National Fuel Gas Co (NFG) 2010 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the fourth quarter 2010 National Fuel Gas Company earnings conference call. My name is Shantalay, and I will be your facilitator for today's call.

(Operator Instructions).

As a reminder, this conference call is being recorded for replay purposes. I would now like to turn the presentation over to your host for today's call, Mr. Tim Silverstein of Investor Relations. Please proceed, sir.

Thank you, Shantalay, and good morning, everyone. Thank you for joining us on today's conference call for a discussion of last evening's earnings release. With us on the call from National Fuel Gas Company are Dave Smith, Chairman and Chief Executive Officer, Ron Tanski, President and Chief Operating Officer, and Dave Bauer, Treasurer and Principal Financial Officer. Joining us from Seneca Resources Corporation is Matt Cabell, President. At the end of the prepared remarks, we will open the discussion for 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 earning release for a listing of certain specific risk factors. With that, we will begin with Dave Smith.

Thank you, Tim, and good morning to everyone. The fourth quarter was another very good quarter for National Fuel, as you read in last night's release, operating results for the quarter were $32.4 million or $0.39 per share, which was right in line with our expectations. Compared to the prior year's fourth quarter, operating results for the Company were up $0.02 per share, despite the fact that E&P earnings for the quarter were down slightly due to an income tax related adjustment. Excluding that adjustment, Seneca's earnings for the quarter were up 10% over the prior year. Fiscal 2010 was also another very good year for National Fuel. Operating results for the fiscal year were $219.1 million or $2.65 per share, an increase of $8.7 million or $0.05 per share.

Perhaps more importantly, fiscal 2010 was a year in which we made considerable progress on a number of strategic fronts. With respect to our Marcellus program, when we started the fiscal year, Seneca was in the very early stages, having just drilled its first two Seneca-operated horizontal wells. By the end of the year, Seneca was a seasoned operator having drilled another 29 horizontal wells, and having grown it's daily Marcellus production from virtually zero to 53 million cubic feet per day. Matt will review our Marcellus program later in the call, so I won't go into any further details.

There are, however two clear takeaways from our 2010 Marcellus program. First, given our recent well results, and given EOG's recent well results, our acreage, both in the Eastern and Western Development Areas is of very high quality. Second, our team at Seneca, which incidentally we have expanded significantly over the last year, has the necessary capacity and expertise to fully exploit this vast asset. So we are excited about the progress we have made in the Marcellus in 2010, and we look forward to continued success in fiscal 2011.

Despite the decline in natural gas prices in recent months, we remain committed to spending between $380 million and $425 million on our Marcellus program in 2011. Even at $4.00 gas prices, our returns are still very, very attractive. It's also relevant that the 100 to 130 well program we anticipate is only a very small fraction of our total Marcellus drilling inventory. While we are pleased with our results, and with EOG's joint venture results, we are open to opportunities to grow the program at even faster rate.

To that end, we have retained Jefferies & Company to help us explore joint venture opportunities. Now at this point, we are still very early in the process. In fact, the only reason we made the announcement as early as we did, is because of our concerns over Reg FD and the risk of selected disclosure. That said, while there is not much that we can, or frankly should disclose, regarding any potential transactions, we can say that we are pleased with the level of interest expressed to date by potential partners. And we are hopeful that we'll complete a significant transaction within the next three to six months. However, as I've said in the past, we will only do a joint venture if it adds to shareholder value in a very meaningful way.

Before leaving the E&P segment, a couple of comments on Seneca's other divisions. In the West, our team has been a great job of keeping production basically flat compared to the prior year. Our California oil properties are a terrific assets that are sometimes overshadowed by the Marcellus. They not only provide a nice oil and natural gas balance, they also generate considerable free cash flow, over $100 million in 2010, which funds a large portion of our Marcellus program. In the Gulf, fiscal 2010 production was down 3% from the prior year, which was expected given the limited amount of capital we committed to that division. As we have said over the last two years, we will continue to deemphasize operations in the Gulf.

Turning to the regulated segments, our Utility had a very another strong year, posting $0.76 per share of earnings, up $0.03 from the prior year. From an earnings perspective, our Pipeline and Storage segment struggled a bit this year, mostly because of higher operating expenses and the persistently strong pricing basis at Niagara, which has made selling import capacity from Canada difficult. We expect these trends will continue through 2011, but then quickly reverse in fiscal 2012, as our Line N, Tioga Extension and Northern Access projects come online. Each of these projects is proceeding according to schedule, and Ron will have more to say on each of them later. As we've said in the past many times, our regulated operations, which are much less sensitive to commodity prices, provide stable, reliable earnings and cash flow, and are the foundation for our long-standing dividend.

Lastly, this quarter we made good progress this quarter in divesting our smaller non-core businesses. We sold our landfill gas operations for a small gain, and sold what I will call our retail timber operations, basically our sawmill at a break-even price. We will continue to pursue the sale of our gas-fired generation business, and we'll keep you posted as that transaction develops. In closing, fiscal 2010 was a great year for National Fuel, both financially and operationally. We made great progress particularly with regard to our opportunities in Appalachia, and look forward to continued success in 2011. Thanks for listening, and I look forward to seeing many of you our Analyst Day in New York next week. With that, I will turn the call over to Ron Tanski. Ron.

Thanks, Dave, and good morning, everyone. As Dave said, operationally we had a very good 2010 fiscal year, and we've entered fiscal 2011 in great shape. In the Utility we were on track with all our major capital maintenance projects, and we were also within our budget. Going into the winter heating season, the Utility has 97% of it's gas storage capacity filled which is just where we planned to be. Anna Marie Cellino will go over more of the Utility details at our Analyst Day next week in New York, so I don't need to say anything more here.

In the Pipeline and Storage segment, we completed all the pipeline integrity and maintenance work that we had planned for the year, with the exception of a small amount of work on storage wells that we moved into fiscal 2011. All the work that was done came in pretty well on budget. Now because we changed the timing on the West-to-East Project to a 2013 project, our spending on our expansion projects was behind our original projection by approximately $11 million. In addition, a number of the compression projects were moved to fiscal 2011, to more closely coincide with the timing of our customer contracts.

The schedule for our expansion projects was laid out on page 37 in the IPAA OGIS presentation that you can find on our website. And I'll review the status of those projects next week in New York, as well. In addition to Distribution Company having 97% of it's gas in storage for the upcoming winter, all of Supply Corporation's other customers had their contracted storage space filled up to the 98% level. So we are in good shape to meet our customers winter supply requirements.

Funding in our Midstream business was $39 million less than we had initially projected. One third-party producer put a major project on hold, as result of a pending M&A transaction, and another project went to another contractor. Also the commencement of the Trout Run Gathering System in Lycoming County for Seneca's production from the Lycoming County DCNR Tract 100 was delayed until Seneca had a successful test well drilled on the tract. The logistics for the Trout Run Gathering System are also a little bit more intricate than they were for the Covington System. We are working on those issues, and expect a line to be operational next fall. Matt will cover most of the operational highlights for the Exploration and Production segment.

From the spending side, our spending there was ahead of schedule, due to the early arrival of Seneca's fourth drilling rig, the acceleration of some drilling and well fracing by EOG in the joint venture, and the running of additional seismic lines across Seneca's acreage. Most all of that additional activity occurred during the last quarter, and we're still waiting for some of the actual billing from the contractors. But as we noted in the capital expenditure table on page 22 of the release, we accrued an additional $55.5 million to cover the cost of those activities.

We had another good year in our Marketing segment. Although overall sales volumes were down, the volume decrease was from NFR's lower margin wholesale customers. With lower gas prices last year, margins in the other customer classes improved. Now I'll turn the call over to Matt Cabell for the discussion of the E&P segment.

Thanks, Ron. And good morning, everyone. It was a good quarter, and a great year for Seneca. Total net production for the fiscal year was 49.7 Bcfe, an increase of 17% versus last year. We finished the year with 700 Bcfe of proved reserves, which means we replaced 445% of our annual production. Our California, Gulf of Mexico, and Upper Devonian production stayed relatively flat, while our Marcellus production grew by 50 million cubic feet per day over the course of the fiscal year.

Now let me provide some detail from our Marcellus operations. In the Tioga/Potter/Lycoming County area, or what we call the Eastern Development Area, we have now drilled 31 horizontal wells, 13 wells are producing at about 60 million cubic feet per day, that's a gross rate. Three horizontal rigs are active in the area, and we are currently fracing on one pad, while we bring on new production at another. Our average IP in Tioga County is just under 8 million cubic feet per day. As we announced in late September, we have tested our first well in Lycoming County at a rate of 15.8 million cubic feet per day on a 28/64" choke. We think this well is capable of an even higher rate.

Our Midstream group, as Ron had mentioned, is acquiring rights-of-way and surveying for a gathering system that will bring production from this block south to Transco. Construction will begin in the spring, with first production expected next fall. We have about 85 well locations laid out on this 9,000-acre block in Lycoming County. Across all of the Eastern Development Area, we have over 50,000 net acres and over 2 Tcf resource potential.

Much further west, in Elk County, we have just begun drilling near on a three well pad near a well that we IP'd at a 3.9 million cubic foot per day rate. One of our goals for these three wells is to determine the ideal landing zone for the horizontal wellbore. Based on our analysis of various rock properties, and results from fracs across our acreage, we believe that landing a lateral in the ideal zone can have a significant impact on well results.

Regarding our joint venture with EOG, we have had some great results in the past two months. EOG has now tested four wells that used 5.5 inch casing, and a higher pump rate. These wells tested at an average IP of 8.2 million cubic feet per day. This is a very significant improvement over the previous wells in this area which had IP's of about 3 million cubic feet per day. Current infrastructure constraints are limiting our production in this Clearfield County area, but we expect the bottleneck will be fixed over the next couple of months.

We were very busy the last two months of the fiscal year. We added a fourth rig, and initiated an intensive multi-well fracing program. Meanwhile, EOG, ramped up their fracing activity as well. Due to this burst in activity, we outspent our capital forecast, and finished the year at $398 million for all of Seneca, $332 million for the Marcellus. The results of this activity are apparent in our substantial reserve additions, our year-end Marcellus exit rate of 53 million cubic feet per day, and our company-wide finding and development cost of $1.80 per Mcfe.

Moving on to the West Division, our California oil production continues to provide steady revenue and cash flow. For fiscal 2010 West Division operating cash flow was approximately $130 million, while capital spending was only $28 million, leaving $102 million of free cash flow to redeploy in the Marcellus. Looking forward to fiscal 2011, we will spend about $40 million to $45 million to drill 50 development wells, including two five-acre infill wells at our Sespe Field, which, if successful, could lead to a multi-well infield program across much of the Sespe Field.

In the Gulf, we only drilled one well in fiscal 2010. However, with that new well and first production from our Eugene Island 383 discovery, which came on at 10 million cubic feet per day, Seneca has a 30% working interest. We are managing to keep production fairly steady, and expect only a modest decline over the course of fiscal 2011.

All in all, fiscal 2010 was a great year for Seneca. We are fortunate to have steady cash flow from our legacy producing assets, as we continue to execute our Marcellus growth plan. We have an outstanding acreage position, a great team, and a very bright future. Few E&P companies have an opportunity as economically attractive as Seneca's position in the Marcellus Shale. Due to our large fee mineral ownership position, we have a much higher net revenue interest than any of our competitors, and consequently a lower break-even cost. We have worked hard to quickly become one of the best operators in the basin, and are now the industry leader in Marcellus production per well.

Also our 745,000 net acres in the heart of the Marcellus provide shareholders with the largest per share exposure to the basin of any Company. Perhaps most importantly, we are not faced with expiring leasehold, and can develop our acres as we see fit. Our Marcellus production has grown from next to nothing a year ago, to 60 million cubic feet per day today. Our growth plans for fiscal 2011 are aggressive but prudent, and driven not by a need to hold acreage, but only by the outstanding economic opportunities that we possess. With that, I'll turn it over to Dave Bauer.

Thank you, Matt, and good morning everyone. As Dave said earlier, the fourth quarter was a good one for National Fuel. Our consolidated earnings of $0.39 per share were right in line with our expectations. Yesterday's release does a good job explaining the major variances in earnings for the quarter and fiscal year, but I want to add some color to a couple of items. First, in the Utility segment, O&M expense for the quarter was down $1.1 million from the prior year, mostly due to a $2 million adjustment that reduced our allowance for doubtful accounts. This past winter the gas cost component of our Utility customers bills was about 25% lower than it was in the winter of 2008 to 2009, which in turn naturally led us to record a lower level of bad debt expense for the 2010 winter. Our bad debt expense typically averages about 2.25% to 2.5% of our retail revenues.

Given the state of the economy, we took a pretty conservative approach to our bad debt accruals for the first nine months of the year. When we reached year-end, our accounts receivable aging was better than we expected, which led us to reverse some of the expense we had recorded earlier in the year.

Turning to the E&P segment, Seneca's G&A expense for the quarter was down a little more $600,000 from the prior year. In 2009, we had accrued a bad debt expense related to receivable from a refinery that have filed for bankruptcy protection. When the bankruptcy proceeding was resolved in the fourth quarter of 2010, we ended up collecting about $2.5 million more than we had expected, and therefore reduced our bad debt reserve by that amount.

Excluding that recovery, Seneca's G&A expense was up about $2 million for the quarter, which was driven in large part by the continued growth of the East division. Going forward, we are still comfortable with a $38 million to $41 million range for fiscal 2011 G&A expense for Seneca. Seneca's DD&A rate for the quarter was $2.10 per Mcfe, which is down from the $2.15 rate for the first nine months of the year. This drop is the direct result of Seneca's significant year-end reserve additions, which as Matt said were recorded at considerably lower F&D cost, than the composite full cost pool. Looking to fiscal 2011, we now expect Seneca's DD&A rate will be the range of $2.05 to $2.15 per Mcfe.

Lastly, as you may have noticed in last night's release, our effective tax rate for the quarter was a bit higher than in recent quarters. And this was caused by a change in Federal tax law that was enacted in the fourth quarterand had the effect of increasing our book tax expense for the entire year. Looking to fiscal 2011, we are expecting our consolidated effective tax rate will be consistent with the fiscal 2010 annual rate of about 38.5%. Turning to our forecast for 2011, we are revising our earnings guidance to reflect an assumed NYMEX natural gas price of $4.00 per MMbtu, which is in line with the current strip.

Our new earnings guidance is $2.40 to $2.70 per share, which is $0.20 lower than our previous guidance. This decrease is entirely attributable to the $1.00 drop in our natural gas price assumption, and really shouldn't be a surprise. The sensitivity table we included with our initial earnings guidance, indicated that a $1.00 change in NYMEX natural gas prices would reduce earnings by $0.19 per share. And the remaining $0.01 per share difference is simply rounding to the nearest $0.05.

Our consolidated capital budget for fiscal 2011, which is now final, is $605 million to $740 million, and is spread across the segments as follows, $55 million to $60 million in the Utility segment, $100 million to $150 million in the Pipeline and Storage segment, $425 million to $500 million in the E&P segment, and $25 million to $30 million in the Corporate and All other segments. I would add, that substantially all of the Corporate and All Other spending relates to the Lycoming Gathering System that Ron and Matt mentioned earlier.

Using the midpoint of our earnings guidance and capital budget, we expect CapEx will outpace operating cash flows by about $110 million in 2011. But we have cash on the balance sheet, and ample short-term lines of credit in place to handle that spending, including over $400 million of bilateral lines of credit, and a $300 million committed credit facility. We plan to use cash from our balance sheet to fund the $200 million of long-term debt that comes due later this month. After that, our next maturity of $150 million is in November of 2011. At this point I expect we will refinance that maturity with a new issuance next fall. With that, I will close and ask the operator to open the line for questions.

(Operator Instructions).

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

Good morning, guys, Nice quarter.

Thanks, Jon. Thanks.

I just wanted to start out on the JV, and the Marcellus, maybe just touch on it if you can, and I know it's probably still early and you are limited as to what you can say, but just in terms of the size of the package, acreage value, and maybe timing. And just taking those in reverse order here, in terms of timing, you outlined a three to six month kind of time frame. If we start pushing up against the six month type of area, is a reason to believe you may shelf this, or pull it at that time? Can you maybe highlight that?

Jonathan, I think in terms of the timing of it. In part, we gave ourselves a pretty broad range there. And part - it will depend, I mentioned we have a lot of interest. There are certain opportunities to move fast if -- a lot of it will depend on the partner that we select. So it could be before three months. It could be over six months. But, unless we don't get the kind of value that we are looking for, it's our expectation that we will move forward with the joint venture, and not pull it. I guess at the end of the day, the timing doesn't matter as much to us as the value that we receive for the package, for the acreage.

Understood. You mentioned that it was going to be a significant joint venture. Maybe could you help us understand what you mean by significant -- in terms of size? I mean, this is not going to be just a floating kind of minority interest? It sounds like you want to do something more transformative?

Jonathan, this is Matt. We are looking at a minority interest, but it is a minority interest across our entire position, which when you consider how larg our position is, a minority interest can be quite significant. We haven't set a definite percentage, and that will depend on the negotiation.

Understood. And then just maybe on the acreage values, we are seeing a little bit of a public deals, more in the $9,000 to $10,000 per acre, maybe private deals on the five to six. Any reason to believe we might be below that lower bound?

I don't think we should comment on the price.

Yes, we are aware of the values out there, Jonathan. We know what the acreage has been selling for. We are pretty comfortable with the position we have. We are pretty comfortable with the -- I think one of the big advantages we have a such a contiguous block. Many of the other joint ventures our there are having difficulty meeting their minimums. Our acreage is so contiguous, we don't have the royalty issue now, so we are pretty comfortable, we feel pretty comfortable about it. But I don't think we should comment on the value.

Understood. And then just lastly, and I will jump back in queue. The EOG wells, very nice wells that they put up in I believe it was Clearfield. I mean does this say anything on your opinion, on your Western acreage? Is there any read through there that we should be making?

Oh, sure. It says a lot. You are looking at wells that are very close to --they're on -- they may be on the Clearfield County side of the entire position, but it's not distant from really any of our big chunk of fee mineral acreage. So these are the first wells that are landed in what we think is the ideal zone, and fraced at a high rate and we're getting 8 million a day. Very, very positive results as far as we are concerned.

So you think the learning there that are very transferable you're Western acreage, there is not a big difference between the geology, between the two areas?

Just to be clear, the wells we've drilled on the western-most part of our acreage we did drill with 5.5 inch casing, and fraced at a high rate. I think the piece of the puzzle that we still need to completely unravel, is the ideal landing zone. And our program for fiscal 2011 includes a significant effort to determine that ideal zone, and see exactly what rate we'll get when we are in that ideal zone. Now all of that said, we are confident that we are going to see better and better results as we continue to tweak the program.

And Jonathan, just this Clearfield acreage is in what we consider to be our Western acreage.

Understood. Okay, guys. I will see you on Tuesday next week. Thanks.

Thanks.

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

Hi. Good morning, gentlemen, and congratulations on a strong year.

Thanks, Kevin.

Matt, in your prepared remarks I think you mentioned you have 745,00 net acres -- did you guys pick up 5,000 net acres recently in the Marcellus?

Oh, a little more than that. But yes, we continue to add acreage. Not any particularly large single blocks, it tends to be tracts that are contiguous to our existing position. Most of what we added over the fiscal year was in the Eastern Development Area.

Okay. Fair enough. And the other thing, can you talk about the Clearfield County gathering issues, and kind of what your pace is at is that expected to be taken care of?

Oh, a matter of weeks, or maybe a couple of months, we should see significant increase in that area.

Okay. So do you think by the end of the next quarter we are looking at -- or maybe by the end of the calendar year, we're looking at all of the wells being completed and being brought online, or is it going to be kind of --

No, it's not quite that simple. There will be -- it's going to be lumpy. We'll get this current bottleneck fixed, but then in very short order. But then, there are quite a few wells left to be fraced and put online.

Got you.. And then my last question. Can you talk about reserve bookings, and how you are viewing that in the Marcellus, and what is your practice for one PDP, how many offsets are you booking, and I guess what's kind of the reserve number you are booking as well?

First of all, let's just keep in mind that reserve bookings, as much as we like to portray it as is an exact science, it is really highly subjective. We work closely with our auditors, Netherland, Sewell,and we book it the way that they think they should do it, which in a sort of a brand-new area, we are going to tend to book just a well on either side of an existing well. But then, when we've got more well control and more production history, we might book two wells to each side, plus one on either end. Now all of that said, I guess I can give you a little more detail. We've got 93 wells booked in the Marcellus. And 47 of those, or about half of them are PUDs, but 16 of those PUDs are already drilled. So virtually two-thirds of the wells that we have booked have already been drilled. So it's a really a fairly conservative proved undeveloped booking. Does that help?

Absolutely, though I am kind of surprised, I guess, by the high percentage of the PDP. I would figure with the new reserve rules, your PUD weighting would be higher. But is that just apart of the new drilling just because you are drilling in areas that you have drilled before? Or am I looking at it incorrectly?

There's a lot of pieces that go into it, that would be one. But the other is, as you -- if you are pad drilling which we are. We are pad drilling and we're drilling areas that are all kind of close together. It's you're not able to drill a well and then book five more, because you are drilling wells that are right next to each other. Does that make sense?

Yes, I think so. Okay.

A company that may be out going to out hold acreage, may be drilling a well, and booking five in a lot of different areas. I am showing you this with my hands, but you can't see it. (Laughter).

Fair enough. I appreciate the answers. Thank you.

Your next question comes from the line of Andrea Sharkey of Gabelli & Co.

Hi, good morning.

Morning. Hi, Andrea.

I want to ask a little bit about -- I heard some other E&P companies in the Marcellus start talking about the Utica Shale. And I was curious, as to how much of your Marcellus acreage you think would also be prospective for the Utica? And I know it would be early days right now, but what maybe your initial thoughts and plans would be for developing that?

Sure, a good bit of our acreage is prospective for the Utica. And you are right, it is very early days. I don't think we can say -- I don't think we are prepared to give any estimate as to how many acres are prospective for the Utica? There are going to be places on our acreage where the Utica would be quite deep, which would affect both it's prospectivity and the and the cost to develop it. But other areas where it's at a very reasonable depth, it is highly prospective. We'll get some vertical wells through the Utica, here in the next several months. We will cut some core in the Utica, and then determine what the next step is.

Okay, great. That makes sense. And then maybe to talk about I think on your last call, you said that at $5.00 gas, 52% of your acreage would be developed. And not that $4.00 gas is here forever necessarily, but maybe could you give us an update on at $4.00 gas how much of your acreage would be developed?

Yes, just to sort of clarify what we talked about on the last call, that was a resource potential estimate. And the estimate that we used at the time, was that in kind of the middle case, or the midpoint of our resource range, it assumed that 52% of our acreage gets developed. Frankly, I don't think that would change dramatically if it went from $5.00 to $4.00. I guess I would go a step further, and say that because of the results we have had even just the last quarter, I would say that I might lean closer to the high end of that range than the midpoint.

Okay. That's helpful. And then maybe just sort of similar question or similar -- trying to get to a similar point. I know in your last presentation that you had you gave pretax IRR's, and at $4.00 gas, you still had some very high rates. I think it was over 40% for Tioga, 35% for the EOG joint venture. I am just curious is this sort of a cutoff point for you guys, where you say, the lower end of that is not acceptable, and so we are going to switch our drilling to focus more on the Tioga or the EOG joint venture versus the Seneca wells? Or I guess is there any change in kind of where you are focusing your development in the current price environment?

Let me answer it this way. The current price environment is not low enough to cause us to make any dramatic change to our plans for fiscal 2011.

Okay. I think that's about all I had. And I guess I'll just turn it back. Thanks a lot guys.

You're welcome.

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

Thank you. Good morning, everybody, and also nice results here. Just -- actually most of my questions have been hit. But maybe if you follow up in one, Matt, I wanted to go back to the reserve bookings, just to make sure I understand. So 93 wells in the Marcellus then. Conservative offset on the timing, or conservative offset. So the issue for instance - of, I know one of the SEC -- or the new SEC rules, as far as I guess wells have to be drilled, PUDs have to be drilled within a five-year timeframe. At only 93 wells booked, two-thirds of them drilled, obviously that is not a constraint. Even if we've moved into getting a JV partner, that would accelerate potential drilling potential, do you see that five-year drilling cutoff window as being a constraint on your reserve bookings, anytime in the next one, two, or three years? When does that get to be more of an issue?

Oh, I guess it gets to be more of an issue if we book, multiple PCFs.

Okay. All right. I just wanted to make sure I was clear on that. So that's helpful. One of the questions I wanted to ask, was just given over the last two months, especially with the better EOG wells landing in the right zone, I wouldn't imagine that, that in itself would impact well cost. I didn't know if you had any update there on any trends you might be seeing?

I guess I would say, Carl, that in fiscal 2010 our well costs were higher than we would have hoped, more in $5 million range than the $4 million range. That said, a lot of that cost was related to a well where we stuck a perf gun, a well that we had to redrill, various operational issues that come up. And they are normal in E&P operations. And it's just a matter of kind of fine-tuning the program. At this point things are actually going very well. I think the current wells we're on, we are going to start seeing significantly better costs.

Meaning back to the $4 million range?

Kind of the Eastern Development Area might tend to be $4.5 million range, because those are our deeper higher pressure wells, cost a little more to frac them, and the wells to the West might be closer to $4 million. And of course, it all depends on lateral length, too. The lateral length doesn't add a significant amount to the drill cost, but if you are fracing 15 stages instead of ten, that does add to the cost.

Right, right. The issue of landing it in the right zone, is that a combination of both lateral length and the zone, or is that just we are really just talking about where to land it?

Lateral length is important as well, but when I talk about that I'm really just talking about landing it in the ideal zone. You might be surprised, you think of the shales as being kind of being homogeneous through a thick interval, but they actually vary quite a bit,and that ideal landing zone makes a significant difference in how the rock fracs.

Great, and then maybe one last question for Ron, this is actually just on the pipelines you mentioned the same challenges in fiscal 2011 that we talked about in the last conference call. And obviously as the new projects come on, and it's going to alleviate any pressure in fiscal 2011. But last I saw in my notes, we are talking about maybe having the pipes having some headwinds of about $10.5 million. Has anything over the last two or three months changed that estimate for this coming fiscal year?

No. We are still obviously out beating the bushes to try to fill in that capacity with short-term transportation volumes. And we pick up some here and there, but it's not terribly different than what we talked about last time.

Great. Thanks, guys.

You're welcome, Carl.

Your next question comes from the line of Ray Deacon of Pritchard Capital. Please proceed, sir.

Good morning. I had a question about Gulf of Mexico production, and sort of what kind of decline we should expect in 2011.

Yes, Ray, I think we are forecasting about a 20% decline in 2011.

Okay. Got it.

It's very -- we have several fields that are really just rocking along at a nice rate, and you know how it is in the Gulf of Mexico, you can lose that production very suddenly.

Got it.

So it's a little difficult to predict.

Okay. Got it. I guess just, would you -- I don't want to steal your thunder from the analyst meeting -- but do you intend to update the EURs for each of the areas in the Marcellus? Is that part of what you are going to do?

That's not part of the plan.

Okay.

At least not in any level of detail.

Okay.

We might talk EURs a little bit.

Okay, got it. I guess just one more. I just got back from this DUG East Conference, and the big topic there was water management, and dealing with cuttings, and also produced water and brine. I guess could you just talk kind of about how you are handling that and recycling issues I guess?

Sure, we recycle all of our frac water.

Right.

One of the things we are doing and this really had a big impact on the area where we we're the most active which is Tioga County, we have a location where we capture acid mine drain-off from an abandoned coal mine. It's a win-win, the Susquehanna River Basin Commission is very happy to have us capturing that water, because it keeps it from ending up in a trout stream somewhere, and then we have a pipeline system that takes that water to our well locations, to our well pads. So we take all those trucks off the road as well. It's a really good system for us. It has lot of environmental benefit, and at the same time, we save about $120,000 per well in trucking costs.

Wow. Great. And then with the produced water I guess what -- you are recycling that, you said.

We are.

Okay. Got it. Great. Thanks very much.

You're welcome.

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

Good morning, guys.

Good morning, Mark.

I just wanted to -- I got on late, so this is more for clarification. I wanted to see, given the success you mentioned the EOG wells, and I know you don't want to get in the habit of constantly updating this. But given that success that you are starting to see on the western side -- and I know we got the resource update -- how we should think about your EURs? And the second part of that is going to be -- I know you don't want to comment too much on the JV -- but as I look at it, you are one of the few companies in the region who have sort of a unique position, in the fact that you own a lot of your acreage and fees. So I feel like your JV value proposition is much different than peers. I just wanted to see how I should think about that, because it seems to me that you should be getting an uplift, for the fact that you have it in fee, where everyone else has a much higher royalty? But didn't know if you'd comment on that a little bit.

I would agree with you that all other things being equal the value -- there's a significant value in having royalty-free acreage. And it really goes beyond that, in that we don't have to drill to hold our acreage. So we and a joint venture partner can develop the acreage very logically, rather than a sort of scattered drilling program to hold acreage.

Yes, Mark, that has an additional advantage in that we are able to put the gathering systems in, and to the extent that we do a joint venture we are going to redeploy some of that capital into the pipeline assets, gathering systems to accommodate the accelerated drilling. And as I said before, a number of these joint ventures are having some difficulty reaching the minimum levels of drilling that were anticipated, because they are drilling in a very inefficient scattered fashion. And we should -- we're not going to have to do that, because of the proximity of our acreage because it's so contiguous. I think a joint venture, I think our joint venture has some significant advantages vis a vis some of the others out there that you see.

One last question, given all the craziness that was going on with the difference talks about severance taxes and whatnot, have you seen any change, I think David, I heard you say earlier that you are still seeing a lot of good interest in the acreage?

Yes. Well, there's a lot of interest in our joint venture as I mentioned. If anything, Corbett's election is likely to slow down a severance tax as opposed to speed it up. And also I think both the Senate and House now are in Republican hands in Pennsylvania, which is also likely to slow it down. That is not to suggest there won't be one. That is that even to suggest that we're fighting one, a reasonable severance tax that deals with the environment and goes back to the communities is not a terrible thing. It's just a question of a reasonable severance tax.

Great. Thanks, guys.

You're welcome.

Your next question comes from the line of Brian Kuzma of Weiss Multi-Strategy. Please proceed.

Good morning guys.

Morning, Brian.

I was curious, you guys said that in the Gulf of Mexico, you expect only modest type declines in 2011. I just wanted to make sure if that's over your exit rate or that's over your fiscal year number?

We are looking at about a 20% decline year-over-year for the annual production in fiscal 2011. And as I said in an earlier question, that's a little hard to predict that precisely, it's very possible that we could end up with a much smaller decline than that. But it's a little hard to predict when these fields will go off-line.

Got you. Okay. And then in California what happens to California production with 50 wells?

We are looking at a fairly flat year-to-year. I can't remember exactly what our estimate is for fiscal 2011 but it's out there in the slide presentation that we used in San Francisco.

I'm going to check that out then. And then you're Elk County pad when do you think you will frac that?

Well, the rig has just arrived on location so we have to drill those three wells. Move out of there, and have a frac crew scheduled to come in. So I would say it's at least 60 days away. But it could be a little bit longer than that. I'm not exactly sure where the frac crew -- where that falls in the schedule.

Okay. And is that the next operated frac that we are going to get out of you guys on the Western acreage?

Yes.

Okay. That is all I had. Thanks, guys.

You're welcome.

At this time, I would like to turn the call back over to Mr. Silverstein for closing remarks. Please proceed, sir.

Thank you, Shantalay. We would like to thank everyone for taking the time to be with us today. A replay of this call will be available at approximately 2.00 PM Eastern Time on both our website and by telephone, and will run through the close of business on Friday, November 12, 2010. To access the replay online, visit our Investor Relations website at investor.nationalfuelgas.com. And to access the telephone, call 1-888-286-8010, and enter passcode 78038698. This concludes our conference call for today. Thank you, and goodbye.

Thank you for your participation in today's conference. This concludes the presentation. You may now disconnect. Have a wonderful day.