Good day ladies and gentlemen, and welcome to the fourth quarter 2009 National Fuel Gas Company earnings conference call. My name is Tom and I’ll be your coordinator for today. At this time, all participants are in listen-only mode. We will be facilitating a question-and-answer session towards the end of this conference. (Operator Instructions). I would now like to turn the presentation over to Jim Welch, Director of Investor Relations. Please proceed.

Thank you Tom 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, President and Chief Executive Officer; and Ron Tanski, 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 Jim, and good morning to everyone. Last night, National Fuel reported fourth quarter operating results of $0.36 per share down $0.16 per share for the quarter. These results were consistent with the first nine months of the year and we are inline with our expectations. For the physical year we reported operating results of $2.60 per share, a decrease of $0.57 per share from the prior year. As expected the drop in operating results for both the quarter and the physical year was almost entirely due to lower crude oil and natural gas prices realized primarily in our EMP segment. Overall, given the weak economy and lower commodity prices, fiscal 2009 was a strong year for National Fuel, financial and operationally and a testament to our balanced integrated model. Perhaps even more importantly during fiscal 2009 we continued to take steps particularly in the development of our vast Marcellus shale that will insure continued growth in the future. On the regulated side of our business the performance of our utility and pipeline and storage segment was rock solid. Thanks to the many revenue protecting rate making mechanisms in place, including straight fix variable rate design in the pipeline and storage segment and the revenue decoupling mechanism in our New York utility. Our regulated operations are much less sensitive to commodity prices or to act on macro economic cycles. Their stable reliable earnings and cash flows particularly important in troubling times serve as the foundation for our long standing dividend. In the E&P segment Seneca’s east division had another outstanding year posting a 15% increase in natural gas production and a reserve replacement ratio of 340%. Excluding the impact of some downward reserve divisions which were generally price related and most of which would reverse at current prices, these…

Thanks Dave. Good morning everyone. It was a good quarter and a good year for Seneca. Production was up 20% versus last year’s fourth quarter, and up 4% for the fiscal year. We have now drilled and competed two Seneca operated horizontal Marcellus shale wells with a combined one week IP of over 10 million cubic feet per day. We have continued to dramatically improve our overall funding and development cost with companywide fiscal 2009 F&D cost at $2.40 per Mcfe excluding lease acquisition cost. We replaced a 156% of our production through drilling. Added some high quality properties in California and divested some of our non-core properties in the Gulf of Mexico. Now, let me add some detail concerning our Marcellus shale activity. We recently completed our second Seneca operated horizontal and tested it at 4.7 million cubic feet per day for seven days. Much like our first horizontal well which tested 5.8 million cubic feet per day, this well showed very little decline over the seven day test period, each of these two wells was drilled in about 18 days, stimulated and competed at a cost of about $4 million each, far better than industry average. Needless to say we are very pleased with the results of the two wells in our Tioga County focus area, and plan to develop the area aggressively this fiscal year. We are currently drilling our fifth Seneca operated horizontal well in the same area and expect to have the more fracs completed by the end of December, including a zipper frac in which we frac two parallel wells, alternating stages from well to well. Over the past two years we rolled the learning curve at minimal cost and now as an operator our performance is on par with or even superior to…

Thanks Matt and hello everyone. Dave and Matt already covered a lot so I’ll be brief and we can get right to your questions. Earnings for the entire 2009 fiscal year were right in the middle of our guidance range, now the consensus estimates were higher, but we think this some analysts may have not factored into their estimates the impact of year-over-year commodity pricing effects on efficiency gas volumes in the pipeline and storage segment and some positive market to market adjustments and hedges in the EMP segment that occurred last year. It was also the year-to-year change in the allowance for funds used during construction and the capitalization of interest expense and impacted earrings in the pipeline and storage segment that may have been difficult for some analysts to get a handle on. The future regulated pipeline of projects will be sure to point out those issues for your modeling purposes. Looking to fiscal 2010, we revised our production volume to a range between 42 and 50 Bcfe. That volume change had the effect of increasing our 2010 earning guidance range to a range between $2.30 and $2.65 per diluted share and again that’s based on flat NYMEX prices of $5 per Mmbtu for natural gas and $75 per barrel of oil for our unhedged production. From the perspective of the utility segment, lower gas prices will have the effect of lowering winter bills for our customers by approximately 18% from last year and as we do at the beginning of every heating season, our utility customer service representatives and field service people are prepared to assist our customers in applying for heating aid, setting up payment arrangements and other service needs. Another area that’s worth reviewing and updated are the preliminary 2010 capital expenditure budgets that I…

(Operator Instructions) Your first question comes from Carl Kirst - BMO.

A couple of quick questions, Matt, just first off and great results here. With respect to the latest two Seneca wells and the difference say for instance than what we were seeing prior, do you choke this up mainly to just being in Tiago or do we have more frac stages or different completion as well that is in part responsible for the differences in early IP rates.

Carl I guess the way we’re looking at it now is there are two potential factors that are affecting these fracs as compared to our fracs in the area that we have been active with EOG. One is the rocks are a little different, the rocks are a little thicker and potentially a little different in some other properties and the other is we did frac at a higher bump rate. So, our frac technique was a little different. What remains to be seen is how much of the difference in the performance of the wells is a function of difference in the rocks and how much is a function of the difference in the completion technique and until we have the completion technique that we used and the pump rate that we used on a well in a more western part of our acreage we won’t know for sure which is the bigger factor, but we wouldn’t know that within a months.

Then just a quick follow up on the acceleration you gave us the update on what you think the exit rate for September 2010 would be. I think previously you had also gone out and said what you thought September 11 things and rate might be and I didn’t know if perhaps, as we are accelerating it to 2010 and presumably that momentum will continue into 2011, didn’t know if you would hazard a guess what you think that exit rate could be to yourself?

Well, I think I’ll do it this way Carl. It’s undoubtedly going to be higher than what we had previously estimated, but I’m not certain that we’re ready to provide a range today.

Carl, our analyst conference is next week in New York and Boston and then I think by then Matt might have it.

Carl, this is Ron and in part the wide range in our earnings guidance range at least for 2010 reflects the uncertainty as to when production will get turned on. I mean looking out two years and at this stage maybe there are some uncertainties.

No, all of that, points are very well taken I just thought I had hazard a question. Last question maybe and I will jump back in queue, Ron more for you, you guys have of got a rock solid balance sheet, you are obviously going to start to inflict a negative cash flow next year, clearly the rate of Marcellus spend is only going to increase as the opportunities increase. The idea of maintaining kind of BBB plus balance sheet is that a definitive goal or is that something where will this kind of keep it as perhaps solid balance sheet?

Well, it’s certainly as, we still have quite a few regulated operations and we plan to grow the pipeline in storage segment right along with the Marcellus and primarily to allow Seneca to produce its gas. So, to the extend that we do have regulated operations; we will be looking to keep the balance in the balance sheet. Now, that still gives us with the 56% equity component we have right now, I mean immediately if we want to do it, and I’m not saying we’re doing this, but we could lever up issue another $340 million or so of debt and still keep the 50:50 balance. Now, most of the spending and when we really start exceeding our cash flow would be in fiscal 2011 when we’ve got the pipeline projects in addition to the ramp up in the Marcellus. So for 2010, we’re pretty solid with cash on hand, liquidity and earnings, and we’ll just be careful to watch that during the year to see what we need to do.

Yes, longer term Carl, although options around the table of course, I mean short term we’re fine with the cash we have, and as Ron said and the ability to lever up if we need to, but longer term we’ll be looking at it over the next two, three, four years and every year we sit down with our Board and go over this kind of a plan, and consider all of our options. I mean there’s also certainly the ability to bring in partners with respect to midstream, with respect to ENPs and all of those options are on the table, but maintaining a strong balance sheet is very important to.

Your next question comes from Rebecca Followill - Tudor Pickering Holt.

Three questions for you, one on the West to East. How much committed capacity do you need to build it, right now you have 175 million a day? How much incrementally, do you need?

Rebecca I kind of oversimplified it a little bit talking about, I didn’t go into all the detail in the two phases, because it was boring me and I knew it would bore everybody else, but in part we’d be looking to jockey around some of the commitments that are on phase two as opposed to phase one. I think at the end of the day, if we get 200 or more on Phase I, we’ll be able to move forward with that project and we think we’ll be able to do that. Just looking at who bid on Phase II, who bid on Phase I, how they plan to put the gas into the system, we think that is a very likely project, let me put it that way.

So it’s not very far away, what you are saying?

No, it’s not very far away. We have 175 committed on and we think there are some producers out there, who are very serious about taking capacity. So it’s not very far away let’s put it that way.

Then following on that, I don’t know if you guys are ready to talk about it now, if you want to do it next week, if all of these things go through, the Lamont, Astoria, West to East, Empire, how much CapEx are you looking at for 2011?

We are going to talk about that next week.

Yes, we’re going to talk about that next week Rebecca, and what we’ll also have a little bit more firm or more definitive fashion. As you know in our 10-K, we’re required to protect out capital expenditures over the next three years. So we’ll have that laid out and be able to talk about it then. One of the things that I might suggest also for anyone who wants to get into some more detailed questions and make it a little bit more easy to see pictorially. If you go to our website, specifically Supply Corporation and Empires section of the website, we do list the open seasons in a little bit more detail and provide maps and it will be probably a lot easier to ask questions and to make sense of our responses. If you look at those maps and the open seasons and what’s involved and it will probably paint a more cohesive picture if you have that in hand.

I’ll do that and then last question on the 20% production growth that you mentioned Matt, if memory serves me correct, in August, you guys talked about 10% to 20%, is this 20% now an increase?

I think when we talked about 10% to 20%; we were including fiscal ‘10. Now we’re saying 20% not fiscal ‘10, but fiscal ‘11 forward, we think will be close to 20% production growth.

Your next question comes from Ray Deacon - Pritchard Capital.

Ron, I had a question regarding, so you believe the West to East could begin to make a contribution in 2011 from the first phase, did I hear that right?

No, with the construction would be likely to begin in 2011, and maybe completed by November of 2011 or so. So no, there wouldn’t be any contribution specifically from that project in ‘11.

Basically, Matt it sounded like what you were saying was maybe don’t read too much into the quality of the EOG acreage relative to what you’ve seen on your first two operated wells, because there’s still maybe some things that get changed on the completion technique that could be the better 30 day rates on IP rates. I guess relative to Tioga?

Yes, I guess I would characterize it as we don’t know yet, whether it’s more a function of the rocks or more function of completion technique. My suspicion is that it’s s both we just don’t know how much each contributes.

I guess is there a way, I know the acreage is in several different places, but is there a way to quantify what the takeaway capacity is just tied to the EOG acreage and your activity there?

Not really.

No, I don’t think Ray, that’s spread all over.

Your next question comes from the line of Jonathan Lefebvre - Wells Fargo.

Just quickly, on the first operated Marcellus well, can you talk about how that’s holding up today, I apologize if you already said this, but just trying to get a sense, it sounds like you probably have 30 plus days on that well now.

No, we really don’t Jonathan. We flow tested it for about seven days and then we shutted in to get some pressure buildup. We have actually recently opened it up again for some additional deliverability data, but it’s only been for a few days now. When we bring it online, when the gathering system is ready and we bring it online later this month, that’s when we’ll get some more extended production data.

On the Marcellus proved reserves that you booked at 20 or so Bcf, can you give us a breakdown of what the PUDs were on that? Is there any color you can share with us, but you have no flowing I guess maybe it’s all PUDs or how should we be thinking about it?

No, I wouldn’t think of it that way. Well, I guess technically that’s probably true because none of them are producing, but it amounted to eight PUDs and something on the order of eight PUDs and nine working interest wells that had been tested for a long enough period of time that we could book reserves, and a fairly big variation in the estimated EURs within that set of 17 wells. The vast majority of which all but really one, or wells in the joint venture where we have a working interest that is typically around, working interest of 50% and our net revenue interest of typically about 60. Also keep in mind these are relatively conservative estimates when those wells have been online for say 90 days or 180 days, will be able to better define that decline curve and that tool will be comfortable with a perhaps on more aggressive reserve booking.

Then in terms of drill time efficiencies, where are you seeing kind of spud to spud times, and I see that you are bringing on the next operate Marcellus rig a little earlier than I think you had previously said January or February, now it sounds like by the end of this year.

By the end of this month actually.

By the end of the month, sorry.

Spud to spud, keep in mind we’ve got a pretty small sample set here so far, we’re on our fifth well, but I’d say spud to spud the assumption we’re kind of using going forward is somewhere between say 20 and 25 days. Now, when a rig has to move a long way that gets a little bit longer, and that also is going to depend some degree on the length of the horizontals. Some areas we may have reason that we’re drilling 5,000 foot horizontals and other areas it may be 3000.

The updated CapEx for the Marcellus, what are you basing that on a $4 million well cost or assuming that you are going to get to the $3.5 next year?

We’re basing that estimate on a $4 million well cost.

I do think that as we get further along and into more of a development phase that we will be looking at $3.5 million well cost, but the relatively conservative assumption for fiscal ‘10 is that the wells will average on the order of $4 million per well.

Then I know you don’t want to maybe front run the analyst day, but in ‘11 my numbers kind of imply maybe 80 to 90 wells including the joint venture, any comments on that based on your new updated guidance?

We will talk about that next week, but frankly I think there is a good chance it would be a larger total well count than what you are suggesting.

Your next question comes from Faisel Khan - Citigroup.

Just a question on the realization you guys had in Appalachia, $4.09 in the quarter, it seems a bit higher than the Columbia pool pricing, and can you just kind of walk us through why again by the realizations on that Appalachia productions than what we would see in Columbia pool.

You broke up a little bit better, but I guess what I am hearing you ask is the realized price in Appalachia is higher than you anticipated.

Yes. Just, I was looking at that Columbia pool pricing, I thought I’d get a lower price; I’m just trying to figure out. I know you guys are farther up on the pipeline capacity than what you guys are geographically, but I suppose that has something to do with it but I was hoping you could.

I think we would have to do a little bit of research on that to understand why it differs from what you are seeing. Faisel Khan – Citigroup: On the overall portfolio in E&P, obviously with the ramp up in production in Appalachia your gas production from a larger mix of your overall portfolio, is there any sense that you guys would want to increase your production or exposure on the oil side either through acquisitions or through some other methods?

Again you are breaking up a little bit, but I think you’re asking, is there anything we can do to increase our oil production. Faisel Khan – Citigroup: Yes. I was asking if the portfolio approach do you want to, is there a goal to keep your oil production kind of a certain percentage of overall production or are you happy becoming more gassier overtime.

Well to some degree our production and reserve mix is a function of the assets that we have and we have a great position in the Marcellus shale which is a gas play. So, we’re naturally going to become gassier overtime. Is that a gold, no, not really, I wouldn’t mind keeping the mix a little more even, but frankly the assets that we’ve got some great assets and those assets tend to be gassier, if we had 720,000 acres in the Bakken that would be a nice mix.

I think, it’s not, I mean as with Ivanhoe Faisel, where we added last year in California, we get some more of those potentially built on acquisitions where we think we can do a good job. Yes, we’ve been looking at adding those, but no we don’t have a predetermined percentage between oil and gas and as Matt said, given our resource, it’s like we will become gassier overtime. Faisel Khan – Citigroup: I just want to understand if there was any gold mine, but it sounds like you are in both plays, you’ve got good opportunities in both plays and you are just going to continue to take you to invest where the best returns are. Thanks guys.

Your next question comes from Carl Kirst - BMO.

Just a very quick clarification with respect to the price, the negative price related revisions and it looked like the largest one was in Appalachia there. Matt, can you give us the price or a range where you think the majority of that would come back?

Yes. The year end price was about $3.30. So even today we would get a fair bit of that back now maybe half of that. That’s just a guess though Carl.

I was just curious kind of what the rough range was that helps to give some color?

That’s pretty close, Carl, I think we took a look at that, that’s pretty close.

Your next question comes from Jim Harmon - Barclays Capital.

I think you made comments that you would need processing facilities on a year or two. I was curious if you had on early read on what Btu content would be and maybe how much processing capabilities you might need going forward?

Actually what I said Jim is that, part of the program this year horizontals that we drill with the second rig coming up fairly soon. Out of that program will be to evaluate that Btu content in several areas across the sort of western flank of our acreage and determine what that Btu content is and where do we need processing. A lot of it is very kind of close to the line and close to the assumed line of where you’re going to need processing and where you are not.

As you are building Midstream infrastructure, are you going to be the main holder of capacity or you have a more third party to support as you move forward?

Jim, that’s real project-by-project, I mean the Covington project, Seneca is utilizing that capacity. There’s likely to be others that will utilize that capacity. In other parts though I mean we’re working, for example the supply company project with range, that’s all range production and our Midstream has. So probably, I’m looking at them about 12 or 13 projects with other producers in addition to Seneca. So it’s going to be, we would own the Midstream pipe and it is going to be project-by-project decision.

Your final question comes from Ray Deacon - Pritchard Capital.

I just wanted to ask a question more about, can you just remind me again how the activity is going to ramp up on the EOG side and on the operated site for you guys. I know it’s a second rig before your end that you’ll operate and then the third in the summer and then EOG will be 20 gross wells in fiscal 2010, is that correct?

EOG’s minimum requirement as part of the joint venture agreement maybe 20 wells in calendar 2010; now from what Dave have indicated, I expect will be at a significantly higher level than that in calendar ‘10, and our best guess for fiscal 2010 would be, as I said, 25 to 30 for fiscal 2010. On the Seneca operated side, we’re going to bring that second rig next month and the third rig we haven’t really set a date certain, but let’s say by this next summer. So similar well count for Seneca, 25 to 30 operated wells. Keep in mind, when I refer to these well counts, those are gross well counts. So when I say 25 to 30 EOG wells, we’ll have 50% working interest in those.

Has the acreage position changed much since the end of the last quarter?

Not substantially. There are places where we’re adding acreage primarily acreage that holds on and supplements our existing position.

Ladies and gentlemen, this concludes the question-and-answer session for today’s conference. I will now turn the call back over to Jim Welch.

Thank you, Tom. We’d like to thank everyone for taking the time to be with us today. A replay of this call will be available at approximately 2.00 pm Eastern Time today on both our website and by telephone, and a run through the close of business on Friday, November 13. To access the replay online visit our Investor Relations website at www.investor.nationalfuelgas.com and to access by telephone, call 1-888-286-8010 and enter pass code 75925727. We’d also like to mention that on Thursday, November 12, at approximately 8:30 am Eastern Time National Fuel will be making a webcast presentation of year end financial and operational results that can be accessed through our Investor Relations website as well. We’ll issue a press release to remind everyone of the details of this event this afternoon. This concludes our conference call for today. Thank you and good bye.

Ladies and gentlemen, thank you for your participation in today’s conference. This concludes the presentation. You may now disconnect. Have a great day.