National Fuel Gas Co (NFG) 2009 Q4 法說會逐字稿

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

Thank you, Tom, and good morning, everyone.

Thank you for joining us on today's conference call for a discussion of last evenings 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 will open the discussion to questions.

We'd like to remind you that today's teleconference will contain forward-looking statements. While National Fuels' 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 evenings earnings release for a listing of certain specific risk factors.

With that, we will begin with Dave.

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 were in line with our expectations. For the fiscal 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 fiscal year was almost entirely due to lower crude oil and natural gas prices realized primarily in our E&P segment.

Overall, given the weak economy and lower commodity prices fiscal 2009 was a strong year for National Fuel financially 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 ensure continued growth in the future. On the regulated side of our business, the performance of our utility and pipeline and storage segments was rock solid.

Thanks to the many revenue protecting rate making mechanisms in place, including straight fixed variable rate design in the Pipeline and Storage segment and the revenue and decoupling mechanism in our New York Utility, our regulated operations are much less sensitive to commodity prices or to macroeconomic cycles. They are 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 revisions which were generally price related and most of which would reverse at current prices, the East 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 of production growth in California. Overall, Seneca'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, that increase was achieved despite a cut back in spending in the Gulf, a 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've 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 position, drilling 11 vertical wells in seven counties. Log and core data have enabled to us prioritize our acreage while working alongside our joint venture partner EOG, we gained valuable experience in drilling and completing horizontals well at little cost to Seneca.

This past quarter we drilled our first two Seneca operated horizontal wells and we're 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've gained the 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. Since our last call we revisited our 2010 capital budget for the Marcellus. Based on our success to date, Seneca now expects to spend between $180 million and $200 million on the Marcellus in 2010, which is 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 setup 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.

Though relatively small in terms of capital, the Covington system demonstrates our ability to solve the infrastructure issues in Appalachia, to build the system in a short period of time; from start to finish this system was done in about eight months. A number of producers have asked to us 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 precedent agreements with shippers that will allow it to go forward with its Lamont compression expansion project Bristoria, we now call it Line-N, expansion project.

The Lamont project will add approximately 1,200-horsepower of compression at Supply Corporation's existing interconnection with Tennessee Gas Pipeline's 300 line at Lamont in Pennsylvania; and provide an additional 40,000 dekatherms per day of take away capacity. This project, which will be built under Supply's 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 requests for service, even more compression is likely to be added at Lamont in the future.

The Line-N expansion project which, as I noted, in the past we called Bristoria, is a $23 million pipeline and compression project at the southwestern end of our system that will move 150 million per day of Range Marcellus production to an interconnection with Texas Eastern ultimately then off system. Environmental and field routing studies are underway and we expect to file our FERC application in the Spring of 2010. This project, which like Lamont, is also likely to be further expanded in the future, it 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 in service 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 8th with binding requests for 175,000 dekatherms per day of firm transportation capacity, most of it was from Marcellus producers.

Supply expects to execute the signed precedent 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 primarily routing and environmental analysis this fall; and if all goes well we hope to file our application with FERC next summer.

Lastly, in Pipeline and Storage and Empire. In October, Empire held a nonbinding open season for its Tioga County extension project, which would--think of it as extending the Empire Connector south. It would be a 16-mile, 24-inch pipeline designed to move at least 200,000 dekatherms 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 interconnections with Millennium and with TransCanada Pipeline at Chippewa, and into a planned new interconnection with Tennessee's 200 line in Ontario County, New York. This project also contemplates modifications to the existing Empire facilities to allow bi-directional flow. The total cost of the project is estimated at $43 million and a projected in-service date is September 2011.

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 precedent 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, have focused largely on our potential in Appalachia, potential in Pipeline and Storage, Midstream, and E&P. Today, I think it's fair to say that we've moved far beyond potential, we are now focused on execution. The Marcellus is undoubtably 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, thank you for your attention and I'll turn the call over to Matt for a detailed update of Seneca's operations.

Thanks, Dave. Good morning, everyone.

It was both 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've now drilled and completed 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 finding and development cost with company-wide fiscal 2009 F&D cost at $2.40 per Mcfe, excluding lease acquisition costs. We replaced 156% of our production through drilling, added some high quality properties in California, and divested some of our noncore 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, simulated and completed 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 first 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 three 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 rode 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 most experienced shale players. We have more than doubled the size of our East Division team, adding horizontal drilling and completion experts to our already very experienced and capable Pennsylvania operating staff. Our immediate plans include three more fracs over the next two months and first production from our Tioga assets by the end of this month. I am confident that Seneca can execute a development program as efficiently 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 of drilling or completion at fiscal year end. Two wells were brought online recently and I expect sales from several more by the end of the quarter. EOG has been operating with one to two horizontal drilling rigs and one top hold 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 frac'd and completed and three are producing. By the next earning 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've 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 three parts. First, the EOG joint venture development. Second, the Seneca operated Tioga County development. And, third, a horizontal program targeting our high priority areas identified from our vertical drilling program.

This third piece is primarily designed to derisk 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 range of $180 million 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 on to 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 have begun to improve production. We have 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 bcfe to 13.5 bcfe for the Gulf of Mexico, while continuing our plan of minimal capital spending. In addition, we sold five of our noncore Gulf properties.

Fiscal 2009 was a very good year for reserve replacement and finding and development costs, even with some downward revisions due to lower gas prices. As I mentioned at the outset, we replaced 156% of our production in fiscal 2009 at a finding and development cost of $2.40 per Mcfe excluding lease acquisitions. If we include revisions, lease acquisitions, and property acquisitions, we 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 are revising the high-end of production guidance to 50 bcfe with a relatively broad range of 42 to 50 bcfe. 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 are increasing our expectation for fiscal year end Marcellus shale exit rate, which would 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 the remainder of our acreage. I anticipate substantial acceleration of a development program over the next several years, leading to 20% company-wide annual production growth at a rapidly growing reserve base.

With that, I will pass it on to Ron.

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 that 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 mark-to-market adjustments on hedges in the E&P segment that occurred last year. There was also the year-to-year change in the allowance for funds used during construction, and the capitalization of interest expense that impacted earnings in the Pipeline and Storage segment that may have been difficult for some analysts to get a handle on. For future regulated pipeline projects, we 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 earnings 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 updating 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 have 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 are budgeting capital spending of up to $45 million and a 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 total $1 million that gives us a total range between $402 million and $450 million of capital spending for fiscal 2010. These budgets have us outspending projected cash flow by $60 million 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, our projected earnings are firm and we expect to have adequate cash flow and access to working capital to support all of those spending plans.

Now, Operator, let's open it up for questions.

(Operator Instructions). Your first question comes from the line of Carl Kirst with BMO. Please proceed.

Hi. Good morning, everybody. It's Carl Kirst.

A couple quick questions, Matt. 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 chalk this up mainly to just being in Tioga; or do we have more frac stages or a different completion as well that is in part responsible for the differences in early IP rates?

Carl, I guess the way we are 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've 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 of their properties and the other is we did frac it at a higher pump rate. 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 the 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 should know that within a few months.

Within a few months. Okay. Thank you.

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 11th exit rate might be; and I didn't know if perhaps as we were accelerating 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 two years out.

I think I will do it this way, Carl. It's undoubtably going to be higher than what we had previously estimated, but I'm not certain that we are ready to provide a range today.

Carl, you know our Analyst Conference is next week in New York and Boston and I think by then we might--Matt might have that for you.

Carl, this is Ron.

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 hence maybe at this stage maybe there are uncertainties.

No, all of that --points are very well taken. I just thought I would hazard the question.

Last question maybe and I will jump back in queue, Ron, more for you, you guys have got a rock solid balance sheet. You are obviously going to start to inflect 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 a BBB+ balance sheet, is that a definitive goal or is it something where we will just kind of keep it as perhaps solid balance sheet?

It's certainly, as you know, we still have quite a few regulated operations and we'll plan to grow the pipeline and storage segment right along with the Marcellus and primarily to allow Seneca to produce its gas. So to the extent that we do have regulated operations, we will be looking to keep the balance in the balance sheet. Now that still gives us with a 56% equity component we have right now, I mean, immediately if we wanted to; and I'm not saying we are 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 have the pipeline projects in addition to the ramp up in the Marcellus. So for 2010, we are pretty solid with cash on hand, liquidity, and earnings; and we will just be careful to watch that during the year to see what we need to do.

Longer term, Carl, all those options are on the table, of course. Short term we are fine with the cash we have; and as Ron said, the ability to lever up if we need to, but longer term we will 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. There's also certainly the ability to bring in partners with respect to Midstream, with respect to E&P. So, all of those options are on the table, but maintaining a strong balance sheet is very important to National Fuel.

Sure. Thank you.

Your next question comes from the line of Becca Followill with Tudor, Pickering, Holt.

Hi. It's Becca with Tudor, Pickering, Holt.

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

Well, Becca, I kind of over simplified 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 II as opposed to Phase I,and 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's a very likely project. Let me put it that way.

It's not very far a way is what you're saying.

No. It's not very far away. And we have 175 committed on and we think--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.

And following on that, I don't know if you guys are ready to talk about it now, if you wanted to do it next week, if all these things going on, the Lamont, Bristoria, West to East, Empire, how much CapEx are you looking at for 2011?

We are going to talk about that next week.

We are going to talk about that next week, Becca, and what we'll also have a little bit more firm or more definitive fashion is the--as you know in our 10K, we are required to project 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 Empire's 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.

Great. Thank you, I'll do that.

Last question on the 20% production growth that you mentioned, Matt, if memory serves me correct in August you guys talked about 10% to 20%. Is this 20% now an increase?

I think when we talked about 10% to 20%, we were including fiscal '10.

Okay.

Now we are saying 20%, not fiscal '10 but fiscal '11 forward, we think we will be close to 20% production growth.

Great. Thank you, guys.

Thanks, Becca.

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

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

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

Okay. Got it. Great.

And so I guess 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 still may be some things that get changed on the completion technique that could give you better thirty-day rates and IP rates, I guess, relative to Tioga?

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

Okay. Got it.

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

Not really.

No, I don't think so, Ray, that's spread out all over.

A lot of small deals. Okay. Got it. Thanks very much.

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

Good morning, guys.

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.

We really don't, Jonathan, we float tested it for about seven days and then we shut it in to get some pressure build up.

That's right.

We've 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 will get some more extended production data.

Got you.

Then on the Marcellus proved reserves that you booked the 20 or so bcf; can you give us a break down of what the PUDs were on that? Is there any color you can share with us?

Yes.

That you have no flowing, I guess maybe it's all PUDs or how should we be thinking about it.

No, I wouldn't think of it that way. Well, I guess technically that's probably true because none of them are producing; but it amounted to eight, I think eight PUDs and something on the order--eight PUDs and nine working interest wells that had been tested at a long enough--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, were wells in the joint venture where we have a working interest that is typically around--well 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, we will be able to better define that decline curve and that will ensure we will be comfortable with perhaps, perhaps, a more aggressive reserve booking.

Okay.

In terms of drill time efficiencies, where are you seeing kind of spud to spud times? I see that you are bringing on the next operated Marcellus rig a little earlier than--I think had you previously said January or February. Now it sounds like by the ends of this year but we are getting--

By the ends of this month, actually.

--by the end of the month, sorry.

Spud to spud--keep in mind we have a pretty small sample set here so far, we are on our fifth well. But I would say spud to spud, the assumption we are 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 to some degree on the length of the horizontals. Some areas we may have reason that we are drilling 5,000-foot horizontals and other areas it may be 3,000.

Got you.

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

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

Okay.

Then I know you don't want to maybe front run the Analyst Day, but in '11--my numbers kind of imply maybe 80 to 90 wells including the joint venture, any comments on that? Based on your new updated guidance.

We will talk about that next week; but frankly, I think there's a good chance it will be a larger total well count than what you're suggesting.

Okay. Fair enough. Thanks a lot, guys.

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

Morning, guys. It's Faisel.

Hi, Faisel.

How are you doing?

Just a question on the realizations you guys had in Appalachia, $4.09 in the quarter. Seems a bit higher than the Columbia Pool pricing. Can you just kind of walk us through why you are getting better realizations on your Appalachia production than what we would see in Columbia pool?

You broke up a little bit there, but I guess what I'm hearing you ask is the realized price in Appalachia is higher than you anticipated?

Yes. I'm looking at that Columbia Pool pricing I thought you got a lower price. I'm just trying to figure out--I know you guys are farther up on the pipeline capacity where you guys are geographically, but I suppose that has something to do with it, but I was just hoping--

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

Got you.

Then on your overall portfolio and E&P, you are going to--obviously with the ramp up in production, Appalachia, your gas production starts to become a larger mix of your overall portfolio. Is there any sense that you guys would want to increase your production or your exposure on the oil side either through acquisitions or through both or some other methods?

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

I was asking as a portfolio approach is there a goal to keep your oil production kind of as a certain percentage of your overall production; or is there--are you happy becoming more gassier over time.

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 are naturally going to become gassier over time. Is that a goal? No, not really. I wouldn't mind keeping the mix a little more even; but frankly, the assets that--we've got some great assets and those assets tend to be gassier. If we had 720,000 acres in the Bakken, that would be a nice mix.

I think it's not--I mean as with Ivanhoe, Faisel, where we added last year in California. If we get more of those potential bolt on acquisitions where we think we can do a good job, yes, we would be looking at adding those. But, no, we don't have a predetermined percentage between oil and gas, and as Matt said given our resources it's likely we become gassier over time.

Okay. That's fair.

I just wanted to understand if there was any goal in mind; but it sounds like you are in both plays, you have good opportunity in both plays and it's going to continue to take you to invest where the best returns are. Thanks guys.

Thanks, Faisel.

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

Thanks, guys.

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 a price or a range where you think the majority of that would come back?

The year end price was about $3.30. So even today we would get a fair bit of that back now, maybe half of it.

Half?

That's just a guess, though, Carl.

I was just curious kind of what the rough range was. That helps give some color, though. Thank you.

That's pretty close, though, Carl, half, I think--we took a look at that and that's pretty close.

Great.

(Operator Instructions). Your next question coming from the line of Jim Harmon with Barclays Capital. Please proceed.

Thank you. I guess I'm late enough in the queue to get to say good afternoon.

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

No, actually what I said, Jim, is that part of the program this year, horizontals that we'll drill with the second rig coming up fairly soon; part 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're not.

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

Jim, that's a real project by project.

Covington, yes.

I mean Seneca's--the Covington project, Seneca is utilizing that capacity. There is likely to be others that will utilize that capacity. In other parts, though, we are working; for example, the Supply Company project with Range, that's all Range production. And our Midstream has probably, well, I'm looking at them, about 12 or 13 projects with other producers in addition to Seneca. It's going to be--we'd own the Midstream pipe and it's going to be a project by project decision.

Okay. Great. Thank you.

Your next question is a follow-up question from the line of Ray Deacon with Pritchard Capital. Please proceed.

Yes. Hi.

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

Yes. EOG's minimum requirement as a part of the joint venture agreement is 20 wells in calendar 2010. Now from what they have indicated, I expect we'll be at a significantly higher level than that in calendar '10; and our best guess for calendar, or I'm sorry for fiscal 2010 will be, as I said 25 to 30 for fiscal 2010. On the Seneca operated side, we are going to bring in 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.

Got it.

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 a 50% working interest in those.

Okay. Got it.

And has the acreage position changed much since the end of the last quarter?

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

Okay. Got it. Thanks very much.

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

Thank you, Tom.

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