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National Fuel Gas Co. (NYSE:NFG)

F4Q09 Earnings Call

November 06, 2009; 11:00 am ET

Executives

Dave Smith - President & Chief Executive Officer

Matt Cabell - President of Seneca Resources Corporation

Ron Tanski - Treasurer & Principal Financial Officer

Jim Welch - Director of Investor Relations

Analysts

Carl Kirst - BMO

Rebecca Followill - Tudor Pickering Holt

Ray Deacon - Pritchard Capital

Jonathan Lefebvre - Wells Fargo

Faisel Khan - Citigroup

Jim Harmon - Barclays Capital

Operator

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

I would now like to turn the presentation over to Jim Welch, Director of Investor Relations. Please proceed.

Jim Welch

Thank you Tom and good morning everyone. Thank you for joining us on today’s conference call for a discussion of last evening’s earnings release. With us on the call from National Fuel Gas Company are Dave Smith, President and Chief Executive Officer; and Ron Tanski, Treasurer and Principal Financial Officer. Joining us from Seneca Resources Corporation is Matt Cabell, President. At the end of the prepared remarks, we’ll open the discussion to questions.

We’d like to remind you that today’s teleconference will contain forward-looking statements. While National Fuel’s expectations, beliefs and projections are made in good faith and are believed to have a reasonable basis, actual results may differ materially. These statements speak only as of the date on which they are made, and you may refer to last evening’s earnings release for a listing of certain specific risk factors. With that, we’ll begin with Dave Smith.

Dave Smith

Thank you Jim, and good morning to everyone. Last night, National Fuel reported fourth quarter operating results of $0.36 per share down $0.16 per share for the quarter. These results were consistent with the first nine months of the year and we are inline with our expectations.

For the physical year we reported operating results of $2.60 per share, a decrease of $0.57 per share from the prior year. As expected the drop in operating results for both the quarter and the physical year was almost entirely due to lower crude oil and natural gas prices realized primarily in our EMP segment.

Overall, given the weak economy and lower commodity prices, fiscal 2009 was a strong year for National Fuel, financial and operationally and a testament to our balanced integrated model. Perhaps even more importantly during fiscal 2009 we continued to take steps particularly in the development of our vast Marcellus shale that will insure continued growth in the future.

On the regulated side of our business the performance of our utility and pipeline and storage segment was rock solid. Thanks to the many revenue protecting rate making mechanisms in place, including straight fix variable rate design in the pipeline and storage segment and the revenue decoupling mechanism in our New York utility.

Our regulated operations are much less sensitive to commodity prices or to act on macro economic cycles. Their stable reliable earnings and cash flows particularly important in troubling times serve as the foundation for our long standing dividend.

In the E&P segment Seneca’s east division had another outstanding year posting a 15% increase in natural gas production and a reserve replacement ratio of 340%. Excluding the impact of some downward reserve divisions which were generally price related and most of which would reverse at current prices, these divisions reserve replacement ratio was over 500%.

Meanwhile, Seneca’s west division continues to do a great job. Fiscal production was 7% higher than fiscal 2008 production and our second consecutive year production growth in California.

Overall, Zeneca’s consolidated production for the quarter and fiscal year was up compared to the prior year by 20% and 4% respectively. While the 4% annual increase in production appears relatively modest, net increase was achieved despite our cut back in spending in the gulf, our cut back in spending in California, a cut back in spending in the upper Devonian program in Appalachia and most noteworthy it was done without any Marcellus production. Production will be coming online this quarter.

With regard to the Marcellus we have made considerable progress on our Marcellus related initiatives in the E&P midstream and pipeline and storage segments, and have positioned ourselves for what we believe will be exceptional future growth. For the past several months Seneca has been evaluating its vast Marcellus positions, drilling 11 vertical wells in 7 counties.

Log and core data have enabled us to prioritize our acreage while working alongside our joint venture partner EOG, we gained valuable experience in drilling and in completing horizontal wells at little cost to Seneca.

This past quarter we drilled our first two Seneca operator horizontal wells and we are very pleased with the results. In addition to validating the potential of our acreage, these wells demonstrate that we have the people, knowledge and skills to be a successful operator in the Marcellus.

Now that we have gained a requisite experience we plan to move rapidly into the execution phase of our strategy. Over the next several months Seneca’s Marcellus program will ramp up quickly, and so, last call we revisited our 2010 capital budget for the Marcellus. Based on our success today Seneca now expects to spend between a $180 million and $200 million on the Marcellus in 2010, which was about a 50% increase from the initial budget we announced in August.

Our current plans call for a second Seneca operated horizontal rig to be running by the end of the month and a third by early summer. Matt will provide additional details later on the call. While Seneca was drilling its horizontal wells, NFG Midstream, a company that we set up in 2009, was busy building the Covington gathering system which will get Seneca Marcellus production to market.

Construction of the first phase of the Covington system is completed and we expect to begin flowing production once Tennessee commissions the interconnection which should be by the middle of the month within the next two weeks.

A relatively small in terms of capital, the Covington systems demonstrates our ability to solve the infrastructure issues in Appalachia and to build the system in a short period of time. From start to finish this system was down at about 8 months.

A number of producers have asked us to submit proposals, to build gathering systems for them and we anticipate that our responses will lead to new projects in 2010 and 2011, and Ron will address our projected CapEx for Midstream in his comments.

Turning to our pipeline and storage segment we continue to see strong interest particularly from Marcellus producers and our proposed transmission and storage development projects. During the quarter Supply Corporation executed binding press and agreements with shippers that will allow it to go forward with its Lamont compression expansion project in its Bristoria, we now call it Line-N expansion project.

The Lamont project will add approximately 1200 horse power of compression at Supply Corporation’s existing interconnection with Tennessee gas pipelines at 300 lines at Lamont in Pennsylvania, and provide an additional 40,000 deca-therms per day of takeaway capacity.

This project which will be built on their supplies blanket construction certificate is expected to cost approximately $6 million and should be in service in May 2010. Given the anticipated Marcellus production in this area, given the continued request for service, even more compression is likely to be added at Lamont in the future.

The Line-N expansion project which as I noted we in the past called Bristoria, is a $22 million pipeline and compression project at the south western end of our system that will move 150 million per day of range Marcellus production to an interconnection with Texas Eastern ultimately than off system.

Environmental and field routing studies are underway and we expect to file our per cap location in the spring of 2010. This project which like Lamont is also likely to be further expanded in the future, is expected to go in service in November of 2011.

Supply Corporation also continues to make excellent progress on its West to East project based on the interest expressed by potential shippers and services starting as early as 2011. Supply held a binding open season for transportation capacity on two initial phases of the project. The open season concluded on October the 8th with binding requests for a 175,000 deca-therms per day of firm transportation capacity. Most of it was from Marcellus producers.

Supply expects to execute the signed president agreements submitted by those bidders and while we don’t yet have the level of commitment we need to ensure construction of the project, we are very optimistic that the ongoing negotiations with Marcellus producers will yield the required support. As a result, we began preliminary routing and environmental analysis this fall and if all go well hope to file our application with FERC next summer.

Lastly, in pipeline and storage, in October Empire held a non-binding open season for its Tioga County extension project which would -- think of it as extending the Empire connector itself. It would be a 16 mile 24 inch pipeline designed to move at least 200,000 deca-therms per day of Marcellus production from Tioga County Pennsylvania to Empire’s existing system at Corning New York.

From there Marcellus production could be delivered into existing Empire interconnects with Millennium and with TransCanada pipeline at Chipola and into a planned new interconnection with Tennessee’s 200 lines in Ontario County, New York. This project also contemplates modifications to the existing Empire facilities to allow bidirectional flow.

The total cost of the project is estimated at $43 million and the projected in-service date is September 2011. The Empire received extremely strong interest in the project, in fact more than adequate capacity to support the project was requested in the open season.

As a result, we are in the process of negotiating binding president agreements with potential shippers and following successful negotiations we expect to file an application with FERC for approval likely in the summer of 2010. In the meantime based on the strong interest Empire has moved ahead with preliminary routing and environmental analysis.

In closing, this is an exciting time for National Fuel, for the past couple of years our remarks and mine in particular has focused largely on our potential in Appalachia. Potential in pipeline and storage, Midstream and E&P.

Today I think it is fair to say that we have moved far beyond potential we are now focused on execution. Marcellus is undoubtedly critical to the future growth of National Fuel and we plan to exploit this exceptional opportunity as quickly and as effectively as we reasonably can.

With that I thank you for your attention and I will turn the call over to Matt for a detailed update of Seneca’s operation.

Matt Cabell

Thanks Dave. Good morning everyone. It was a good quarter and a good year for Seneca. Production was up 20% versus last year’s fourth quarter, and up 4% for the fiscal year. We have now drilled and competed two Seneca operated horizontal Marcellus shale wells with a combined one week IP of over 10 million cubic feet per day.

We have continued to dramatically improve our overall funding and development cost with companywide fiscal 2009 F&D cost at $2.40 per Mcfe excluding lease acquisition cost. We replaced a 156% of our production through drilling. Added some high quality properties in California and divested some of our non-core properties in the Gulf of Mexico.

Now, let me add some detail concerning our Marcellus shale activity. We recently completed our second Seneca operated horizontal and tested it at 4.7 million cubic feet per day for seven days.

Much like our first horizontal well which tested 5.8 million cubic feet per day, this well showed very little decline over the seven day test period, each of these two wells was drilled in about 18 days, stimulated and competed at a cost of about $4 million each, far better than industry average.

Needless to say we are very pleased with the results of the two wells in our Tioga County focus area, and plan to develop the area aggressively this fiscal year.

We are currently drilling our fifth Seneca operated horizontal well in the same area and expect to have the more fracs completed by the end of December, including a zipper frac in which we frac two parallel wells, alternating stages from well to well.

Over the past two years we rolled the learning curve at minimal cost and now as an operator our performance is on par with or even superior to the performance of many of the more experienced shale players. We have more than doubled the size of the East division team adding horizontal drilling and completion exports to our already very experienced and capable Pennsylvania operating staff.

Our immediate plans include the more fracs over the next two months and first production from our Tioga assets from the end of this month. I am confident that Seneca can execute a development program as sufficiently and as effectively as any company operating in the Marcellus play.

Meanwhile, our joint venture with EOG continues to accelerate. Ten horizontal wells were completed by EOG during the fiscal year and four more were in some stage drilling their completion at fiscal year-end.

Two wells were brought on line recently and I expect sales from several or more by the end of the quarter. EOG has been operating with one to two horizontal drilling rigs and one top hole rig developing our Punxsutawney focus area. I expect 25 to 30 horizontals to be drilled by the joint venture this fiscal year.

In total, including both Seneca operated and EOG operated wells, we now have 17 vertical wells and 18 horizontal wells drilled across our Marcellus shale acreage. 12 of the horizontals have been fraced and completed, and three are producing. By the next earnings call I expect to have at least 10 wells online and possibly as many as 16 or 18.

Given our success over the past few months we have decided to ramp up our drilling activity for fiscal 2010. We will add a second Seneca operated rig later this month and now expect to drill a total of at least 50 Marcellus shale wells in fiscal 2010 including the previously mentioned 25 to 30 wells operated by EOG.

You can consider our fiscal 2010 Marcellus program as consisting of free parts. First, the EOG joint venture development, second, the Seneca operated Tioga County development, and third of horizontal program targeting on high priority areas identified from our vertical joint program. This third piece is primarily designed to de-risk and further prioritize other areas for development, including identifying where we will need to build gas processing facilities.

This acceleration in our plans will increase our Marcellus capital spending by about 50% to a new age of about $180 to $200 million. I expect a much greater increase in Marcellus spending in fiscal 2011 as we add rigs and begin development of additional focus areas.

Moving onto California, we produced 5.1 Bcfe for the quarter and 20.1 Bcfe for the fiscal year, an increase of 7% versus fiscal 2008 surpassing our expectations. The properties acquired in July from Ivanhoe are performing as expected and we’ve begun to improve production. We’ve identified additional upside opportunities on our assets and we continue to produce at a very competitive lifting cost.

In the Gulf of Mexico, we produced 3.8 Bcfe for the quarter and 13.7 Bcfe for the fiscal year, nearly matching our production from fiscal 2008. For fiscal 2010, we are forecasting 11 to 13.5 Bcfe for the Gulf of Mexico, while continuing our plan of minimal capital spending. In addition we sold five of our non core Gulf properties.

Fiscal 2009 was a very good year for reserve replacement in funding and development cost even with some downward revisions due to lower gas prices. As I’ve mentioned at the outset, we replaced a 156% of our production in fiscal 2009 and a finding and development cost of $2.40 per Mcfe excluding lease acquisitions. If we include revisions, lease acquisitions and property acquisitions they replaced 160% of our reserves at a cost of $3.04 per Mcfe.

In the Marcellus shale we added 21.2 Bcfe at a cost of $1.28 excluding lease acquisitions. The Marcellus reserves include initial conservative bookings only for horizontal wells where we had significant flow test data and a few offsetting PUDs. Marcellus reserve adds for fiscal 2010 should be substantially higher.

Looking forward to fiscal 2010 we’re revising the high end of production guidance to 50 Bcfe, at a relatively broad range of 42 to 50. This large range reflects the uncertainty of timing for bringing on new Marcellus production as gathering system delays appear to be likely in some areas.

However, we’re increasing our expectation for fiscal year end Marcellus shale exit rate which should be September of 2010, from the previous target of 20 to 30 million cubic feet per day to a new target of 30 to 50 million cubic feet per day.

Of course this is just the beginning. This year we will develop two Marcellus focus areas and continue to derisk and prioritize through the remainder of our acreage. I anticipate substantial acceleration of the development program over the next several years leading to 20% companywide annual production growth and rapidly growing reserve base.

With that I’ll pass it on to Ron.

Ron Tanski

Thanks Matt and hello everyone. Dave and Matt already covered a lot so I’ll be brief and we can get right to your questions. Earnings for the entire 2009 fiscal year were right in the middle of our guidance range, now the consensus estimates were higher, but we think this some analysts may have not factored into their estimates the impact of year-over-year commodity pricing effects on efficiency gas volumes in the pipeline and storage segment and some positive market to market adjustments and hedges in the EMP segment that occurred last year.

It was also the year-to-year change in the allowance for funds used during construction and the capitalization of interest expense and impacted earrings in the pipeline and storage segment that may have been difficult for some analysts to get a handle on. The future regulated pipeline of projects will be sure to point out those issues for your modeling purposes.

Looking to fiscal 2010, we revised our production volume to a range between 42 and 50 Bcfe. That volume change had the effect of increasing our 2010 earning guidance range to a range between $2.30 and $2.65 per diluted share and again that’s based on flat NYMEX prices of $5 per Mmbtu for natural gas and $75 per barrel of oil for our unhedged production.

From the perspective of the utility segment, lower gas prices will have the effect of lowering winter bills for our customers by approximately 18% from last year and as we do at the beginning of every heating season, our utility customer service representatives and field service people are prepared to assist our customers in applying for heating aid, setting up payment arrangements and other service needs.

Another area that’s worth reviewing and updated are the preliminary 2010 capital expenditure budgets that I gave out during our August call. In the utility segment, capital spending is now budgeted at $60 million. For the pipeline and storage segment, we’ve a budget of $51 million. For the exploration and production segment our total capital budget is in a range between $245 million and $293 million.

For the Midstream Company, we’re budgeting capital spending of up to $45 million and lot of that spending will depend on whether or not we get the projects that Dave talked about earlier. For all other areas, the budgets totaled $1 million and that gives us the total range between $402 million and $450 million of capital spending for fiscal 2010.

These budgets have us outstanding projected cash flow by $60 to $110 million in 2010 but we do have current cash available and ample liquidity to handle the spending. We still have $420 million of bilateral credit lines in place and we will be working to renew or extend our $300 million syndicated committed credit facility which remains available currently through September of 2010.

Our next long-term debt maturity totaling $200 million will be in November of 2010. We will continue to monitor the credit markets and our cash flow to see if it makes sense to visit the capital markets during the year. Our balance sheet is solid with a 56% equity component, are projected earnings are from and we expect to have adequate cash flow and access to working capital to support all of those spending plans.

Now operator lets open it up for questions.

Question-and-Answer Session

Operator

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

Carl Kirst - BMO

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

Matt Cabell

Carl I guess the way we’re looking at it now is there are two potential factors that are affecting these fracs as compared to our fracs in the area that we have been active with EOG. One is the rocks are a little different, the rocks are a little thicker and potentially a little different in some other properties and the other is we did frac at a higher bump rate.

So, our frac technique was a little different. What remains to be seen is how much of the difference in the performance of the wells is a function of difference in the rocks and how much is a function of the difference in the completion technique and until we have the completion technique that we used and the pump rate that we used on a well in a more western part of our acreage we won’t know for sure which is the bigger factor, but we wouldn’t know that within a months.

Carl Kirst - BMO

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

Matt Cabell

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

Dave Smith

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

Ron Tanski

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

Carl Kirst - BMO

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

Ron Tanski

Well, it’s certainly as, we still have quite a few regulated operations and we plan to grow the pipeline in storage segment right along with the Marcellus and primarily to allow Seneca to produce its gas. So, to the extend that we do have regulated operations; we will be looking to keep the balance in the balance sheet.

Now, that still gives us with the 56% equity component we have right now, I mean immediately if we want to do it, and I’m not saying we’re doing this, but we could lever up issue another $340 million or so of debt and still keep the 50:50 balance.

Now, most of the spending and when we really start exceeding our cash flow would be in fiscal 2011 when we’ve got the pipeline projects in addition to the ramp up in the Marcellus. So for 2010, we’re pretty solid with cash on hand, liquidity and earnings, and we’ll just be careful to watch that during the year to see what we need to do.

Dave Smith

Yes, longer term Carl, although options around the table of course, I mean short term we’re fine with the cash we have, and as Ron said and the ability to lever up if we need to, but longer term we’ll be looking at it over the next two, three, four years and every year we sit down with our Board and go over this kind of a plan, and consider all of our options.

I mean there’s also certainly the ability to bring in partners with respect to midstream, with respect to ENPs and all of those options are on the table, but maintaining a strong balance sheet is very important to.

Operator

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

Rebecca Followill - Tudor Pickering Holt

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

Ron Tanski

Rebecca I kind of oversimplified it a little bit talking about, I didn’t go into all the detail in the two phases, because it was boring me and I knew it would bore everybody else, but in part we’d be looking to jockey around some of the commitments that are on phase two as opposed to phase one.

I think at the end of the day, if we get 200 or more on Phase I, we’ll be able to move forward with that project and we think we’ll be able to do that. Just looking at who bid on Phase II, who bid on Phase I, how they plan to put the gas into the system, we think that is a very likely project, let me put it that way.

Rebecca Followill - Tudor Pickering Holt

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

Ron Tanski

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

Rebecca Followill - Tudor Pickering Holt

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

Ron Tanski

We are going to talk about that next week.

Dave Smith

Yes, we’re going to talk about that next week Rebecca, and what we’ll also have a little bit more firm or more definitive fashion. As you know in our 10-K, we’re required to protect out capital expenditures over the next three years. So we’ll have that laid out and be able to talk about it then. One of the things that I might suggest also for anyone who wants to get into some more detailed questions and make it a little bit more easy to see pictorially.

If you go to our website, specifically Supply Corporation and Empires section of the website, we do list the open seasons in a little bit more detail and provide maps and it will be probably a lot easier to ask questions and to make sense of our responses. If you look at those maps and the open seasons and what’s involved and it will probably paint a more cohesive picture if you have that in hand.

Rebecca Followill - Tudor Pickering Holt

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

Ron Tanski

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

Operator

Your next question comes from Ray Deacon - Pritchard Capital.

Ray Deacon - Pritchard Capital

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

Ron Tanski

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

Ray Deacon - Pritchard Capital

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

Matt Cabell

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

Ray Deacon - Pritchard Capital

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

Matt Cabell

Not really.

Dave Smith

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

Operator

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

Jonathan Lefebvre - Wells Fargo

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

Matt Cabell

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

Jonathan Lefebvre - Wells Fargo

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

Matt Cabell

No, I wouldn’t think of it that way. Well, I guess technically that’s probably true because none of them are producing, but it amounted to eight PUDs and something on the order of eight PUDs and nine working interest wells that had been tested for a long enough period of time that we could book reserves, and a fairly big variation in the estimated EURs within that set of 17 wells.

The vast majority of which all but really one, or wells in the joint venture where we have a working interest that is typically around, working interest of 50% and our net revenue interest of typically about 60. Also keep in mind these are relatively conservative estimates when those wells have been online for say 90 days or 180 days, will be able to better define that decline curve and that tool will be comfortable with a perhaps on more aggressive reserve booking.

Jonathan Lefebvre - Wells Fargo

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

Matt Cabell

By the end of this month actually.

Jonathan Lefebvre - Wells Fargo

By the end of the month, sorry.

Matt Cabell

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

Jonathan Lefebvre - Wells Fargo

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

Matt Cabell

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

Ron Tanski

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

Jonathan Lefebvre - Wells Fargo

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

Matt Cabell

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

Operator

Your next question comes from Faisel Khan - Citigroup.

Faisel Khan - Citigroup

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

Ron Tanski

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

Faisel Khan - Citigroup

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

Matt Cabell

I think we would have to do a little bit of research on that to understand why it differs from what you are seeing.

Faisel Khan – Citigroup

On the overall portfolio in E&P, obviously with the ramp up in production in Appalachia your gas production from a larger mix of your overall portfolio, is there any sense that you guys would want to increase your production or exposure on the oil side either through acquisitions or through some other methods?

Matt Cabell

Again you are breaking up a little bit, but I think you’re asking, is there anything we can do to increase our oil production.

Faisel Khan – Citigroup

Yes. I was asking if the portfolio approach do you want to, is there a goal to keep your oil production kind of a certain percentage of overall production or are you happy becoming more gassier overtime.

Matt Cabell

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

Dave Smith

I think, it’s not, I mean as with Ivanhoe Faisel, where we added last year in California, we get some more of those potentially built on acquisitions where we think we can do a good job. Yes, we’ve been looking at adding those, but no we don’t have a predetermined percentage between oil and gas and as Matt said, given our resource, it’s like we will become gassier overtime.

Faisel Khan – Citigroup

I just want to understand if there was any gold mine, but it sounds like you are in both plays, you’ve got good opportunities in both plays and you are just going to continue to take you to invest where the best returns are. Thanks guys.

Operator

Your next question comes from Carl Kirst - BMO.

Carl Kirst - BMO

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

Matt Cabell

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

Carl Kirst - BMO

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

Ron Tanski

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

Operator

Your next question comes from Jim Harmon - Barclays Capital.

Jim Harmon - Barclays Capital

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

Matt Cabell

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

Jim Harmon - Barclays Capital

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

Dave Smith

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

Operator

Your final question comes from Ray Deacon - Pritchard Capital.

Ray Deacon - Pritchard Capital

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

Ron Tanski

EOG’s minimum requirement as part of the joint venture agreement maybe 20 wells in calendar 2010; now from what Dave have indicated, I expect will be at a significantly higher level than that in calendar ‘10, and our best guess for fiscal 2010 would be, as I said, 25 to 30 for fiscal 2010.

On the Seneca operated side, we’re going to bring that second rig next month and the third rig we haven’t really set a date certain, but let’s say by this next summer. So similar well count for Seneca, 25 to 30 operated wells. Keep in mind, when I refer to these well counts, those are gross well counts. So when I say 25 to 30 EOG wells, we’ll have 50% working interest in those.

Ray Deacon - Pritchard Capital

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

Ron Tanski

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

Operator

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

Jim Welch

Thank you, Tom. We’d like to thank everyone for taking the time to be with us today. A replay of this call will be available at approximately 2.00 pm Eastern Time today on both our website and by telephone, and a run through the close of business on Friday, November 13. To access the replay online visit our Investor Relations website at www.investor.nationalfuelgas.com and to access by telephone, call 1-888-286-8010 and enter pass code 75925727.

We’d also like to mention that on Thursday, November 12, at approximately 8:30 am Eastern Time National Fuel will be making a webcast presentation of year end financial and operational results that can be accessed through our Investor Relations website as well. We’ll issue a press release to remind everyone of the details of this event this afternoon.

This concludes our conference call for today. Thank you and good bye.

Operator

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

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Source: National Fuel Gas Co. F4Q09 (Qtr End 30/9/2009) Earnings Call Transcript
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