company. Please proceed. Andrea Sharkey - Gabelli & Company: Hi, good morning. So correct me if I’m wrong, because I might be, but did your CAPEX spend go up for 2012 for the E&P business? But your well count, I believe, stayed the same? So I was just curious what was driving that increase.

Our CAPEX has gone up. I guess I’m not certain what well count you’re looking at from a past disclosure that— Andrea Sharkey - Gabelli & Company: I think it was the last, and maybe it’s not the same comparison, because I think it was 115 to 140 but that included the EOG joint venture wells.

I know what you’re looking at, yeah. The biggest change, Andrea, is while our gross well count stayed the same, our net well count actually went up. There were more of the wells in the previous disclosure that were going to be 50/50 with EOG, and now more of those wells are 100%. Andrea Sharkey - Gabelli & Company: Okay. So are you dropping some 50/50 EOG wells?

Essentially what happened is we were going to drill some wells with our rig that were going to be part of the EOG joint venture program, and ultimately we’ve decided we’re not going to drill there, we’re going to drill elsewhere. So essentially we replaced some 50% wells with 100% wells. Andrea Sharkey - Gabelli & Company: Okay. And then on the Beachwood area, you said you not going to have this as a focus area anymore, because of the results from the couple of wells you had. Can you remind us where, what County that was located in?

That’s on the eastern edge of Elk County. I guess the way I would characterize that is we do believe we can get much better results there as we tweak the frac design and focus on exactly where we want that landing depth to be, but the reality is that we have so many places to chose from, it’s just more likely to fall further down the priority list, and we’ll focus on a place like Owl’s Nest where we’ve already de-risked it more significantly. Andrea Sharkey - Gabelli & Company: Right, that’s fair. And then I guess one more question and then I’ll turn it back. On the Utica drilling, I guess any updates on where you stand on that, and do you think that the acreage that you have that’s projected for the Utica is mainly in the dry gas portion, or do you think you have some exposure to the natural gas liquids area or the oil area?

We think it’s mostly the dry gas window. The well that we’ll be drilling here fairly soon is about as far west as our current acreage position extends, so it may be an opportunity to see if we have a liquids component there, but honestly I think we’re more in the dry gas window. Andrea Sharkey - Gabelli & Company: Okay great, thanks so much.

Our next question comes from the line of Stephen Maresca with Morgan Stanley. Please proceed.

Good morning everybody. I’m realizing you can’t discuss it too much, but if you’re coming out saying you’re likely not to do a JV, but you’re saying you’re also in discussions, or discussions are still continuing; how do you sort of reconcile that? Are these just more high level discussions? What makes you come out and say we’re not going to do it, but we’re still discussing it?

Specifically what we said is it’s likely we’re going to move forward on our own. There are a few parties we’re still talking with, but again, it’s a matter of degree. We just think at this point it’s more likely we’re going to go on our own than through a joint venture. That doesn’t foreclose the possibility of a joint venture as we move forward. That’s specifically why we used the word likely.

Okay. And to follow up, and I appreciate it if you can’t issue any color, but understanding you have a very high bar, do you think that not getting to an agreement with somebody was more value driven or more on the size of the acreage?

Well, with respect to the size of the acreage, there were diverse proposals, so it was more with respect to what we’re able to do without a joint venture relative to what we’re able to do with a joint venture. And then your question, valuation is the way I would characterize it.

Okay, and in terms of your CAPEX now, the guidance you gave, that was for ’12, the outspend of $300 million. Was that right?

Yes.

Okay, and so you feel comfortable with the debt issuance of $400 to $500 million, plugging that?

Yes.

And Steve, just a little bit more on your question, it’s fair to say that some circumstances have changed since the start of this process, in terms of gas prices, transaction values, things of that nature. But with respect to our plans, they haven’t; I mean, with respect to our plans, we continue to have this robust growth strategy, so we haven’t changed with respect to the valuation of our assets. So I think that’s where, when we get into the relative discussion, that’s what we’re talking about. We still have this great growth plan that’s precisely what it was when we started this process, and that’s what, in large part, we’re comparing it against.

Okay, and then finally I was writing this down, but you said you fracked in the west acreage and was it 3.1 Mcfd and you said that’s not going to be a focus? Could you give me more clarity? I don’t know if I wrote down enough when you were talking about it.

It was two wells at Beachwood with a combined IP of three to four million.

Okay, thanks a lot.

Our next question comes from the line of Kevin Smith with Raymond James. Please proceed.

Good morning gentlemen; I’m hoping not to beat a dead horse, but you have mentioned twice now, you talked about your plans were more robust than maybe what bidders were thinking. Robust, is that maybe more capital maybe than people were looking to bring, or is that more of a plan of you just had better expectations for rate of returns for wells, or how should I interpret that statement?

I guess I interpret it to – we said right from the beginning that we would do this if it enhanced the shareholder value. We’d do this if we were comfortable it would result in a better outcome than what we do on our own, so as we looked at those few proposals we talked about we just concluded that with the change in circumstances, things like gas prices and transaction values, we were just better off holding on to that acreage. Not, in effect, selling it, relative to those transactions, and drilling it on our own and following our own plan.

Was operating a sticking point?

There were differing proposals, and operational issues were involved with respect to one of the discussions.

Okay, and then switching gears here, I guess that topic’s been covered pretty well; Matt, getting back to the Beachwood, is there any geological differences between that and Owl’s Nest, or do you have anything that you can kind of contribute to why you’re seeing differences in well results, and maybe why you picked Beachwood in the first place?

You know, we’re still studying it Kevin. I don’t think I have a definitive answer for you. The thing that’s interesting here is a lot of people look at our acreage and have a tendency to say that eastern is better and western is weaker, and it’s clearly not that simple, because Beachwood is about as far east as you can go in our western acreage, while Owl’s Nest is much further west. So I think that what we have learned as we’ve drilled out more of our western acreage is there will be a lot of variability. It’s not necessarily that easy to predict ahead of time, and every time we drill a well, we learn something new. So we’re very confident we’re going to have a whole lot of very attractive acreage in our western development area, but we’re kind of learning as we go.

Okay, fair enough. And if we assume that there’s no JV, does this change your capital plans? At least to my understanding, one of the reasons for the JV discussion was trying to bring a lot of PV value forward, and we recognized that earlier on the live, do you imagine now increasing CAPEX in trying to drill projects, or is it the same as it goes?

We’ve kept our capital plans consistent with the assumption that we would not do a JV, from the beginning. Every time we evaluated a specific JV proposal, we modified capital plans for that proposal, but all of our borrowing plans, our capital spending plans, were based on no JV.

Okay, thank you very much.

Our next question comes from the line of Becca Followill with US Capital Advisors. Please proceed.

Good morning. You guys had talked at one point about possibly disclosing a range of outcomes in the event that you did not do a JV. Any willingness to do that at this point?

No, particularly with us still having some discussions, Becca.

Okay, and you also have a dormant buy back program that’s authorized. With the market correction and your stock down about 9% today, any thoughts on maybe using some of your CAPEX for that, or you feel like you would rather put it into your E&P and Midstream businesses?

We’d be looking first and foremost for our spending in the Midstream and pipeline and E&P, but you’re right. With the market the way it is, we will be revisiting that with the Board, but I don’t see – right today, I don’t see us reacting immediately to that dip in the stock price.

Okay, and then finally, obviously the whole premise behind the JV was two part. One to show a market value and then second to be able to accelerate drilling. So now that you’re not going to do a JV, or it looks like it’s unlikely at this point, going beyond 2012, do you try to find a way to get additional capital to increase or further accelerate drilling? Do you look at possibly issuing equity or are you just happy with trying to live within your means at this point?

We’re not looking at issuing equity, and given the – I don’t think we’ve disclosed our five year plan with respect to CAPEX, but we’re continuing on a fairly aggressive growth pattern, and can pretty much handle any of those requirements in our existing structure, our existing capacity. So living within our means I think is a good way to put it.

Can I add something to that? If we think about when we decided to go forward with this JV, we were in an environment with a pretty frothy gas shale joint venture market. We weren’t driven by a need to raise capital in order to execute our program, we recognized that was one of the benefits of a JV, that we could accelerate it a bit, but we weren’t driven by this need for capital. So when we saw the very robust program that we can handle within our own balance sheet going forward, whether we have a joint venture partner or not.

Great, thank you.

Our next question comes from the line of Ken Schneider with Citigroup. Please proceed. Ken Schneider – Citigroup: Hey guys, how’s it going? A quick question; the uptick in the DD&A for next year, what is driving that?

When you think about how the DD&A rate is calculated, it based entirely on capital spending and reserve bookings. We’re pretty conservative as we book our reserves. This year a lot of our drilling was developing puds at Covington, and also drilling wells that were fairly remote to our development plans that don’t really allow for significant pud booking, so it’s entirely possible that at year end we’ll book enough reserves that we’ll be lower than that anticipated DD&A rate, but that’s our best guess for now. I do expect that in fiscal 2012 we’ll probably have significant reserve bookings, you’ll probably see that DD&A rate come down again. Ken Schneider – Citigroup: And then real quick on the LOE expense; I mean directionally it’s going down, which makes sense, because your Marcellus production is picking up. Can you just give us what your actual LOE in the Marcellus is, versus out in the west? On a per Mcf and a per barrel basis, if you have it?

It’s on the order of $0.35, $0.40 in the Marcellus versus --$0.50 maybe average across the Marcellus, while in the west it’s about $10.00 a barrel. Ken Schneider – Citigroup: Alright, thank you.

Our next question comes from the line of Josh Silverstein with Enerecap Partners.

Good morning guys. Just another thought, without doing the joint venture, I was curious if you guys might look at doing some other sort of asset sale, whether a funded acre sale, maybe sale some of your shallower Devonian production if that’s still something that might be on the table.

No.

Okay, and then other rate that you guys were talking about in the last press release, getting up to 240 MMcfd by the end of next year, can you do that with the existing capacity that you have? I know you were adding another line, I think the Trout Run line for the end of next year, which is about 300 MMcfd, I was curious if that was needed to come online for you guys to get to that level, or if you can do this on the existing capacity.

We need Trout Run, but Trout Run will be in place this winter.

So would that bring you guys north of 400 MMcfd?

You mean of capacity?

Right. I was curious if you had more room to ramp up above the 240 level.

Trout Run has - total capacity of Trout Run, Ron, do you recall?

350 to 4. Trout Run is 466.

466 is the total capacity of Trout Run, and we intend to use maybe three-quarters of that, ultimately. We won’t hit that level until probably sometime in fiscal 2013.

Got you, okay, I was just curious if you guys had more room to grow into that. And then I know you were talking about the upspend that you guys would have in 2012; I know you talked a little bit preliminary about 2013, growing your production then. It seems like you would still have an upspend in that year and then would you have an additional upspend close at the same 300 level, based on the capital spending that you have to do in the E&P business plus adding some additional capital for the west to east line, and potentially the central Tioga line as well?

Well, we haven’t given really any sort of guidance on ’13, so I guess I don’t really want to speculate too much. But I think we plan to keep our mind on the Marcellus while they pay out relatively quickly. And when you look at the core business, there’s a certain financing cost that ramping up when you’re adding a rig, but ultimately that catches up relatively quickly.

Got you, okay, thank you guys.

Our next question comes from the line of John Abbott, with Pritchard Capital Partners. Please proceed.

Good morning, just one quick question; with regards to your core Marcellus acreage, could you break that out a little bit? How much of that acreage is in Potter versus Lycoming, versus eastern Tioga versus western Tioga? And also, in that area where TOG’s been doing a lot of drilling in Clearfield, how much acreage do you have in that area particularly?

A lot of parts to that question. Lycoming, we have something on the order of 10,000 acres in Lycoming; Tioga County we probably have another 12 to 15,000 acres, I don’t know off the top of my head, that’s probably evenly split between – no, that’s not right. Probably more like 15,000 acres and maybe 10,000 of that is eastern and 5,000 of that is western. Potter’s another 15,000 or 20,000 acres. Clearfield County, where we’re partnered with EOG, that’s probably – that one block is on the order of 25,000 acres.

Okay, I appreciate it. Thank you.

And we have a follow up question from the line of Andrea Sharkey with Gabelli & Company. Please proceed. Andrea Sharkey - Gabelli & Company: Looking at the market in general and specifically in the energy business, it looks like a lot of companies have been either splitting off or spinning off and doing things like that to sort of be more focused and to show better market value, get better valuations for their companies. Would you give any thought to that? And if you did, in the future, what would maybe prompt you to start thinking about that more seriously? How do you view what’s been going on from that perspective?

We pretty much have the view we’ve had all along, and that’s we like the balance between the regulated companies and the unregulated companies, and what they each bring to the table. As we said, as we move down the road, certainly three or four years out, if you’re 75% or 80% E&P that may call for a different discussion. But at this point, we really like this model we have and we are building the pipeline and storage business at the same time we’re building E&P. But there’s no question that four or five years out, with the kind of program that we contemplate in E&P, it’s going to call for a re-examination of that model. Andrea Sharkey - Gabelli & Company: Okay, that was helpful. That’s all that I have, thanks.

And our next question is a follow up from the line of Mark Barnett with Morningstar. Please proceed.

Hey guys, not really a follow up, I got disconnected a little bit earlier. A quick question on talking about the sweet spot in Lycoming, and obviously with the small amount of data you have it looks great. What are you estimating there, that you would say you’re up there with the best? I’m just curious about that.

We’ve been assuming something on the order of a 8 Bcfu there; when we get a few more wells and some more well tests I think it’s entirely possible that will go up.

And then to kind of piggyback onto an earlier question about CAPEX, but as you’re developing that area and Owl’s Nest through next year, what are your projections for well cost? Do you think there’s going to be any shift, either up or down, from where you’re operating today?

Well cost is so heavily dependant on lateral lines and number of frac stages, really on number of frac stages, but frac stages to some degree are dependent on lateral lines. So our experience is that we’re wanting to do 15 plus stages per well, and that’s driving our well cost above $6 million. I don’t anticipate that dropping dramatically in the near term, however we’re already seeing significant efficiencies in our drilling and completing of the wells with our multi-well pads. So ultimately, I do see those costs coming down. A lot of it’s also dependent on service company cost. We have contracted a company to do completions for us at a better cost per stage than we had been running, so that’s going to help. We’re looking at our entire supply chain to see what else we can do to reduce those costs. It’s only a matter of time I think, we as well as everyone else in the industry is going to be able to drive these costs down.

And we have no further questions. I would like to hand the call back to Mr. Silverstein for closing remarks.