Good day, ladies and gentlemen, and welcome to the second 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. As you read in last night's release, National Fuel's earnings for second quarter were $0.81 per share. Excluding the $0.08 per share charge related to the new Marcellus impact fee on Pennsylvania most of which relates to Marcellus wells drilled in prior quarters, operating results for the quarter were $0.89 per share, which is $0.11 less than last year's second quarter. This drop was largely due to three factors. First; the winter of 2011 and 2012 was unseasonably warm. In fact it was the warmest on record on our service territories. The mild weather impact the earnings by $0.05 per share in the Pennsylvania service territory of our utility and was the significant contributor to the $0.03 per share drop in earnings at National Fuel Resources, our non-regulated energy market subsidiary. Second; and as you all know, natural gas prices continue to decline throughout the second quarter. While our hedging program did help, our actually realized natural gas price still decreased by $0.68 per Mcf quarter over quarter. That decrease in the sale of our offshore Gulf of Mexico properties last April which is the third factor was the largest contributor to the $0.05 per share drop in operating results at Seneca. Of the three, only the sale of the Gulf, which incidentally we believe was the right decision, was within our control. Since we can't control gas prices much less the weather, we focused on managing our businesses and put particular emphasis on controlling our budgets. We also continue to execute on our plans to grow our Midstream assets all with a view to maintaining our strong balance sheet in creating long-term shareholder value. In the Pipeline and Storage segment, our ongoing expansion efforts are progressing according to plan. Construction has actually commenced…

Thank you Dave and good morning everyone. As a result of the warmer weather, we expected and saw a decrease in our year-over-year throughput in our utility segment and in the legacy contracts and our pipeline and storage segment. Simply stated, because of the space heating needs were lower in our all utility service territory and in the service territories above the utilities that ships gas to our interstate pipeline system, related throughput was lower. Offsetting those decreases from our traditional utility customers, we saw an increase in throughput from shippers, moving gas out of the Marcellus production areas through our system and off the East Coast and New England markets. In addition, because of the lower price of natural gas, besides gas-fired electric co-generation plant near (inaudible) was running quite a bit during the quarter and we saw increased throughput in our Empire pipeline as a result. When the producers get all their gathering lines tied into the Tioga County extension, we should see a very slight increase in throughput on the Empire pipeline system and will only be slight because the producers have temporarily released our capacity to replacement shippers who actually use the capacity during the quarter. With respect to field operations, the mild winter weather allowed our construction and maintenance crews to work pretty steadily on all of our maintenance and system upgrade products and we are right on target with our capital spending for our ongoing pipeline integrity field board. We are also moving along with our spending on a couple of near-term, new infrastructure projects. Supply Corporation, we begun construction of a compressor station for our Northern Access project and we expect to have all the metering changes and other bits and pieces of that project complete this November so that we can provide…

Thanks Ron. Good morning everyone. East division production was 13.3 Bcfe, up 22% while West production was 5.1 Bcfe, up 9%. Overall production was 18.4 Bcfe, up only slightly due to sale of Gulf of Mexico assets last year. Focusing on California first, we are continuing to grow production with significant increases at both South Midway-Sunset and at Sespe. We plan to drill a total of 23 new wells at South Midway-Sunset this year. Recent drilling has extended the size of the two primary envelopes and reservoirs and allowed us to increase production from about 700 barrels of oil per day last year to 1050 barrels of oil per day now. At Sespe four wells were drilled in fiscal 2011 that are producing at a combined rate of about 300 BOE per day. We have six wells planned for this year including two more five acre infield wells, two cold water formation wells and two wells on our new Oak Flat lease. Also in California, our non-operated Monterey well at the Belridge field is producing about 50 barrels of oil per day. Three to four delineation wells are planned there including at least one horizontal. But we only have a 12.5% interest if the delineation drilling is successful there could be hundreds of additional locations. In Pennsylvania, we continue to develop our Eastern Marcellus acreage in Tioga and Lycoming Counties. Our combined Covington and Tract 595 wells in Tioga County are capable of about 140 million cubic feet per day. But we are currently curtailing production to about 130 million cubic feet per day for which we have firm sales contracts. In Lycoming County, the Tract Run gathering system is fully installed and our first four well pad has been fracked. We are currently drilling out plugs and running production…

Thank you, Matt and good morning everyone. Overall, our operating results for the quarter were lower than last year had a number of bright spots. In the utility, if you put aside the effect of unseasonably warm winter, earnings in that segment were actually ahead of forecast due to lower than anticipated O&M expenses. In the pipeline and storage segment, this was the first quarter to reflect the full year impact of the Tioga extension and Line N expansion projects to replace and service last fall. For the quarter, the two projects added $7.8 million in revenues. At Seneca, operating results fell short of our previous projections mostly because of lower natural gas prices, but production growth and strong oil prices led to improved results from our California properties which mitigated some of this impact. All of the specific drivers of the quarter’s results are covered in last night’s release, so I won't repeat them all here. However, I would like to expand on Seneca’s per unit operating expenses for the quarter which were a little higher than we anticipated, but which we expect to trend downward over the remainder of the fiscal year. On a sequential basis, Seneca’s $1.14 per Mcfe LOE expense for the quarter was higher than the $1.02 rate for the quarter ended December 31, 2011. Most of that increase is attributable to higher LOE on our non-operate joint venture wells including an out of period adjustment from EOG that by itself increased our LOE rate for the quarter by $0.04 per Mcfe. We've updated our forecast and expect our LOE rate for the last six months of the year will be in the range of $0.95 to $1.10. Seneca’s DD&A rate for the quarter was $2.30, up $0.03 per Mcfe for the quarter ended December…

Thank you (Operator Instructions). Our first question comes from the line of Andrea Sharkey - Gabelli & Company. Please proceed. Andrea Sharkey - Gabelli & Company: I was wondering if you could us some more guidance towards 2013 on California, you guys have done a great job increasing that oil production. I think it's up about 10% so far at the first half of this year. You seem to be ramping up more drilling. Can we expect a similar type of growth rate, you know 2013 and beyond or is there a level where you sort of tap out on the California area?

You know we haven’t given any guidance yet for specific by division for fiscal 2013, but we will spending a bit more in 2013 in California than we did this year in 2012. So I think we would anticipate some growth in production between and 2012 and 2013 but I don’t think we are really prepared to quantify that yet, Andrea. Andrea Sharkey - Gabelli & Company: Okay, that’s fair enough. And then I guess the next question would be I think you guys have about $250 million in debt that's maturing in 2013 and you might be a little bit have a short follow on your capital spending this year. So I guess how do you plan to address that, will that just be new debt equity, what are you thinking there and then also looking at 2013, do you plan to sort of stay within cash flow there?

In terms of the 250 million, at this point I think we plan on refinancing that with another long-term debt issuance. I wouldn't see us needing to issue equity that's not in the plans. And then in terms of fiscal 2013 spending versus cash flows, we haven't initiated guidance yet. But I think it's safe to say that we will be much, much closer to living within cash flows. Andrea Sharkey - Gabelli & Company: And then just last question for me and I will give somebody else the chance. You guys have significant hidden value in all of your assets and there's a lot of options out there for you to service that value. For example we've talked about before monetizing the pipeline by maybe an MLP structure, I guess where are you guys on evaluating any of that potential financial engineering options?

I think at this point Andrea we are fairly comfortable with where we are. Certainly as we move forward and look to devote more capital to the Pipeline and Storage segment, in the Midstream segment and we have a higher tax basis assets there, we would be looking much more toward an MLP at that point. I think right now we have some room to lever up a little bit, a couple of 100 more million dollars and certainly that's very active in our thoughts and considerations as we move forward.

Our next question comes from the line of Holly Stewart with Howard Weil. Please proceed.

I guess just a couple of follow-ups, remind us Matt on the limitations in California because I think obviously as you look out to the macro environment right now. People think great cash flows in California so why wouldn't you be going faster so can you just remind us of the limitations out there?

Well, let’s think about our two biggest growth areas which would be South Midway Sunset and Sespe. At South Midway Sunset, we’re extending reservoirs as we drill those wells. Really if you try to get it heavier yourself you might out drill the limit of the reservoirs. So you need to -- each well is depended on the previous one and at Sespe, the primary source area at Sespe is the five acre in field program. We really want to get some production history before we determine how aggressive we want to get on that program. We’ve got a little bit of production history from the 2011 drilling. We will get some production some further history from those wells plus some from our 2012 drilling that we may be able to accelerate it a little in fiscal ‘14. But there is some limit even if we felt like it was something we want to get more aggressive on there are some limitations too how much we drill at Sespe. We have a limited drilling window. It’s a fairly environmentally sensitive area. So there would still be some other space on that.

And two rigs running right now?

In California? No, one rig in California right now.

One rig, okay. And then kind of I switch to the Marcellus, talk about the decision to drop the rig, I guess more specifically was there a financial impact of that decision? Under rig contracts and services?

We fully expect that we will be able to have that rig placed in another basin and that our cost will be minimal. We do have an obligation on the rig that would be on the order of $6.5 million a year or a non-placed.

Another basin?

Yeah, not for us.

And then just a remainder on I think, Dave said now looking for a 25% growth rate in 2013 in the Marcellus. What was the previous announced growth rate there?

Yeah, with 35% to 40%, I think previously.

Our next question comes from the line of Carl Kirst with BMO Capital.

It’s actually [Denivo]. There was mention of the Niagara capacity turn backs in the pipelines and those turn backs offsetting revenues from the expansion projects. I am just curious if this is something incremental to what we've sort of been talking about already.

[Denivo] You are kind of breaking up there, do you repeat that?

Yes there was a mention of Niagara capacity turn backs. I am just curious if this was something that was incremental to what we have already been talking about.

No, I mean those were kind of all planned and as we move forward by the end of this year when we get the Northern Access project in place that's all pretty much going to be offset by gas flows going the other way.

And finally on the utility, can you please tell us what the pretax dollar impacts from that was for the quarter?

I'm pretty sure it was $0.05.

Okay.

It’s in the back of press release.

The $0.05 is after-tax, right?

I am sorry that's after tax. I don't have that number here.

(Inaudible) pretax number.

I’ll get you back on you on that.

Our next question comes from the line of Tim Schneider with Citigroup. Please proceed.

First question how many more wells are you guys planning to drill at Owl’s Nest this year.

Let's say we've got two more Owl’s Nest wells planned in the coming months. They won't necessarily fall in this fiscal year. If I had to guess I would say one would be this fiscal year, one would be next fiscal year just because the rig will be there at the time that overlaps the end of our fiscal.

And if possible can we get an update on the Henderson well, are you guys still doing the data on that.

We are still keeping that one tight for now.

Okay, with respect to the down spacing at Sespe, what could the incremental locations be there if it’s in fact towards?

I am going to put a range on it and say 20 to 50.

Our next question comes from the line of Chris (inaudible) with UBS. Please proceed.

Just a quick question, Matt when you were talking about curtailments in the east due to takeaway and limitations, do you think, I mean I guess remind me how long will that be in place, how long are you going to be curtailed there?

Well, that's a function of pricing, so if we've got to the point where our spot pricing at TGP 300 was in excess of $2.30, we would probably stop curtailing there.

Okay that's just discounting to get in to outline essentially?

Yes.

Okay, and then Dave switching gears a little bit, when you spoke about the impact of the impact fee, 2 million I think, it was what you said and at the back two quarters in the year. Is that, might think about in addition to what we sort of saw in the run rate in 1Q? So, I mean you guys had sort of tax line if you will in AMP of like 2.5 million in the first quarter. So I might think about the third quarter as being somewhere around 4.5 and incremental to what you had.

Well, we have some franchisee and of Lawrence Gas in California. It would be in addition to the impact fee.

Right. So you were talking only about the impact.

Right. So that 2 million, if you were to go back to last years third quarter, that’s what you are trying to do. That 2 million would be incremental to whatever that previous rate in that.

Okay. Got it. And then I appreciate the color on your hedging strategy change. I saw incidentally it wasn’t employed on the oil side. Obviously, we have backward day curve there. So is this more of and if I thought about your hedging profile in the past or hedging behave in the past, it was around cash flow protection and making sure you guys could forecast the quarter. Now it looks to me more of a, I don’t want to say commodity that but it maybe your viewpoint that you know that can (inaudible) on the natural gas curves, make it such that you guys can make attractive returns. So you just opt to lock it in. Is that the way I think about what you are doing there?

Yeah, I think that’s right. Where if you look at the upward slope, we would hedge it on an average price of around $4 Mcf. We can lock in a pretty good return at that level, given the downside on commodity prices. Thought that was the right thing to do.

Now there has been some questions right I think of that, the out years of the curve, how liquid is, and why not you guys are starting small, can you talk about adding a little bit on as time sort of progress, but any issue with regard to that as you’ve seen it?

Yeah, we’ve heard the same things from our counterparties where at times the big producers may have been doing some good size trade that’s upped the liquidity. But we are patient unlike the levels that we’ve got.

Our next question comes from the line of Craig Shere with Tuohy Brothers. Please proceed.

May I a couple quick questions on the EOG JV participation; I thought that was running maybe a 150 a year, is that right and do you have a rough portion of that that you might choose not to participate for fiscal ‘13 and would any of that effect the second half of this year?

It’s important to understand when you think about the our participation in a well that’s spud today that a whole lot of a cost, let me rephrase that. If you look at 2013 a lot of whole what we’ll spend on the EOG program, is completion of wells that are already drilled or they are being drilled as we speak. So even if we non-participated in very time the impact to 2013 is probably only in order of about $50 million.

I got you.

Now, if we continue to non-participate, it would have a, you are probably right probably gets to be more like $150 million overtime.

And then on the Sespe questions; you are talking about the down spacing, but didn’t you have a deeper delineation well you are working that’s kind of separate from that?

Yes.

And what’s the progress of that.

We haven’t drilled yet.

When will that be done?

It will be in fiscal ’13.

Okay, any idea how…

It will be in fiscal ’12.

So you’ll have results report by the year end for the fiscal year?

I wouldn’t count on having production results in ’12, no; probably more likely be ’13 by the time we’ve completed it.

And Dave, you are talking about at the lower commodities drop about – the competitiveness of Midstream expansion, serving third party producers versus CapEx to E&P; that makes a lot of sense, but could you put some additional color maybe around just how much the Midstream could grow overtime?

I think in large part, we have a number of projects that now on the drawing board let’s say over the next three years we have probably about $400 million right now. Now the likelihood is that won’t all happen and many of those coming from our actual Midstream subsidiary, the unregulated side are devoted to Seneca. But I could see a scenario working with other producers particularly expanding Trout Run, expanding Covington and working with other producers, I could spending an incremental $200 million there lets say over the next two or three years. But there is a lot of moving parts to it; so it will depend on how many of those projects for example we presently on the joint board we do a little spend on our ability to work those relationships that I talked about, but certainly, we think those are very, very good projects and a great opportunity for us to grow.

If I may dovetailed out with the question about the MLP status, do you think if we fast forward say 24 months and you've got an extra couple of $100 million of midstream CapEx well on its way that you are getting close to the point of critical mass to think about improving your cost of capital and some of the parts multiple with an MLP?

Yeah, absolutely.

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

Just I have one and maybe two, first are you going to be able to produce everything on a Tract 100 at capacity, where do you stand I guess with firm capacity out of there?

We have about 30 million a day of firm sales, now close to 50 million in November. I would say there is a pretty big, pretty high likelihood that we will be above that from sales level. So spot market is okay there right now and the reason why we can't produce above our firm sales, I mean also we are looking at potentially locking in additional.

Sorry I think I lost you, you said you are looking at an additional firm capacity?

Yeah, I wouldn’t think of it as a firm capacity, more as firm sales, but yes we are looking at additional firm sales.

And then lastly, when do you think you are going to be able to talk about Utica well results and what that play mean for you, do you guys have a targeted year from now or six months from now or what's your timetable on thinking on that?

Maybe a way to look at it Kevin as we’ll have to wells drilled and fracked by the end of this fiscal year and we may have some test results from sometime in the fall. So I would say, if what you are trying to think about is when are we going to be talking about how significant this potential is to us and what does it mean for our capital spending going forward at target sometime in the fall.

Is anybody else drilling – do have any competitors are drilling around that acreage?

We only permitted wells around that acreage.

Ladies and gentlemen that concludes the Q&A portion of our call. I would now like to turn the presentation over to Mr. Tim Silverstein for closing remarks.

Thank you, Jeff. We would like to thank everyone for taking the time to be with us today. A replay of this call will be available at approximately 2 PM Eastern Time on both our website and by telephone. And we’ll run through the close of business on Friday, May 11, 2012. To access the replay online visit our Investor Relations website at investor.nationalfuelgas.com and to access by telephone call 1888-286-8010 and enter pass code 11631131. This concludes our conference call for today. Thank you and good bye.

Ladies and gentlemen that concludes the call. Thank you for participation. You may now disconnect. Have a wonderful day.