Good day, ladies and gentlemen, and welcome to the First Quarter 2009 National Fuel Gas Company Earnings Conference Call. My name is Shannon 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). As a reminder, this conference is being recorded for replay purposes. I would now like to turn the presentation over to your host for today's call, Mr. Jim Welch, Director of Investor Relations. Please proceed.

Thank you 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 for 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 day 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, we reported a net loss for our first fiscal quarter of $0.07 per share. A sharp drop in crude oil and natural gas prices required us to take a $108 million after tax charge, to write down the book value of our exploration and production assets. While disappointing, it was expected, its non-cash, and it's important to realize this impairment was entirely price driven, with no significant loss reserves. Our reserves are still in place, and as they are produced, they will contribute to future earnings. As we've said in the past, diversity of assets is a defining characteristics of National Fuel's long-term strategy. Our regulated operations, which are not greatly impacted by short-term swings in commodity prices, act as a natural hedge to our more price sensitive E&P operations. The benefit of our diversified and balanced portfolio of assets was readily evident in this quarter's results. While lower crude oil prices and hurricane related production shut-ins Gulf, our Seneca's recurring operating results to drop by $0.08 per share. Our utility and our pipeline and storage operations posted strong results; results that largely offset the reduction at Seneca. Consequently, consolidated operating results were down only $0.02 per share, compared to the prior year's record first quarter. The past several months have been characterized by declining commodity prices, and tighter access to credit, conditions which may exist for some time. Since there is little we can do to influence commodity prices or credit markets, we have focused on effectively managing our assets, and prudently allocating our capital. In the E&P segment, we continue to prioritize the development of our nearly 1 million acres of mineral rights in Appalachia. In the Marcellus, our partnership with EOG is proceeding at the pace called…

Thanks Dave. Good morning, everyone. Let me start by addressing Seneca's first quarter production. Although Hurricane Ike caused overall production to be down 10.5% versus first quarter last year, I expect that we will make up most, if not all of that shortfall over the remainder of the fiscal year, as Gulf of Mexico development projects come on line, and Appalachian infrastructure constraints are relieved. Due to Hurricane Ike, first quarter Gulf of Mexico production was 1.2 Bcfe lower than first quarter of last year. While much of our production returned very fairly quickly after the hurricane, two of our major fields remained shut-in the entire quarter, and are just coming back on line this month. In addition to the resumption of shut-in production, we expect to have first production from the Cyclops field within the next few weeks, bringing overall Gulf of Mexico net production up to 45 million cubic feet equivalent per day. We have one more discovery from last year, Eugene Island 383 that is still being developed, with first production expected in the fourth quarter. In California, quarterly production is up 7% versus a year ago, due to the net production increase from last year's Ventura area property trade. The production increase resulting from our modified steaming (ph) operations, and the production added from our new Maverick wells at Midway Sunset, and our Monterey Shale wells at Lost Hills. While our goal in California is to keep production flat for the next several years, our West division team is doing a great job finding ways to actually increase production, in each of our three field areas. In Appalachia, we continue to aggressively develop our Upper Devonian type gas sands. However, our production for the first quarter was disappointingly low, due to gathering system constraints and compressor…

Thanks Matt and good morning everyone. Although variability in commodity prices has provided a challenge for all the financial analysts, trying to keep their forecast models updated. Back in August, when we gave our preliminary fiscal 2009 earnings guidance of $3.20 to $3.40 per share, we based our forecast on NYMEX prices of $9.50 per MMBtu for gas and $115 per barrel of oil. When we reported earnings in November, we revised 2009 earnings guidance to a range of $2.60 to $2.80 per share based on NYMEX prices of $7 per MMBtu for gas and $70 per barrel of oil. In last evening's release, we revised our guidance once again, including $1.35 per share reduction in earnings from our ceiling test impairment and began reducing commodity prices to $5.50 per MMBtu for gas and $45 per barrel of oil for our un-hedged production over the remaining nine months of fiscal year. We have a new earnings guidance range of $1.10 to $1.30 per share or $2.45 to $2.65 per share excluding the impairment. Continuing our usual practice, we've included an earnings per share sensitivity due to changes in commodity prices at page 21 of last evening's release. In addition to that table, our first quarter 10-Q that we'll be filing later today have some additional calculations regarding a hypothetical impairment if lower prices have been used in the ceiling test calculation at the end of November. Matt mentioned a cut back in CapEx for the exploration and production segment. With that reduction, planned CapEx for the fiscal year will be $244 million for the E&P segment, for the consolidated company our CapEx is now targeted at $376 million. From a cash flow perspective, factoring in $376 million in capital spending for the year and using the middle of our earnings…

(Operator Instructions). The first question comes from the line of Carl Kirst of BMO Capital.

Hey, good morning everybody and a nice way to start off here. Just a few E&P questions if I could, Matt just... I guess the EOG JV horizontal well that's drilling now, is that number seven or number eight, I am losing track.

The one that it's drilling now would be our seventh horizontal.

Would be seventh. And are you seeing previously I guess we've talked about well cost in the range of $3.5 million sort of on a run rate basis, understanding we're doing a lot of science in the early days here. But, are you seeing costs beginning to come off on that, as far as your drilling incompletion estimate for this well here?

Maybe a little bit Carl. It's not a substantial change at this point. I think what we're really seeing is, we'll probably be able to drill wells at that same cost, and get much longer laterals. So, on a cost per foot basis, yeah we're seeing an improvement.

Could you repeat what the lateral lines of these of the three wells that are going be fracked and I guess the anticipated laterals the well that's being drilled?

They range from 3,800 feet to 5,700 feet.

Okay. And then, just last question I had on that, you had mentioned a possible flow test in March, and then maybe having a data point on the next earnings release. Since we have three wells waiting to be fracked is that some thing where all three wells can kind of be fracked kind of back-to-back i.e. we might have three data points, or is the timing such that there going to be space enough on part where we really are going to have that sort of first flow test by the next call.

Carl, I guess I would expect that we'll only have one by the next call. Two, that are waiting are in a fairly remote location that we think is better or I should sat EOG thinks is better to wait until, after the spring fall. So those two wells would be further down the line.

Okay. Thank you.

You're welcome.

(Operator Instructions). Your next question comes from the line of Shneur Gershuni of UBS.

Actually Shneur Gershuni, but okay.

We know its Shneur.

Just a couple of quick questions here. I was wondering if you can give us a little color on the ceiling test, what areas were more impaired, and so forth. Kind of how you evolve with the numbers?

I am sorry, Shneur. You need to repeat that.

The ceiling test. I was just wondering, if you can sort of, if you can walk us through which areas were more susceptible to.... to the test versus others? Whether it was more in California, or whether it's in the Gulf of Mexico and so forth?

Well. Keep in mind it's a full cost pool. So really, you like at the total value of all your reserves, and compare that to what's on your books. And you calculate that total value, based on year-end pricing. Now, another way to look at it is oil prices took a substantial dive, particularly when you apply a California basis differential. So, one could argue that California had more of an influence on it. But it's really an aggregation to do the calculation.

Okay, fair enough. You mentioned in your remarks that you were looking at potentially cutting the Upper Devonian program. Just kind of trying to look at where you believe the breakeven prices for the Upper Devonian program or breakeven plus cost to capital, kind of where do you need to see gas prices, you need to make sure that you're earnings your returns there?

I think really the way we need to look at it is by discreet project. And some of the projects look good at $4. And others don't look good unless it's at least say 550. So, that's why I'd say we're looking at it hard. There will be certain projects that maybe, won't make the cut. That would have made the cut six or eight months ago. So that could potentially affect the number of wells that we drill for the year.

Is it kind of circular like if you see service costs come down in those numbers, you trying to change?

Yes, and that's part of what we're factoring into our analysis is, how much can we assume well cost would be reduced.

Okay. And you've also noted that 50,000 acres have been chosen by EOG. Was that primarily on NFG's legacy acreage or is it on EOG's legacy acreage?

That will be the selection process is entirely on an NFG's acreage, Seneca's acreage because the way the joint venture works, we have the right to earn 50% working interest in all of EOG's acreage that's with in the AMI. EOG has the right to earn 50% of 200,000 acres or 100,000 net on our acreage, so they need to select down to that amount where there is no selection process any of EOG's acreage.

Okay. And one last question with respect to share buyback program, is it currently suspended now or is it something that you're looking at now that, you're taking that expensive gas out of the ground and gas is much cheap as the liquidity is improving?

Really Shneur this round tasking is really is going to depend more on the credit markets and the fuel for the credit markets. As Dave mentioned in his comments, we're just really watching our capital and there's a lot of acreage to be tested. And we want to do a lot more science or we're just being careful; managing what capital we have and don't want to assume necessarily that the credit markets are always going to be there. So, the share buyback is still extent. We haven't purchased any shares under at lately well.

Okay, great. Thank you very much.

Your next question comes from line of Rebecca Followill of Tudor Pickering. Rebecca Followill - Tudor Pickering &Co.: Good morning. You guys mentioned that in your 10-Q to be filed later today, you had some hypotheticals on what would happen to reserves; had there been a lower oil price at September 30th, can you give us any color on that or do we need to wait?

Well. No. its not reserves Becca, it's really the ceiling test calculation. Rebecca Followill - Tudor Pickering &Co.: Okay.

And what we did is, we did another sensitivity and we did the calculation with oil prices that were $5 a barrel lower and then we also did another run at gas prices that were a $1 lower at the end of December and then we combined them both together. Rebecca Followill - Tudor Pickering &Co.: Okay. So if fuelling test not negative reserve additions?

Ceiling test. So under each scenario we get round about another $50 million impairment, $50 million of gas prices were $1 lower or $50 million of oil prices were $5 a barrel lower and if you add them together round about $100 million, extra impairment but it didn't effect the reserves. Rebecca Followill - Tudor Pickering &Co.: Any field force of you guys escape the pull of having a September 30th fiscal year-end. A lot of companies as you're seeing are facing big negative reserve provisions because of their really low oil price and the light basis at year end, any feel for what happened to reserves had a different oil price scenarios?

Becca of course we look at our reserves quarterly, so we did take a small, very small negative reserve revision at the end of the quarter but its not substantial. And yeah, oil in California is what is most sensitive to that. Now, the vast majority of our oil production can handle a much lower oil price, so it's only going to effect tail end years out into the distant future. Rebecca Followill - Tudor Pickering &Co.: So if September 30th of this year, if oil is at 50; we shouldn't expect a massive negative reserve revision?

No. Rebecca Followill - Tudor Pickering &Co.: Okay, great. Thank you.

I would now like to turn the call back over to the management.

Thank you, Shannon. We would like to thank you 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 on both our website and by telephone and a run through the close of business on Friday, February 13, 2009. 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 64283323. This concludes our conference call for today. Thank you and good bye.

Ladies and gentlemen that concludes the presentation. Thank you for your participation. You may now disconnect. Have a wonderful weekend.