Good day, ladies and gentlemen, and welcome to the first quarter 2012 National Fuel Gas Company earnings conference call. My name is Fab, and I will be your operator for today. At this time all participants are in a 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.

Thank you, Deb, 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. National Fuel has had a number of very good quarters in a row, and the first quarter of fiscal 2012 was no exception. Indeed, given the headwinds created by the extremely warm winter and significantly lower gas prices, the quarter was exceptional and clearly demonstrates the value of owning diverse assets. Overall, earnings were up 4% or $0.03 per share quarter-over-quarter. The increase was largely due to a $15 per barrel increase in realized crude oil price and a 17% increase in Seneca’s production, an increase that I should note was achieved despite the sale of our offshore Gulf of Mexico properties in fiscal 2011. Excluding the impact to that sale, Seneca’s production was up 40%. Earnings in the regulated businesses which are not particularly commodity price sensitive remain steady and were consistent with our expectations. In the utility, particularly in Pennsylvania and our Pennsylvania division, earnings were off because of warmer weather. But that was offset by growth in our pipeline and storage segment whereas expected, our recent expansion projects contributed to a $0.03 per share growth in earnings. As we placed additional expansion projects and service, pipeline and storage segments earnings will continue to grow. So, generally and overall, we’re pleased with our consolidated earnings for the quarter. Despite the significant headwinds that I mentioned earlier, earnings of $0.73 per share were virtually spot on our own internal forecast. While we can’t control the weather and gas prices, we can and do control our operations. And in that front, we had an excellent quarter. In the Marcellus, Seneca’s production continues to grow at a rapid pace, nearly doubling quarter-over-quarter. And Seneca was also active in continuing to delineate our acreage with respect to the Utica Shale. Assessing the prospectivity of…

Thanks, Dave, and good morning, everyone. Technically, we’re in the middle of our heating season in Western New York and Northwestern Pennsylvania. However, the temperatures during the first quarter were about 20% warmer than last year in both of our New York and Pennsylvania service territories. As a result, we saw our utility throughput for the quarter decrease by 3.4 Bcf year-over-year. Pipeline and storage throughput was also down almost 5 Bcf year-over-year as a result of the warmer weather. That warmer weather combined with a ready availability of billions of cubic feet of new natural gas supplies across the US, resulting from the success of hydraulic fracturing in shale gas fields, has substantially lowered and dampened the volatility of natural gas prices. The average delivered gas price for our utility customers for the heating season in New York is projected be approximately 2% lower than prices last year, and about leveled in Pennsylvania. Yesterday, the forward 12-month strip price for natural gas closed at roughly $3.08 per MMBtu on the NYMEX. And while those lowered gas prices post some near-term challenges for our exploration and production operations, we believe that long live gas reserves at stable gas prices are great for our customers and create long-term opportunities for all of our business units. While we already have most all of the space heating load in our service territory, we’ve seen more and more interests in natural gas vehicles for fleet that could boast our utility load. Longer-term, we expect further replacements of coal-fired electric plants with gas-fired electric generation that will be seeking capacity from our pipeline and storage segment, and our marketing company. And finally, as the demand increases for these new uses, we expect to see a leveling of commodity prices that will allow our exploration and…

Thanks, Ron. Good morning, everyone. For the first quarter, Seneca produced 18.2 Bcfe, a 17% increase of last year’s first quarter. Considering that we sold our Gulf of Mexico properties last spring, a more relevant comparison is production growth from our East and West divisions, which are up a combined 40% versus last year’s first quarter. I’m particularly pleased with our increasing oil production in California. Our Midway-Sunset properties are up over 500 barrels of oil per day due to improved steaming efficiency and new wells coming on line. Next quarter, I expect to see an impact from our new wells at Sesby [ph]. And for the fiscal year, I expect our West division production to be up about 3% versus fiscal 2011, with oil production, in particular, up about 5%. In the East division, our Marcellus production was up about as is expected, well, up 12% versus the previous quarter and 91% versus the first quarter of 2011. We expect a substantial jump in March as we bring on new production from Tract 595 in Tioga County and another jump in April as we bring on our first pad at Tract 100 in Lycoming County that will flow on the Trout Run gathering system. This new production will have only a modest impact on second quarter volumes, but will increase our fiscal third quarter substantially. At Boone Mountain, in southern Elk County, we have tested two new Marcellus horizontal wells at rates of 3.8 million cubic feet per day and 4.2 million cubic feet per day. One additional well will be coming on next week. Later this quarter, we will be testing a well in our Rich Valley area in Cameron County, which will wrap up our current delineation program. At that point, we will have drilled, frac and…

Thank you, Matt, and good morning, everyone. Overall, our results for the quarter were fairly straightforward. Dave already hit on the main drivers of earnings and all of the specific details were covered in last night’s release. So I won’t repeat them all here. I would, however, like to emphasize a point that Dave made earlier. Our $0.73 of earnings, while somewhat lower than the Street’s consensus, were right in line with our internal forecast. Looking at a few of the Street’s models, it appears that some of you are using assumptions that aren’t entirely consistent with the guidance we communicated for our regulated segments. And I’d encourage you to talk with Tim to sort out any differences. Turning to our earnings guidance for 2012, as you read in last night’s release, we lowered our earnings expectations to a range of $2.40 to $2.65 per share. The change in our guidance is mostly attributable to our updated commodity pricing assumptions. The new earnings forecast assumes flat NYMEX commodity pricing for the remainder of fiscal 2012 of $3 for gas, which is a $1.50 from our prior forecast, and $100 for crude oil, which is a $5 per barrel increase. We also revised the pricing basis assumptions for our Marcellus production to reflect current market conditions. Our new guidance assumes Dominion index that have used to price the bulk of our Marcellus production is flat to slightly negative to Henry Hub. Our previous forecast assumed that Dominion traded at a slight premium to NYMEX. We also adjusted our realized prices to reflect both firm sales contracts that have been put in place in current basis estimates for any forecast production that is not linked to an existing firm sales contract. Again, these changes to our pricing assumptions accounted for substantially all…

(Operator Instructions) And your first question will come from the line of Andrea Sharkey of Gabelli & Company.

Hi. Good morning.

Hi, Andrea.

So, one question. I was wondering if you could help me out with the CapEx. It looks like you’ve mentioned the midpoint is dropping $70 million on Seneca and it looks you’re pulling back your well drilling at the midpoint of the range, around 35, 40 wells. And so, just based on the estimate of $5 million per well, that got me to a $200 million drop in CapEx. So I’m just wondering if you could help understand what am I missing there. And why didn’t CapEx go down by $200 million instead of $70 million?

There are a lot of moving parts there, Andrea. First of all, the well count we provide is the well spud during the particular fiscal year. So capital spending is, the cost of a well covers the entire gamut from drilling to the top hold and drilling the lateral to completing the wells. But probably the biggest factor is, we’ve moved from drilling shallower, shorter lateral wells in our Western acreage to drilling deep long lateral Utica wells and deep long lateral Marcellus in our Eastern acreage. So they tend to take longer and are more expensive.

Okay, that makes sense. And then, I guess maybe thinking about the wells that you’re not going to drill this year, will that have a great impact on your 2013 production guidance or not really?

It will certainly have a greater impact on ’13 than it does on ’12. But we still, as I mentioned in the comments, even if we were to stay at this four-rig program, we would still expect a fairly healthy production increase in fiscal ’13.

Okay, sure. That makes sense. And then one last question and then I’ll let somebody else have a chance. Did you have to drop any contracted frac crudes since you dropped one rig? Or are you okay with the frac crudes that you have? Matt Cabell We only have one frac crude contracted full time and the four-rig program is about right to keep that frac crude busy and meet our contractual obligation.

Okay, great. Thanks a lot.

Your next question will come from the line of Kevin Smith with Raymond James.

Hi. Good morning, gentlemen.

Good morning.

Hey, Kevin.

Would you mind in giving me an update on the status of Tract Run gathering system and the completions activities there. I believe you’re previously targeting the start completion activities in January and February. But I guess based off Matt comments, that seems a little bit delayed. But maybe I’m looking at that incorrectly.

No, it was a little bit delayed, Kevin. There was a teamster strike that affected us for a little bit there. That’s since been resolved and the drilling was going maybe just a little bit slower and that could have slowed down kind of in response to the delayed completion of Trout Run. So we’re coordinating so that we’re getting them both done together, and it looks like late March.

Okay, then late March is when Trout Run will be completed?

Completed and the first well pad and DCNR Tract 100 tied in and flowing.

Oh, okay, got you. All right, so that’s being done on a phase [ph]. So it does – you’re not waiting on Trout Run to be completed before you start completion activities.

Well, I mean, they’re going on now as we speak, but again, you know, we would – got to get a whole well – or I’m sorry – a whole well pad done. And so that just takes some time.

Got you. So when we – for the Trout, was it 100 or Tract 100, when are we expecting initial production from that? Is that end of March or more April-ish.

End of March, early April.

Okay, great. And then switching gears, any updates on the Utica Shale test and Venango County or in Elk County?

Well, I guess, one thing that I think we’ve announced previously is that the well in the Mt. Jewett area which is kind of at the Elk and the Kane border, the vertical well there, we announced, that that is dry gas, good quality dry gas, pipeline quality dry gas. The vertical well in our Henderson area that’s kind of at the Venango, Mercer [ph] boarder, we don’t intend to discuss the makeup of that gas. We don’t intend to disclose that in the near future.

Okay. So we won’t know for awhile whether there’s any liquids components to it, is that fair?

That’s fair.

Okay. And then, one other question. Did you guys ever get fix rigs or would just – did you go to five and just drop down to four?

We were at six briefly. Our plans, our original plans had us – had us going to six rigs kind of about this time frame.

Got you.

We’re now on the process of dropping two rigs.

Fair enough. All right. Thank you very much.

Your next question will come from the line of Craig Shere with Tuohy Brothers.

Hi, thanks for the call. A couple of questions. First, Matt, if that Henderson well in northwest there turns out attractive though it may take a little while for us to hear the results, just how much are you all willing or interested in growing the acreage position out there before we start to see big rig deployment? And then I got a couple of other questions.

Yeah, well, obviously, it doesn't depend on the well results, but I think you could probably read between the lines and see that, you know, there’s a reason why we don’t want to disclose anything about that well right away. It is a very competitive area for leasing. And, yes, in fact, we would consider adding to that lease position in that area.

Can you at least put some color on the contiguous nature of your existing acreage there and the need for fill ins and what you might consider a critical mass for a good play?

Sure, I mean, and I think we actually have enough there for some degree of critical mass already. We got something in the order of 15,000 acreage in that area. There are some gaps in there and joining leases that we want to pick up. And, I guess, that’s about all.

Okay, and I think your long-term frac contract ends this year. So could you put a little more color around your flexibility heading into fiscal 2013 to ramp up CapEx if Utica plays out and/or gas recovers in price or ramp down more if neither of those two things happen?

Yeah, the frac contract expires in – oh, it’s about April of 2013. So we’ll have that frac crew working most of the next fiscal year even without extending it. It would be quite easy, and – today, it would be fairly easy to add additional rigs. We could probably pick up the same rigs we’re dropping if we wanted to. But, obviously, that’s in today’s environment if gas prices recover rapidly, there will be some demand for additional rigs and I can see that becoming more competitive. All of that said, I can’t imagine that we’d ever be looking at a delay of more than about six months to add a rig. And I think we could probably, if we wanted to, we could probably get a second frac crew as well. To decrease activity, we have four rigs contracted long term. The first of those four rigs – the first exploration on this long-term contract in those four rigs is July of 2014. Obviously, we can – if we really felt the need to, we could reduce activity and still hold on to that rig. The contract is that onerous. And the second thing on the slowing down activity, as I mentioned, we have the right in the EOG joint venture to not participate in wells and just – just to maintain our 20% royalty interest on our – the acreage. So that’s another lever we can pull if we find the necessity to in a lower gas price environment.

And that’s – that’s like a $200 million line item there.

Okay, I was going to ask about that. Great. And the very last question, I appreciate all this color, is, can you discuss, if we do get an industry ethane solution, and ethane is priced, I mean, let’s just call it 50% above methane, could you talk – even though it’s a little less pressure and lower EUR in southwest, could you talk about the potential economic uplift there?

Yeah, as I mentioned it with the ethane rejection mode, we get $0.80 to $0.90 in Mcfe uplift. In a deep cut where we actually recover the ethane as well, obviously, we would have greater revenue increase. And I’m sorry I don’t have a specific figure for you off the top of my head, but the short answer is, a deep cut with ethane recovery would substantially improve those economics of processing the wet gas.

And am I remembering correct that system wise you’re about 6% or 7% ethane left in the system but that it’s a higher percentage as you move to that western area you were talking about?

Well, the further west you go the more liquids you have. I mean, it’s fairly simple, the BTU content is higher for the west as you go ahead. But the Marcellus is less mature and therefore in a – more of an oil window and less the gas window. I’m not sure they have a specific ethane percentage for you without talking about the specific location.

Understood. I appreciate all the color. Thank you.

Your next question will come from the line of Carl Kirst with BMO Capital Markets.

Thanks, good morning, everybody. Actually, my questions were all hit. But, Matt, I’m not sure if I got my notes down fast enough. Could you go over the cryogenic one more time as far as where you guys were looking at that and the potential timing?

Yeah, if you think about the area where we drilled Owl’s Nest wells in the past – so you can see that on the maps that we put out, this would be kind of just west of that location. So it’s kind of western Elk County and into Forest Country. And we’ve got at Owl’s Nest and sort of along that same – on trend to that part of Owl’s Nest, we would have hundreds of oil location that would fall into that window. What was the other part that you asked me?

Oh, just, David, because I assume this is you guys would be doing it. And so just – did you mention – I’m not sure if I just didn’t get a chance to write it down, did you mention timing and potential investment dollars?

All I said was – we’re looking at this as a possibility for 2013 and 2014.

Okay.

And I would say, potentially, as early as, you know, fairly early in fiscal ’13, potentially. It’s something we’re still evaluating.

A $150 million a day kind of facility or (inaudible).

That’s part of what we’re evaluating.

Got you.

Well, the trade-off there is – the bigger the facility you put in, the longer you have to wait to get enough momentum, enough wells coming into the plant to run it. So there’s kind of a trade-off there between the smaller plant and the larger plant.

Fair enough. And maybe just one other kind of tweaking question from the regulatory side on the pipelines with Line N and Tioga. You know, with the $24 million of revenue sort of being allocated to fiscal 2012, is that something where as – we’ve got Line N now almost fully ramped but Tioga we’re still waiting for producer tie-ins – is that something where the vast majority of that happens in the second half of the fiscal or should we be seeing that kind of allocated ratably here in the last three quarters?

It will come – well, all across the three quarters, Carl.

Okay. Great. Thanks, guys.

Welcome.

Your next question will come from the line of Timm Schneider with Citigroup.

Hey, guys, how’s it going?

Hey, Timm.

Good.

Hey, a quick question. On the new basis assumptions you guys put out there, can you maybe just talk about what’s driving that and what you’re seeing with respect to pipeline constraints and what contracts you have in place over a longer term firm?

Yeah, as you’re probably aware TGP 300 is one of the most utilized pipelines for delivering Marcellus gas to the east coast. And consequently, that basis differential has fallen. At this point, we have firm sales anywhere from just slightly lower than Dominion – South Point to Bay 3010s [ph] below Dominion – South Point. And then, meanwhile, Dominion – South Point is now trading about flat to NYMEX where as it had been at a premium. Did that – did that answer your – oh, you want to know how much we have (inaudible).

Yeah.

Well, we have firm sales on TGP 300, I think, April, we’re up to about 130 million a day.

That’s right. Yeah.

Okay, got it. Thank you.

Your next question will come from the line of John Abbott with Pritchard Capital Partners.

Hey, thank you for taking my call there. Just to – maybe I missed a few here, but this well pads you’re bringing up – you’re going to be bringing on, how many wells are on each of those pads? And then, second, what are your latest thoughts about DOGGR in California, the new administration?

The pads at 595 – there are two pads that we’re going to bring on at 595. One is a six-well pad; one is a three-well pad, and then track one under. It’s a four-well pad that we’re bringing on. I’m not sure that I have any comments on the second question in California.

All right.

Your next question will come from the line of Mark Barnett with Morningstar.

Hey, good morning.

Hey, Mark.

Good morning.

So you’d mentioned that the west to east pipe was going to be a little bit delayed and potentially done in a series of smaller projects. You initially estimated that that could be like a $280 million to $300 million project. If it does end up going forward with some smaller projects, do you have kind of an idea of what kind of spend you’d see there or is it too early?

It’s a little bit too early at this point, Mark, because one of the things that will drive where we go with various sections of that pipe is what’s going on in the market generally and where Seneca is doing all its drilling. So it really is a little bit too early at this point. But the concept would be to get these sections in place that we can get that flowing gas into an interstate market. So I – it’s just too hard to pinpoint at this point.

Yeah, and I think the important thing to recognize is that we won’t – we won’t build that pipe or sections of that pipe without having it contracted for. So we just don’t do it on speculations with – we’d have to have signed contracts before we start putting that in.

Okay. I guess, just regarding any of the smaller plan projects with the curtailments and whatnot and with your own ramp down, are there any other projects that are potentially looking at kind of a delayed timeframe or...

No, no, Northern Access is full go. We’ve got the Line N extension. We’re adding more compression capacity on Line N to be able to take in more production from range resources. And, again, we’ve gotten more, I guess, we’re surprised that the further Tioga County Extension that people are ramping up their interest there – or central Tioga County Extensions. So, no, we don’t see any slowdown in what we’ve talked about before.

Okay, I think – and just a last quick question, maybe, a sort of, a more general question. With gas prices where they’re at, have you thought about your hedging strategy in this and maybe that’s going to be any different this year or is it kind of a little – is that not really going to change?

Yeah, I think our general hedging strategy will stay the same where we’ll take advantage of the Contango shape of the curve and layer new trades throughout the course of the fiscal year. What I think may be different is that given where prices are, we may be towards the lower end of our range of hedge percentages. If you go to our IR deck, we have a graph in there that show sort of where we generally like to be at different points in the fiscal year. And we may be towards the low end of that range.

Great. Appreciate the detail. Thanks, guys.

Okay.

Your next question is a follow up from the line of Timm with Citigroup.

Hey, guys, just real quick, because I was rushing through my notes here, I just want to make sure I got this right. Did you say, with respect to Owl’s Nest and liquids, did you say that you think all of the 90,000 acres are perspective for liquids or it that just a location of where you’ll have the cryo plant potentially?

It’s not all 90,000 acres, no, it would be more the western portion of that, but then, it’s not just Owl’s Nest, we could – you can kind of move and – a long trend to that same area at Owl’s Nest and they’re – we’ve got quite a bit of acreages that falls into that window.

All right. So as I look at your map here, recent presentation, page 19, the stuff you have in Mercer, that’s the 15,000 acres, correct? That’s the Henderson area?

Right.

Okay, got it. All right. Thank you.

And there are no further questions. I would now like to turn the call back over to Mr. Tim Silverstein for closing comments.

Thank you, Deb [ph]. We’d like to thank everyone for taking the time to be with us today. A replay of this call will be available in approximately 2:00 pm Eastern Time on both our website and by telephone. And we’ll run through the close of business on Friday, February 10, 2012. 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 pass code 562-172-87. This concludes our conference call for today. Thank you and goodbye.

Thank you very much. This concludes today’s conference. Thank you for your participation. You may now disconnect. Have a great day.