Good day, ladies and gentlemen, and welcome to the third quarter 2012 National Fuel Gas Company earnings conference call. My name is Jeff, and I will be your coordinator for today. At this time, all participants are in a listen-only mode. Later, we will facilitate 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. Tim Silverstein, Director of Investor Relations. And you have the floor, Mr. Silverstein.

Thank you, Jeff, 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 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 will begin with Dave Smith.

Thank you, Tim, and good morning to everyone. Last night National Fuel reported third earnings of $0.52 per share. Continuing the trend from the first half of the fiscal year, lower realized natural gas prices had a significant impact on our consolidated results. Quarter-over-quarter Seneca’s Natural Gas prices after hedging were $1.55 per Mcf lower, which reduced E&P earnings by about $0.20 per share. Despite a drop of 28%, and realized natural gas prices. Consolidated earnings overall were down only 7% or $0.04 per share. Thanks in large part to our diversified business model and our continued focus on long-term growth particularly in our midstream businesses. There were multiple bright spots across all of our major business segments. At Seneca, consolidated production was up 31%. In the Pipeline and Storage segment the Line N and Tioga County extension projects help drive a $0.10 per share increase in earnings. The Trout Run gathering system was just recently placed in service, and while utility earnings were down slightly by $0.02 per share our employees in both of our regulated business segments did a great job and keeping an eye on spending, which help to limit the overall impact of the 17% warmer than normal winter. Operationally, National Fuel had a great quarter, as I just mentioned Seneca‘s consolidated production of 22.1-Bcfe increased 5.2-Bcfe or 31% despite a reduction in CapEx. Most of this increase in production occurred in each division where in late May we commenced production on four very good wells on our Tract 100 acreage in Lycoming County. Despite voluntary curtailments into the constrained and discounted Tennessee 300 Line, we achieved just a few days ago our major milestone of 200 million cubic feet per day of net production from the Marcellus Shale. We expect production will continue to grow…

Thanks, Dave. Good morning, everyone. It was another good quarter for Seneca. East division production was up 38% and west up 6%. Focusing on California first, our fiscal 2012 drilling program has gone well with 22 new producing wells on line at South Midway Sunset, another 20 in North Midway. At Sespe we drilled six wells, including two more five-acre infill wells and two cold water tests. We plan to frac these wells sometime this fall. We also drilled a horizontal etchegoyen well at North Lost Hills, which is producing 50 barrels of oil per day. A good rate considering this is a relatively shallow, $400,000 horizontal well. A second horizontal is planned for North Lost Hills in fiscal 2013. Moving on to Pennsylvania, we brought on our first four well pad at Tract 100 in Lycoming County. These four wells all came on at rates in excess of $10 million a day. And have averaged estimated ultimate recoveries of about 10 Bcf with the best well and 8,100 foot lateral, expected to produce approximately 14 Bcf. We’ve just finished fracking another three well pad at Tract 100, and expect to have those wells on line in about two weeks. Two of these wells were fracked using reduced cluster spacing, such that frac stages and clusters are more closely spaced, potentially increasing both the production rate and the recovery per foot of lateral. We will test this in a few other locations over the course of the next several months, in order to evaluate the cost benefit trade off. We’re very excited about the results we’re achieving in Lycoming County. This is a challenging area operationally, due to the rugged terrain, deep drilling depths, and high pressures. While cost maybe a bit higher here, we are hoping that EURs of…

Thank you, Matt and good morning everyone. As Dave said earlier considering the significant drop in natural gas prices, the third quarter was a good one for National Fuel, the earnings of the regulated segments are pretty straightforward. And last night’s release hits on all the major drivers. So I won’t repeat them. At Seneca there was some variability in per unit operating expenses that’s worth commenting on. Seneca’s $0.91 per Mcf of LOE expense for the quarter improved from the $1.14 rate that we saw in the second quarter. Most of that decrease is attributable to the jump in Seneca operated production in the Marcellus, which carries a lower LOE burden. A reduction in LOE on our non-operated joint venture wells was also a factor. Per unit G&A expense dropped to $0.59 per Mcf, again mostly due to the growth in Seneca's Marcellus production. DD&A increased to 237 per Mcf; we have seen an upward trend in that rate over the last few quarters, which is generally due to our delineation efforts in the Western Development Area, which tend to be expensive wells that don’t initially add much in the way of reserves and our spending in California. Also in the third quarter, we were forced to write-off a fair number of reserves associated with the EOG joint venture, which further increased our DD&A rates. Property franchise and other taxes were $4.3 million, including a $2.6 million accrual for the PA impact fee. Going forward, assuming current gas prices and a three rig program, we expect the impact fee to average about $2.7 million per quarter. However changes in gas prices and the timing of when we spot our wells could impact that amount. Switching to guidance, we’re increasing and tightening our fiscal 2012 earnings guidance to a range…

Thank you. (Operator Instructions) Your first question comes from the line of Andrea Sharkey with Gabelli & Company. Please go proceed. Andrea Sharkey – Gabelli & Company: Hi, good morning.

Good morning.

Good morning, Andrea. Andrea Sharkey – Gabelli & Company: I guess my first question would just be if, have you guys seen any issues with water sourcing in the Marcellus? I know a lot of your peers have had some issues. I would assume if that hasn’t been a big impact for you guys, but just wanted to get your thoughts on that?

Andrea, this is Matt. It has not been a big issue for us, largely because we're staying ahead of it. So we've got water that we need for the fracs that are coming up. In addition, one of our primary water sourcing points in Tioga County comes from a stream that's fed by an abandoned coal mine, so it's actually a place where they, the river basin commission want us to take that water, because it actually cleans up the stream and removes some of the acid mine drain. Andrea Sharkey – Gabelli & Company: Okay, great. And then on the EOG reserve that you guys had to write-off, is that just a timing issue, because you’re not planning on drilling that within, I guess the next five years or whatever the rule is on that?

It’s a combination of things, Andrea. Some of it is simply pricing, as we evaluate these, we have to use the current pricing to evaluate the economics of the, the crude undeveloped wells. We’ve also had some weaker performance on the last set of wells that we drilled with EOG, so there were some negative revisions associated with that as well. Andrea Sharkey – Gabelli & Company: Okay, that’s helpful. And then I guess just the last thing for me is actually on the pipeline. With northern access in line and going into service, you gave the top line impact for the full year, but I guess, how should we think about that maybe sequentially ramping up through the year and then is there more impact to come from that into fiscal 2014. I guess, meaning it won’t be fully ramped up in 2013 or I guess just help with the timing on that maybe?

Andrea, this is Ron Tanski, line in will be pretty much fully in service for all of 2013. However, Northern Access does ramp up a little bit and I’m trying to think if I've got those numbers here. I don't have them right at my fingertips, but most of that, there shouldn't be a whole lot of ramp up there with Northern Access. Once we get the compression in place that will be pretty set to go.

I think by 2014 it’s ramped up. Andrea Sharkey – Gabelli & Company: Okay, thanks guys. That’s really helpful.

Our next question comes from the line of Kevin Smith with Raymond James. Please proceed. Kevin A. Smith – Raymond James & Associates, Inc.: Hi, good morning gentlemen. Nice quarter.

Thanks. Kevin A. Smith – Raymond James & Associates, Inc.: Matt, is any Marcellus production still curtailed or is everything on line now?

No, we're curtailed about $25 million a day right now. Kevin A. Smith – Raymond James & Associates, Inc.: And what’s outlook for that?

It’s probably going to stay that way for at least another couple of months. The spot price on TGP 300 has been consistently below $2 and frankly we're just not in any rush to produce into that price. For the foreseeable future, at least most months we have 130 million a day of firm sales, so it's probably just made at production rate on TGP 300. Kevin A. Smith – Raymond James & Associates, Inc.: Okay, so we’re just waiting for, is there any I guess potential for any increase firm sales or is it just more of just you're max out the backside of it so you're waiting for pricing?

It’s difficult to increase firm sales at an index price that we're happy with. Kevin A. Smith – Raymond James & Associates, Inc.: Got you.

But for now, I would just assume the status quo and we'll see what happens with market. Kevin A. Smith – Raymond James & Associates, Inc.: Okay, fair enough. How much more expensive are the cluster spacing completions?

Good way to look at it is assume that an RCS will reduce cost for spacing well has twice as many stages and each of those stages costs 60% of what an ordinary well would, so let’s say, you had a 20 stage frac job, you turned into a 40 stage frac job, you will be adding about $1 million to the cost. Kevin A. Smith – Raymond James & Associates, Inc.: Okay, great. And then lastly any updates on the three wet gas Marcellus wells you are drilling in western Elk County. I think you’re supposed to start fracking them sometime right about now.

Actually Kevin, we haven’t drilled them yet. Kevin A. Smith – Raymond James & Associates, Inc.: Okay.

Its part of our slowdown; we’re not going to start drilling those wells till really probably the beginning of the next fiscal year roughly. Kevin A. Smith – Raymond James & Associates, Inc.: Got you, okay. That’s all I have. Thanks.

Our next question comes from the line of Mark Rogers with Soroban Capital. Please proceed Mark Rogers – Soroban Capital Partners LLC: Good morning guys

Good morning, Mark.

Good morning, Mark. Mark Rogers – Soroban Capital Partners LLC: So Dave, I just wanted to touch on the MLP question briefly, I know you are often asked the question and I think you typically say your open to it, but you kind of stop there, but with your close period, QT recently forming MLP and trading well and quite frankly the under performance of NFG versus the period of over last 18 months or so, I think equity is up 20% of that period and NFG is down about 25 over the same period, I wanted to see you could possibly put some tighter goal post around potential timing of the formation for MLP, particularly with midstream is top steady growth curve already for the company now.

Yeah, I think what we have said is not only, we have said that we are open to an MLP, but what we said, it’s largely going to be driven by the need for capital and as we look to all of these various projects that are coming down the pike and there are 10 or 11 that we’ve talked about. Obviously that will drive a significant need for capital in the future. And we’ve regarded an MLP and I think the equitable experience verifies that, that is a good financing vehicle. So through the expansion, looking for timing, we’re looking at a couple of years, but there are moving parts, I mean, we can use our balance sheet. So they are number of other options as well. But we do look to an MLP as a potential financing vehicle next year or so. Mark Rogers – Soroban Capital Partners LLC: And then…

Depending upon as the projects developed. Mark Rogers – Soroban Capital Partners LLC: Okay, it makes sense. And then just one follow-up on that and I realized that one school of thought obviously is that you wait until you have identified growth projects and it's a funding mechanism before forming an MLP, but is there also an argument that maybe the lack of MLP it might really be an impediment to you winning more business and deploying more capital in the Marcellus and Utica, both from the cost of capital and management focus perspective? You guys seem to have to really be in a pole position with your current assets and quite frankly it’s a little surprising you have been able to deploy more and more quickly, given the advantage you have with the pipe in the ground, so I'm just thinking out loud, but just wonder if MLP could potentially accelerate that both from a focus and cost of capital perspective?

Yeah, there is an argument for that, but at the end of the day, we've talked all that through and we will be driven by the need for capital. Mark Rogers – Soroban Capital Partners LLC: Okay, thanks.

Our next question comes from the line of Timm Schneider with Citigroup. Please proceed. Timm Schneider – Citigroup Global Markets: Hey, guys. So far all is well. Just a quick question on the gathering side, what’s your incremental gathering cost in the Marcellus on the new stuff you're hooking up and how does that, what portion of the LOE guidance that you gave in 2013 is a...

Well, what proportion of the – oh, okay. I think I understand your question. As we bring on Trout Run system our gathering costs are higher there. So, Covington is $0.32 range and Trout Run will be pushing 50. So it is higher… Timm Schneider – Citigroup Global Markets: But it is ulnar company.

It is ulnar company, right, we pay it to ourselves. In terms a portion of our total LOE it's, it's a quarter of it, roughly. Timm Schneider – Citigroup Global Markets: Got it. That was it…

Well, no I'm sorry. A little more than a quarter.

Our next question comes from the line of Mark Barnett with Morningstar. Please proceed. Mark Barnett – Morningstar Inc.: Hi, good morning.

Good morning, Mark. Mark Barnett – Morningstar Inc.: A couple of just quick questions around those, those Lycoming wells. Obviously, some pretty strong figures. Is there any, you know I know you updated your CapEx? But is there an increase in development of that area within your, your latest CapEx guidance.

No, it hasn't really changed. It's been the focus of our, our program in fiscal 2013 for sometime now. Mark Barnett – Morningstar Inc.: Okay, and maybe a little early to comment on this, but, how do the, kind of early decline rates look on those wells versus your experience in kind of your earlier Marcellus development?

And so, far very similar. But, but keep in mind, we've only had those wells on for, oh, two months. Mark Barnett – Morningstar Inc.: Okay, thanks for the color.

(Operator Instructions) Up next, we have Becca Followill with U.S. Capital Advisors, please proceed. Becca Followill – U.S. Capital Advisors LLC: Good morning, guys.

Hi, Becca.

Hi, Becca Becca Followill – U.S. Capital Advisors LLC: Can you talked about potentially increasing drilling if gas prices were higher, at what gas price would we start to see an increase in CapEx?

Well, we haven’t set a specific, $2 gas price will increase the number of rigs, but, we're looking at a range of gas prices get to, $3.80, 3.94 would be certain looking pretty higher to adding a rig. Becca Followill – U.S. Capital Advisors LLC: Okay, perfect, thank you. And then following the year two JV then not pursuing anymore, what is your new net acreage position in Marcellus, do you guys have that?

Yeah, Beck it may surprise you that it's not a, it's not a huge change in the overall acreage position. I think it’s an improvement in the quality, though. So in the initial joint venture EOG contributed a 140,000 gross acres. We contributed 200,000 gross acres. So, we get back a 100,000 net less what they’ve earned. They’ve earned roughly 17,000 of that, so get back 83,000 and we give up access to 70,000, so it’s a 13,000 net acre increase. However, a lot of the acreage that they have contributed was fairly scattered across the state. Some of which we probably would never have gotten to within the joint venture. So in that sense, I would say perspective net acreage is really gone up, more than 30. Becca Followill – U.S. Capital Advisors LLC: Okay. And then the write-down of reserves for the quarter because of the EOG and the weaker performance on the recent wells, can you quantify that.

You mean the break out between those two. Becca Followill – U.S. Capital Advisors LLC: Just how much the total life.

It was about 75 Bcf out of the joint venture is that right. Becca Followill – U.S. Capital Advisors LLC: 60.

60 at the joint venture. Becca Followill – U.S. Capital Advisors LLC: 60. Thanks. And then the last one on California, you talked about a well that was $400,000 well that was producing 50 barrels of oil per day. And just what information, and do you know, how many incremental locations you might have or what kind of returns as well as generate?

It’s in the [Michigan], its at North Lost Hills, we have a follow-up, that we’re going to drill in fiscal 2013 and the running room is relatively small. So they’re, they’re note going to be a lot of those wells. Becca Followill – U.S. Capital Advisors LLC: So it’s not a move on.

No. Becca Followill – U.S. Capital Advisors LLC: Okay, great. Thank you guys.

Yep.

Our next question comes from the line of Carl Kirst with BMO Capital Markets. Please proceed. Carl Kirst – BMO Capital Markets: All my questions have been hit. Thanks.

Ladies and gentlemen, since there are no further questions in queue, I’d now like to turn the call over to Mr. Silverstein for closing remarks.

Thank you, Jeff. 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 p.m. Eastern time on both our website and by telephone, and will run through the close of business on Friday, August 10, 2012. To access the replay online or to find additional information visit our Investor Relations website at investor.nationalfuelgas.com and to access by telephone, call 1-888-286-8010 and enter pass code 85783979. This concludes our conference call for today. Thank you and goodbye.

Ladies and Gentlemen, that concludes today’s call. Thank you for your participation. You may now disconnect. Have a wonderful day.