National Fuel Gas Co (NFG) 2009 Q3 法說會逐字稿

Good day, ladies and gentlemen. And welcome to the third quarter 2009 National Fuel Gas Company earnings conference call. My name is Stacy and I'll be your conference moderator for today.

At this time all participants are in a listen-only mode. And we will be facilitating a question and answer session towards the end of the 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, Stacy. 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 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'll begin with Dave Smith.

Thank you, Jim, and good morning to everyone. As you read in last night's earnings release, National Fuel's third quarter earnings were down $0.19 per share from last year.

Continuing the trend from the first two quarters, lower crude oil and natural gas prices realized in our Exploration and Production segment were the principal drivers. But putting aside the impact of lower commodity prices on Seneca's earnings, the third quarter was an excellent quarter for the Company operationally and strategically. As we expected, the regulated Companies, our state regulated Utility distribution and our federally regulated Pipeline and Storage company, Supply and Empire, delivered another quarter of consistent earnings despite the lower commodity price environment and despite a drop in industrial demand. Our balanced diversified model worked as it should with the regulated companies providing the stability. In the E&P segment, production was up by about 12% over the prior year with each Division- West, Gulf, and the East contributing to the increase.

Importantly, in the area that we have been targeting for significant growth, Appalachia, production is up by approximately 16%, and I should note that, that production is entirely related to our Upper Devonian program. More importantly, we made great progress on putting in place the foundation necessary to exploit our vast Marcellus position, most of which incidentally, we own in mineral fee. During the quarter, EOG completed three successful joint venture horizontal wells in the heart of our acreage. Seneca drilled an additional three vertical wells for a two day total of seven vertical wells. These wells are spread over a wide geographic area. In addition, this past week Seneca reached total depth on the first horizontal well, and is preparing to drill a second horizontal well, utilizing the same pad. With each well we gain more information, more data, and more experience. As is evident by the capital we intend to devote to the Marcellus in 2010, we are encouraged by what we have learned today.

Complimenting Seneca's efforts, NFG Midstream commenced construction of the first phase of its Covington Gathering System, which will connect Seneca's Tioga and Lycoming acreage with Tennessee Gas and with UGI. This first phase connecting our Tioga acreage to Tennessee, is expected to be in service in early fall 2009, in time to move the production from Seneca's first horizontal well. Midstream is presently marketing the capacity that will not be utilized by Seneca to other Marcellus producers. We are also in continuing discussions with a number of parties on other Marcellus-related gathering projects. Given the competitive nature of these projects, and given the confidentiality agreements that are in place, obviously we are not able to provide details. But we can say we are encouraged by the interest and anticipate that the discussions will lead to new projects in 2010 and 2011. Looking to fiscal 2010, we intend to build on the considerable momentum we achieved in 2009. The continued development of the Marcellus will be our top priority.

As you can see from last night's release, Seneca's East Division has been allocated the lion share of our 2010 E&P capital budget, about 83% of the total budget. Most of that Division's budget, over 75%, will be spent in the Marcellus. Though we are focused on the Marcellus, we still plan to maintain an active Upper Devonian program. At current natural gas prices and given current staffing levels, we are anticipating a 150 well program in 2010. That pace should allow us to build a nice inventory of sites ready to be drilled when prices improve. Given our opportunities in the East, spending in the Gulf and West Divisions will be lower compared to 2009.

In the Gulf, where our more focused program has yielded improved results, most of our capital will be spent further developing existing producing properties. In the West, where we have been very successful for some time, our capital will be spent mostly on upgrading facilities and on a limited number of development wells. Total fiscal 2010 capital spending in the E&P segment is expected to be in the range of $175 to $225 million. While that is lower than our fiscal 2009 spending, remember that in 2009 we spent $43 million on the Tioga and Lycoming acreage we acquired in the DCNR lease sale and another $39 million on the recent Ivanhoe acquisition. If you exclude those two items from 2009's capital expenditures, the mid-point of our 2010 capital budget represents a 30% increase over last year. I should note that our 2010 E&P budget does not reflect capital for acquisitions. But given our solid balance sheet, we remain ready, willing, and able to take advantage of other strategic opportunities like we did with Ivanhoe, should they arise.

Turning to our Pipeline and Storage segments. The anticipated increased pace of drilling in Appalachia, both by Seneca and by other operators, should continue to provide opportunities for transmission and storage development, and allow us to continue to keep our balance between the unregulated and the regulated segments. Supply Corporation continues to pursue multiple expansion initiatives. The largest of which is the West to East project and its accompanying Appalachian lateral. Preliminary engineering work, project cost estimates, and rate design work have been completed and precedent agreements have been sent to interested parties. As we have been saying for the last few quarters, and this was verified by the imminent interest shown by prospective shippers and portions of the larger West to East project, it is becoming more and more likely that the project will be built in sequential stages as the market develops. Year to fit Marcellus drilling programs, a likely candidate for such an accelerated project perhaps as soon as 2011, relates to drilling that is currently underway by Seneca and others in the region west of Leidy. We will keep you up to date as these projects develop.

Supply Corporation also continues to make progress on two smaller producer driven projects, both of which are ultimately related to the West to East Pipeline at Bristoria and at Lamont. The Bristoria project is a $35 million pipeline and compression project at the southwestern end of our system that will move about 150 million a day of market constrained Marcellus to an interconnection with Spectra Energy and ultimately off system. At Lamont, Supply Corporation is proposing to build a new $5 million 1200-horsepower compressor station, in order to provide 35 million a day of take-away capacity and an interconnection with Tennessee, that will move primarily Seneca and EOG production. We expect the Lamont project to be in service in early 2010 and the Bristoria project to be completed in two phases - one in late 2010 and one in late 2011.

In closing, the third quarter was a very good quarter for National Fuel. Particularly, with respect to the progress made on our initiatives in Appalachia. We look forward to building on that success in the E&P, in the Midstream and in the Pipeline and Storage businesses, in 2010 and beyond.

With that, I thank you for your attention, and I'll turn the call over to Matt for an update of Seneca's operations. Matt?

Thanks, Dave. Good morning, everyone.

Seneca had a great third quarter, which included a nice bolt-on acquisition in California, continued good news from our Marcellus drilling, and outstanding company-wide production growth. Production was 11.5 Bcfe, 12% better than the third quarter of fiscal 2008, and the largest US quarterly production volume we have had in five years. I anticipate full year production to be above the mid-point of our guidance and above fiscal 2008 production. While this will be a relatively small production increase from 2008 to 2009, you can expect a larger increase in fiscal 2010, and continued growth of 10% to 20% a year as the development of our Marcellus Shale accelerates. Now let me discuss the individual Divisions, beginning with the West. California continues to perform well, with production for the fiscal year up 7% versus last year, largely due to the impact of increased steaming and dedicated steam injection wells at Midway Sunset.

Three weeks ago we closed on the acquisition of Ivanhoe Energy. The majority of Ivanhoe's value was in the Midway Sunset Field, where we are already active. The acquisition will add approximately 650 barrels of oil per day to our West Division production, and we are adding approximately 1.8 million barrels of proved reserves, with an additional 3 to 4 million barrels of upside. The effective date of the transaction was January 1, 2009 while the closing was July 17. At closing, the deal included cash on hand, working capital, and some net operating loss carry forwards, worth a combined $5 million or more. Therefore, the cost of the reserves is approximately $34 million or $19 per barrel of proved reserves. Between signing the stock purchase agreement and closing, oil prices rose considerably. Consequently, we have hedged one-half of the first three years of production from these new assets at a price that is nearly $8 per barrel higher than what we had assumed in our economic analysis. With this acquisition and our other initiatives in California, we expect our West Division production to grow for a third consecutive year in fiscal 2010.

In the Gulf of Mexico, production is up 16% versus last year's third quarter, as we now have a full quarter of production from our Cyclops field, and a full quarter with all of our hurricane related shut-ins back online. Production is also up 16% in the East, as we have solved some of the gathering system constraints, and brought on new wells drilled this fiscal year.

Moving on to our Marcellus Shale activity, since last quarter's call, we have completed three more joint-venture horizontal wells. The average three day IP for the four wells completed this fiscal year is approximately 2.3 million cubic feet per day and our initial estimated EUR's range from 1.9 Bcf to 3.5 Bcf per well. These wells are not clustered close together. In fact, at the extreme, they are over 30 miles apart. Therefore, we are now confident that a large portion of our 720,000 net acres will ultimately be productive.

In our Seneca operated program, we have now drilled seven vertical wells and cored five of them. While we have had no major surprises, we have seen a fairly wide range in rock quality, which will help us to prioritize areas for our horizontal development program. We recently finished drilling our first Seneca operated horizontal well in Tioga County, and have begun operations on our second. The first horizontal was drilled in 17 days to its planned lateral length of 3,300 feet. We expect to fracture stimulate and flow test both wells beginning in late September or early October. Now that we have four consecutive economic wells and have evaluated a wide swath of our acreage with vertical wells and cores, we are prepared to estimate our overall net resource potential for the Marcellus Shale, with the range of 4 Tcf to 8 Tcf. The wide range reflects uncertainty in per-well reserves, as well as a risk factor to estimate what percentage of our acreage will ultimately be developed in each area.

While our assumptions for both EUR and risk factor vary for different areas, the weighted average for risk is 30% for the low case and 40% for the high, while EUR per well is from 2 Bcf to 3 Bcf. Of course, some wells will be much bigger and some may be smaller, but those are the averages for those two estimates. As we gather more data, including longer-term production history, we will revise our resource estimate. Regarding drilling and completion costs, the recent EOG wells have averaged over $5 million. However, as we move to a multi-well drilling pad development program, I expect these costs to eventually come down to a range of $3.5 million to $4 million for both EOG joint-venture wells and the Seneca-operated development wells. Such that we expect long-term finding and development costs to $1.15 to $2 per Mcf.

Production from our Marcellus program will come on rapidly in fiscal 2010. We anticipate net production of 20 to 30 million cubic feet per day by the end of fiscal 2010, that is September of 2010, and 50 to 70 million cubic feet by the end of fiscal 2011. With this new Marcellus production coming on in 2010, we are estimating company-wide production for the next fiscal year of 42 to 48 Bcfe. The mid-point of this guidance range is 45 Bcfe, or 10% higher than the mid-point of our guidance for fiscal 2009. In looking further ahead to fiscal 2011 and 2012, we anticipate production increases in those years to be closer to 20%, as we accelerate our Marcellus program.

In conclusion, we had a great quarter with production up substantially and good test results in the Marcellus. Next year, and the foreseeable future, we'll see increased attention to the Marcellus, which should lead to substantial growth in both production and reserves. With that, I'll turn it over to Ron.

Thank you, Matt, and good morning, everyone.

Last night's earnings release was pretty straightforward. There were no special or one-time items during the quarter and most all of the earnings drivers are covered in the release. Earnings for the quarter were higher than the street consensus and we can point to four likely reasons. First, in the Exploration and Production segment, lease operation expenses of $1.22 per Mcfe were lower for the quarter than the run rate we had for the first six months of the fiscal year of $1.55 per Mcfe. Second, the basis differential for Midway Sunset crude oil also improved during the last quarter, and reached over 90% of West Texas Intermediate. It had been previously running at about 85% of WTI. Third, on a consolidated basis, the effective income tax rate for the quarter of 35.5%, was less than the likely 38.5% that analysts have built into their models. The rate this quarter is lower than the statutory rate because of some tax deductions related to the Exploration and Production segment and some other true-up adjustments related to the filing of our consolidated tax return during the quarter.

Finally, in all of our segments, we have been carefully watching our operation and maintenance expense and we are a few million dollars under forecast for the quarter. Looking forward to the fourth quarter, we are not expecting any unusual items, so I'm going to move ahead to discuss the assumptions built into the fourth quarter earnings guidance and then turn to our earnings guidance for fiscal 2010. Fourth quarter GAAP earnings are expected to be in the range between $0.28 per share and $0.38 per diluted share. When you add the $0.92 of GAAP earnings for the first nine months, our earnings for all of fiscal 2009 are expected to fall in the range between $1.20 and $1.30 per diluted share. If you add back the noncash impairment from the first quarter, the range for 2009 would be $2.55 to $2.65 per share. Now this guidance includes fourth quarter production volumes of approximately 11 Bcfe and incorporates approximately three days in August and three days in September of contingency for possible shut-ins of our Gulf of Mexico production due to hurricanes, and the shut in of a portion of third-party operated Gulf production during August and September due to low prices.

Looking forward to fiscal 2010, our preliminary estimate for consolidated earnings is in the range of $2.30 to $2.60 per diluted share. Now these are preliminary numbers that may change as we refine some commodity pricing assumptions and operation and maintenance expenses in a couple of our segments. The earnings range of $2.30 to $2.60 per share utilizes flat commodity pricing, and includes a flat NYMEX Henry Hub gas price of $5 per MMBtu, and a flat NYMEX WTI price of $75 per barrel. We start with those NYMEX prices and then we apply a basis adjustment in the ranges shown on page 24 of the release. Using the 45 Bcfe mid-point of our 2010 production guidance, we have approximately 47.5% of our expected production for 2010 already hedged. To the extent that NYMEX prices vary from our flat pricing assumption, the impact of those pricing changes on our unhedged production will affect our earnings as shown in the sensitivity table on page 26 of yesterday's release.

We've also set our preliminary capital budgets for each of our segments for fiscal 2010. Those preliminary budgets include $175 million to $225 million of CapEx in our Exploration and Production segment that Dave referred to earlier, $63 million in our Utility segment, $46 million in our Pipeline and Storage segment, $6 million for our Midstream projects, and $1 million for the rest of the Company, for an overall total in the range of $291 million to $341 million. In the Pipeline and Storage segment, approximately $14 million out of the $46 million total is for spending on local production gathering, compression, and interconnections with other interstate pipelines. Our balance sheet continues to be strong. At the end of June, we have an equity component of over 56%, $400 million of available cash, and ample credit availability providing us with plenty of liquidity. Using the middle of our earnings guidance range and CapEx budgets, our preliminary forecast for fiscal 2010 indicates the cash flow will be positive by over $20 million for the year, leaving us some room for the possibility of another small acquisition.

Before we open up the line for questions, I'll mention a couple of items regarding our utility. Natural gas prices have continued to moderate through our summer injection season and we project that the gas cost portion of our customers' bills for the upcoming winter will decrease by approximately 20% in our New York jurisdiction and 28% in Pennsylvania. In our New York Division, our customers continue to take advantage of our Conservation Incentive Program. Since the inception of the program, we have sent out approximately 27,000 rebates totaling $5 million to our customers for the installation of energy-saving equipment. Even with the decrease in natural gas prices since last year, we encourage our New York customers to take advantage of the available rebates under the Conservation Incentive Program before the heating season begins, so they can see continued savings in their fuel bills.

I'll now ask the operator to open up the line for questions.

(Operator instructions).

Your first question comes from the line of Shneur Gershuni with UBS Securities. Please proceed.

Good morning, guys.

Good morning, Shneur.

I just had a couple of quick questions here, if I could start on the E&P side. You sort of out laid your resource potential. I was wondering if you have the ability to bucket the acreage into kind of a 3-P category versus what would be sitting in a resource potential. If that's something you have available at this time.

Well you really can't get to a 3-P category without some wells being drilled, a significant number of wells being drilled, Shneur. This is really all in the resource potential category for now. Since we have several commercial wells we will be booking reserves by year end. But that hasn't been done yet.

Okay. I was also wondering if you've got available the number of locations that you were kind of using, I guess, in your less-than-optimal scenario, the one where you arrive the 4 TCF versus the 8 TCF. If you plugged the Company wells, and what your well spacing was and so forth.

It's both the low and the high cases. Assume 100 acre spacing and ultimately we may be able to space these wells tighter than that. Part of the reason we used 100 in the estimate is that we are not talking about a big square flat tract of land, where you can lay out the wells exactly as you want to. So some of the assumption here is that you are not going to be able to space them at 80 acres for surface reasons, so that the average turns out to be 100. This would amount to, let's see, it's on the order of, after risked, after risking, on the order of 3,000 gross wells. 3,000 to 4,000 gross wells in the range.

Great. Just if I could turn over to the gathering system for a second. Dave, you kind of highlighted a couple of projects that you are working on right now. I was wondering if you could sort of repeat the CapEx numbers, as I missed some of them. If you could also talk about the project that you are looking to go up to 2011. Kind of what the CapEx would be associated with that project assuming fuel prices are at the same levels as they are now.

Well, on the gathering side, the overall Covington CapEx is $25 million to $30 million. This year it looks like we are going to spend about $10 million on that project. I think next year we have forecast $6 million on that project for what we are here calling phase 1B, I think. After that to go further down, it would be about another $15 million that would open up the Lycoming acreage further south. That could be 2011, it could be after that, depending upon on how quickly we are drilling up the Northern, and whether or not there are potential other alternatives with respect to that acreage. The Bristoria project is a regulated cost to service project and that's more in the $25 million to $30 million range. There is some replacement, there's some expansion, expansion is like $24 million of thatLamont, I think that's $5 million to $6 million, a relatively small project. That's just dropping in a compressor, which would open up the acreage.

Potentially, the big project that I was referring to, probably more likely would be a regulated pipeline and storage project, running from Leidy west, to open up much of the acreage that the Marcellus producers are looking at having opened up, part of the West to East project. That could be as long as 82 miles. We are talking about a budget of about $250 million. But that's very rough and preliminary. Even that, our guess is as we look at it, there is about 32 miles in there that is likely to be built before the rest of it. That's the accelerated project I was referring to.

Now beyond that, the Midstream unregulated, in addition to the Covington Project, there are a number of discussions with other fairly significant parties, on potentially building gathering. I think the fact that they moved so quickly on this first phase of Covington, people think of us more as a pipeline company than they do as a gathering company.The fact that it looks like we are going to get this thing in service in a very short order, less than five or six months from when we started, I think has boosted our opportunities. We are in a number of discussions with others. But as I said, we really can't talk about those, there are confidentiality agreements in place there.

Obviously. When we think about these projects as they come in, is it fair to be thinking that there are going to be earning ROE's north of 10%, or kind of seven multiple on an EBITDA basis, that they'll get billed at?

Yes. I guess the way I think about them is essentially three categories. One is the cost of service Pipeline and Storage, which is cost of service and a regulated return. Two is the returns with respect to our Seneca acreage for example, and the Tioga acreage we are talking about. Our primary objective in Midstream there is not to move money from one pocket to the other and make money off Seneca, the primary objective is to open up that Seneca acreage. I think of that differently than I would, for example, if we put in a major system for Cabot, or for Ultra, or for Range, or for some other producer. So I think about those in three categories,and don't want to say too much more about that, Shneur, because we don't want to go out and have people say "oh, you are expecting this kind of return, we are not willing to give that you kind of return". It is just very, very competitive right now.

Understood. Thank you very much.

Thanks, Shneur.

Your next question comes from the line of Jonathan Lefebvre with Wells Fargo. Please proceed.

It's Jonathan Lefebvre. Good morning. Just in terms of the expansion opportunities and adding to your acreage, should we be thinking about that specifically, you expanding your Marcellus acreage? Or would it be outside of your core property? Can you just give us some insight into how we should be thinking about that?

Yes, Jonathan, I guess the way I would look at our Marcellus is our strategy has been and will continue to be, we'll add acreage that is contiguous to our existing acreage that adds value to our existing acreage. And we'll also look to add acreage that, where we can get a fairly substantial chunk of contiguous acreage that we believe has some reason that it may be even better than our acreage. So those are the two things we look for in adding Marcellus acreage. If all we are doing is adding acres scattered about, that is not something we are chasing. Now in terms of other acquisition opportunities, I think the Ivanhoe deal we did in California is a good example of other things that we would consider. We are certainly not limiting our acquisition opportunities to the Marcellus.

Could it be some type of greenfield acquisition in a basin that's not part of your core properties,?

I wouldn't rule that out, but I wouldn't say that it is likely either.

Okay.

It would have to be a fairly compelling opportunity for us before we would move entirely into another basin, and have the scale we need and at the price we need to enter the basin. But I agree, Matt's right. We wouldn't rule that out at all.

Fair enough. In terms of your extensive acreage and accelerating the present value of your Marcellus position, would you consider doing another JV with another operator or some type of farm out? Does that cross your thinking at this point or is that not on the table?

Yes. It's certainly something we will consider. However, our goal at this point is to get a better understanding of our overall position. That is what the purpose of the vertical exploratory wells was and the initial horizontals that we'll drill in some of those areas. Based on that, we may determine that there are particular areas where it makes sense to partner, and other areas where it does not.

Fair enough.

It's unlikely to be as large a scale joint venture as the EOG deal.

Right. And then in terms of your vertical wells, have you been stimulating those wells or have they been just flowing naturally? Can you talk about some of the economics you are seeing there?

Those are not completed wells. Those wells are drilled, logged, in many cases we cut conventional core, five out of the seven to date. We evaluate the rock and we save the well as a monitor well for a future horizontal, but we are not completing those wells.

Okay. I guess Cabot was talking about some of their acreage, probably not prospective for horizontal drilling, and it may make more sense to do vertical wells.

My read on that is that the reason it was not prospective for horizontals had more to do with the shape of the piece of acreage, that they just couldn't locate a horizontal on it. Maybe I'm wrong about that but that was my understanding of it.

Okay.

And certainly there will be places on our acreage where we may find that same limitation, and we will use verticals to produce those areas, but we are not at that stage yet.

Okay, and then just one more if I may. In terms of number of wells you plan to drill over 2010 and 2011 in the Marcellus, has that changed at all? I think you had five operated wells in 2010, and 20 joint venture wells and seven operated in 2011, and 30 joint venture wells in 2011. Is that still the same?

Let me answer it this way. In 2010, we are planning 20 joint venture horizontals, and at least 15 Seneca-operated horizontals, but potentially more than that.

Great. Great quarter guys, thanks.

Thanks.

Your next question comes from the line of Carl Kirst with BMO Capital. Please proceed.

Good morning, everybody. First, I just had a clarification for Dave as I was kind of running down my notes. Did you say the, on the West to East Pipeline, the first stage west of Leidy, that potentially could be done as early as 2011? Would that be the 80-mile stretch $250 million of capital that you were referring to?

Yes, that 82-mile pipe I talked about, that's directly west of Leidy, with people wanting to get to Transco and Texas Eastern there. In the West to East discussions that has been an area of very intense interest, and it's clear to us that there is a need there. yes, that could be, as I said, that might be done in the first 32 miles, and then thereafter, or. Potentially up to an 80-mile pipeline running back to one of our major pipelines, which would bring all of our storages into play as well.

Okay, but right now within the fiscal 2010 CapEx budget, there isn't anything allocated yet for that, potentially?

No.

Okay. Matt, if I could, just a couple of other clarifying questions. On the, with respect to the risked resource, the EUR of two to three B's, it sounds like then and again, it is going to vary quite a bit, but the weighted average IP rate is probably then going to be roughly in the 2.5 million range, what we have seen average right now or would it be higher or lower than that?

Oh, I think that's probably a good assumption, Carl. I think we have to be a little careful, assuming that IP rate times 1000 is always your EUR. But as a rule of thumb for a statistical average that's probably a good bet.

Can you share with us any of the more specifics on the latest two wells? Everything, I know you said that the D&C was a little over $5 million. But with respect to frac stages, for instance and what the, I guess the EUR's of both of those wells kind of in the two to three range we think at this point?

Well, let me put it this way. All four of the wells, so all of the wells that we've ,the last four consecutive horizontals have had our estimate of the EUR ranges from 1.9 to 3.5 Bcf. So they all fall within that range and I think the two most recent are in the middle of that range.

Okay. Did the two most recent also have a 12 frac stage? I guess I'm just trying to get to, have you been changing the formula at all experiment?

We tend to, we, by we I mean collectively with EOG, we tend to experiment with one change at a time. So that we can evaluate what that one change does. It hasn't been the frac stages have tended to be similar, but of course they vary by lateral length. The other tweaks are probably all things that I don't feel like I would want to discuss publicly.

Fair enough. And then last question, if I could. I guess with respect to the number seven, I think it was an IP rate of the 3 to 3.5. Do you have a sense of what the 30 day rate is? I guess I'm trying ultimately to get to what your current thoughts are, on a type curve for the recent wells you have.

Let me answer that in two parts. You notice the range there. That was a three day IP.

Yes.

...and the high was 3.3 million. That well was the one we announced as being 3 million a day over a 25 day period. Did you follow that?

I did, I did. Okay, I thought the 3 million a day was a 7 day rate. So that is why I was trying to dead reckon that.

Is that the way we announced it? As a 7-day rate? I'm sorry. I'm going to take that back. I think it was maybe a 10-day rate but I don't remember exactly how many days, but it's the same well. It was 3.3 million over three days and it was 3 million over I think it was ten days.

Okay. We can clarify that off line. But with respect to just a generic type curve?

Yes. The generic type curve what we are using is something very similar to what you are seeing from Chesapeake. They have published one.

Right.

I think Tudor Pickering has one that's similar to that as well. So not greatly different than the others you are seeing.

Great. Thanks, guys.

You're welcome.

Your next question comes from the line of Ray Deacon with Prichard Capital. Please proceed.

Good morning. I was wondering, could you talk about the sixth horizontal with EOG. Is that, it sounds like you haven't released results of that one yet? Is that?

The sixth horizontal?

I guess I was just wondering what is sort of, what would be the new rate here, I guess, today, if you are putting any out, from the EOG JV.

Oh, okay. Well let me answer it this way. There is the four consecutive wells that ranged from three day IP's from 1.4 to 3.3 million. I guess I would say the most recent one was on the order of 2.5, but I don't have the exact number here at my fingertips, Ray.

Okay. That's fine. I just got off the EOG call, they talked about moving aggressively to build out the production infrastructure surrounding the program with you guys.

Right.

I guess I'm just trying to back in that. What is, you have put out a production estimate for the end of this fiscal year. Have you said anything about the end of next year? Where you think production could go?

Yes. Actually I think I said it in my comments. That I expect to exit 2010, that 20 to 30 million a day in 2011, our fiscal 2011 at 50 to 70.

Okay. Got it. Great. And I guess just one more. Are you, can you talk a little bit about the Ivanhoe acreage and the potential there, will you be putting capital into that, and I guess any plans to test any exploration prospects that might have some relationship to this Oxy discovery?

Sure, our primary purpose of the acquisition was to buy the producing properties where we see opportunity to improve the production there, and add reserves through efficient steam flooding. Now, that said, there is some deep potential, but we are not talking about a huge amount of acreage. So yes, we potentially have some opportunities that are arguably of a similar horizon to what Oxy is chasing, but again, it's not that a big piece of the value.

Okay. Got it. Thank you.

Your next question comes from the line of Mark Caruso with Millennium. Please proceed.

Morning guys, almost good afternoon. I've just got a quick clarification question actually for you, Matt. One, when you gave the resource estimate, is that just your Pennsylvania acreage? Or is that a combination of your Pennsylvania and New York?

Well it's a combination, but we have very little prospective acreage in New York in the Marcellus. That's largely Pennsylvania.

Okay. Then the second question; I know when John asked a question, you are open about JVing and there seems to be some stories that you have looked at acreage in New York. I didn't know if there was any update on that?

No, there is no update on that at this time.

Got you. Great, thanks.

(Operator Instructions). Your next question comes from the line of Faisel Khan with Citigroup. Please proceed.

Good morning. It's Faisel with Citigroup.

Good morning, Faisel.

How are you doing?

Good.

I just wanted to understand the 2010 drilling budget you guys have, I think it is $150 million to maybe $182 million. Most of that 75% of that is going to be toward the Marcellus?

Yes.

Okay. Got you. And that is 20, that includes 20 joint venture horizontals and 15 Seneca operated horizontals and potentially more?

Right.

What would change? What would get that number up higher? What has to happen to make that number higher?

Two things, in terms of capital or in terms of number of wells?

I guess both.

In terms of number of wells two things can happen,one is we can add rigs sooner, and the other is we can drill wells faster. I think I mentioned that we drilled that first lateral in 17 days. Now, if our drilling department, which did an outstanding job with that well, continues to perform as effectively as they did there, well we'll just drill more wells with the same number of rigs.

Now the second thing, which would add both capital and well count, is if we bring in our planned rigs a little sooner. Right now, we are anticipating a second Seneca operated rig, probably around January or February and a third one possibly by July, which if we brought them in any sooner than that, obviously we'd increase that well count. Of course the other thing is whether EOG accelerates it a bit, they have moved to a two rig program. So we are just starting a two rig program. So potentially they could drill more than 20 wells also.

Okay.

Faisel, just a clarification. I'm not sure if I heard you. But it's 75% of the East Division's budget will be focused on the Marcellus. It's more like two-thirds of the overall capital budget if my recollection is, is that right, Matt?

Right.

I think Faisel said 75% of the total capital budget in the Marcellus and it is really more like two-thirds? I just want to - -

Oh, yes. Right.

Got you. So I take it with this kind of 35 wells sort of program here in 2010, for that matter 2011, you have identified all these locations? Is that fair to say?

So, the 35 wells we would drill in 2010? Well, let me put it this way, Faisel, we have identified many locations to drill. Which wells we drill in which order is a moving target,nd it depends on what we see from our vertical program, depends on permitting issues, depends on gathering system issues, and it depends on what we learn as we drill the horizontal wells.

What are the major hurdles for permitting? Is that an issue? Or are those permits pretty easy to get?

I wouldn't say it's an issue that's going to cause us not to drill wells. But depending on water disposal, water sourcing, and disposal issues, potentially it could take 60, 90 days, or even a little longer in some cases to get a permit. What that means is, we don't necessarily have complete flexibility to say I think I want to drill this well a little differently than I originally planned it. So something could come up. Say we get a seismic line across a location that we had planned and we see a fault we hadn't anticipated originally, we may need to change the surface location or change the lateral length, and that may take some time to re-permit. Consequently, we would go drill a different well.

Okay. In terms of the ramp up of production, the 20 to 30 and then 50 to 60 Mcf a day by 2011 from Marcellus production, are those net volumes to you?

Those are net volumes to us.

Okay.

Matt, you have lag times in there to hook those wells up, right?

Right. In other words, what you can't do is assume; okay, I drilled a well here, that well is going to be online next month. There is a lag both to get a frac crew there, get the well fracked, and get it online.

Okay, got you. And in terms of the Midstream infrastructure take this gas to market, is that part of the program that you guys are developing? Or is that something that you foresee as being any sort of hurdle to getting these volumes to market?

It is a hurdle. And to some degree, looking at the take-away options in a given area affects where we are going to be drilling. So yes, that's all part of the puzzle in terms of where we focus our efforts.

Got you. Is there a specific sweet spot within your guys acreage position that you have identified at this point?

Not at this point, no. We do have an area with EOG that we are focusing on in the joint venture development. But I wouldn't necessarily call it an unusual sweet spot relative to the rest of our acreage. It's just a logical place to really get going.

Okay. In terms of the composition of the gas on your acreage versusif you go farther south where there has been a lot of announcements of Marcellus production. Does the composition of the gas change at all as you move from the southwest towards your more northern acreage?

Oh, yes, it changes dramatically. That area down to the southwest where Range for instance, is very active, is very rich gas and needs to be processed. So far where we are active, the gas is dry, doesn't need a lot of processing, so it's much simpler to get it online. Now that said, we are not sure about all of our acreage yet. There probably will be portions that do need some processing, and that's part of what we are learning as we go forward with our sort of exploratory program.

Got you. You did say that you anticipate making some reserve booking? By the end of the year?

Yes.

Would that just be based on your program? Or is there spacing?

No, it would just be based on what we've drilled. Potentially, there would be some immediate offset PUDs. But until we sit down and discuss that with Netherland Sewell, I'm not sure what that will look like yet.

Okay. Got you. On the Ivanhoe acquisition, what do you guys see as peak production for those assets? I think you said it was producing a few hundred, 600 barrels of oil a day?

Yes, about 650 for the whole package and 600 of that is from Midway Sunset. I guess I'm not prepared to give an estimate of the peak production at this time, Faisel.

Is it fair to say there is upside to the current production?

Yes.

Okay, got you. All right guys, I appreciate the time. Thank you.

You're welcome.

You're next question comes from the line of Holly Stewart with Howard Weil. Please proceed.

Morning.

Morning, Holly.

Just two quick ones here. First, Matt, can you give us an estimate, I know you are talking about kind of the production rates that you expect from the Marcellus in 2010 and 2011. Can you just give us an estimate of where you think you are going to be at the end of this year, so FY 09? Just so we can get an idea of - -

Virtually nil.

Virtually nil, okay.

That is just a gathering system issue.

Okay. And then, also can you give us an idea, in Tioga County, we have heard, I guess the beginning of this week, about UPL's recent wells. Where is your acreage in relation to theirs?

Well I know where ours is, I'm not certain I know where the UPL, in their announcement is it clear where their wells are?

I'm actually not sure. I don't think so. But - -

Yes, I know they have a fairly big position in Tioga County so I'm not certain where those wells are.

Holly, I think they are a little bit east of us, maybe a little bit south, too. I mean in the same general ballpark. But I think they are a little further east.

Okay. All right. Thanks, guys.

Thanks, Holly.

Your next question comes from the line of Jim Harmon with Barclay's Capital. Please proceed.

Howdy.

Hi Jim.

I'm down to one question because everyone did such a good job asking you. But if I look out two, three years, is there any reason to think that you guys would still want to be in the Gulf?

No.

Well, if we are at that point in time, because we are not really putting any exploratory money in the Gulf. It's likely we'd either sell out of it or produce out of it. So it's fair to say we are de-emphasizing that and it's fair to say we are unlikely to put much more capital in there. I didn't mean to jump in so quickly, Matt.

No, I think that's a good answer, Dave. That's probably the right way to look at it. Is we are not spending a lot of money there, so whether we are still in the Gulf or not two to three years from now is maybe not so much the right question as to whether it's going to be an important part of our business or not.

Yes, that was the initial way I had it phrased but I guess from conference call critique, I asked it a different way. Thank you very much.

Thanks, Jim.

Your next question is a follow-up question from the line of Carl Kirst with BMO Capital. Please proceed.

Thanks, I appreciate the time. Just a couple of quick follow ups. This actually goes back to the reserve issue. Matt, what do we need to see, as far as to, aside from more drilling, the number of wells perhaps to get some comfort of actually seeing a migration into a 3-P bucket. Apart from obviously what's going to be booked with the producing reserves this year, is it something that by the time we get to January, February, we'll have enough of an idea we might actually start seeing some migration into the possible bucket?

Sure, we may see that. But Carl, I just caution you to what your expectations are. You know standard reserve booking doesn't allow you to book possible reserves more than a couple of offsets away from existing producing well. So, it ispossible is not going to be a big number until we have a lot of wells drilled.

Fair enough. Then last question, if I could. As you guys project forward in kind of a fully developed program and then perhaps with the pad drilling, we have gotten our well costs down to $3.5 to $4 million. And understanding this is a little bit of fun with math and fun with numbers right now, but, as you guys apply your type curves, etcetera, where do you think a gas net back has to be, in order to make this go versus uneconomic? Is it $3, is it $4? Any help there would be appreciated.

Let's do it this way. On our acreage where we have basically 100% interest, we are paying no royalty, which is the vast majority of our acreage.

Okay.

A 2.5 Bcf well looks pretty darn good at $4. I don't think we have really analyzed it below 4. And at 2 Bcf well, you're still making money at $4.

Great. Thanks, guys.

Thanks, Carl.

Your next follow-up question comes from the line of Ray Deacon with Prichard Capital. Please proceed.

Yes, I was just wondering. Have you updated your thoughts on the vertical program, the shallow Devonian shell program, and can you do the same math in terms of returns, the $4 gas there? Does that place still make money?

I don't have the numbers at my fingertips like I did for the Marcellus, Ray, but at $4 the Upper Devonian, you are not really losing money. But you start questioning whether you should be drilling a lot of wells, if your expectation is to be at $4, in the future. $5 looks a little better. But the thing that happens is, if we look at our overall inventory, certain of the wells and even areas will fall off the chart at $4, and at $5, some of those come back on. Obviously, at $6 the vast majority of what we have in inventory looks good.

Ray, one of the reasons we have that broad range in there in the E&P budget has to do with pricing. So to the extent that prices recover, we are likely to drill more than 150 Upper Devonian wells.

Okay. Got it. To stay to over five I guess would be the way to look at it. Then just one more question is, I'm looking at the Chesapeake type curve. I mean they are talking about 4.2 B's. Is what you are saying you think a fairly large portion of the acreage, can kind of fall into that bucket of four Bcf wells?

I don't know that I'm prepared to make that conclusion. Keep in mind we have a pretty broad area we cover with our acreage. And some of it is frankly thinner than it is, in some of the other places. So, I think what I said was, our resource estimate is based on averages that are from 2 Bcf to 3 Bcf for the average across our entire position. So yes, there may be places where we might be at four. I would use that decline curve as an estimate of the decline rate and the shape of the curve, less so than for an EUR.

EUR. Got it. Okay, great, thanks very much.

Okay.

Your next question from the line of Shneur Gershuni with UBS. Please proceed.

Hi, Shneur.

Just one last follow-up. It may have been asked and answered and I apologize. Do you have anything close to a 30 day average for your wells at this point right now?

Shneur, the majority of them we haven't flowed that long. The first one we announced, which was, I think we announced 1.4 million a day over what was that? A 25 day period? I already had trouble remembering the other one earlier in the call. So I'm a little hesitant to guess.

25.

It was 25.

25 day period.

Okay. All right. Thank you very much.

Thanks, Shneur.

Your next question comes from the line of Christopher Heinz with Perennial. Please proceed.

Good afternoon, gentlemen.

Chris, good morning.

Will you guys be providing any kind of follow-up detail on the four to eight TCF estimates at Marcellus Shale potential? Or is this all we are going to get?

That's all you are going to get right away. Do you have a specific question?

Chris, I think Matt did say that as more information develops, we would be putting out updates with respect to that.

Any sense for what the time line for those would be?

I'm sorry. Is it something that maybe I've already answered. We said the weighted average risk factor is 30% to 40% and the weighted average EUR is 2 Bcf to 3 Bcf. Was it something more than that you are looking for?

No, I guess that's good enough for now. I guess I was just looking for a sense for timing as to when we might have greater specifics than that and still a wide range? I know this is a long process, but maybe you could help me with that?

Yes, I would guess that the range of resource potential is something we'll update you know, periodically. I don't know how often, might be once a year first several years. Because as we continue to drill this program, we are going to learn more and more.

Okay. All right thank you.

Thanks, Chris.

Your next question is a follow-up question from Jonathan Lefebvre with Wells Fargo. Please proceed.

Hi, guys. Just one quick one. Since we are talking about economics, I think your California assets are pretty attractive, especially in this crude oil environment where we have a big disparity between the crude to gas ratio. Can you just remind us of what the economics are like out there? And kind of where is the break even on a NYMEX crude oil price and given the forward curve, maybe what type of returns you earn today?

Sure. We do well on our production out there at anything north of probably north of $20 NYMEX. We are still making money on our production. Now on the drilling that adds additional production, most of those projects require, let's say, $50 NYMEX.

Great.

Does that help?

Yes, thanks.

At this time I would like to turn the call back over to Mr. Welch for closing remarks.

Thank you, Stacey. We would like to thank everyone for taking the time to be being 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 will run through the close of business on Tuesday, September 8, 2009. 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 passcode 79992917. This concludes our conference call for today. Thank you and goodbye.

We thank you for your participation in today's conference. This does conclude your presentation. You may now disconnect and have a great day.