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Executives

Jim Welch - Director, IR

Dave Smith - President & CEO

Matt Cabell - President, Seneca Resources Corporation

Ron Tanski - Treasurer & Principal Financial Officer

Analysts

Jonathan Lefebvre - Wells Fargo Securities

Carl Kirst - BMO Capital

Becca Followill - Tudor, Pickering, Holt

Tim Winter - Gabelli & Company

Brian Horey - Aurelian

Holly Stewart - Howard Weil

Ray Deacon - Pritchard Capital

National Fuel Gas Co. (NFG) F1Q10 (Qtr End 12/31/09) Earnings Call February 5, 2010 11:00 AM ET

Operator

Good day ladies and gentlemen, and welcome to the first quarter 2010 National Fuel Gas Company earnings conference call. My name is Jasmine and I'll be your operator for today. At this time, all participants are in listen-only mode. Later we will conduct a question-and-answer session. (Operator Instructions). As a reminder, this conference is being recorded for replay purposes.

I would now like to turn the conference over to your host for today, Mr. Jim Welch, Director of Investor Relations. Please proceed.

Jim Welch

Thank you and good morning everyone. Thank you for joining us on today's conference call for a discussion of last evening's earnings release. With us on the call from National Fuel Gas Company are Dave Smith, President and our 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. As you read in last night's release, National Fuel's earnings for the first quarter of Fiscal 2010 were $64.5 million or $0.78 per share, up approximately a $107 million or a $1.31 per share over the first quarter of fiscal 2009.

Adjusting for non-recurring items, the largest of which was the ceiling test charge Seneca recorded in last year's first quarter. Operating results improved slightly quarter-over-quarter. Overall, particularly given the decline in gas commodity prices, it was a strong quarter for National Fuel and a very good start to the fiscal year.

Our utility distribution corporation posted another quarter of solid reliable earnings consistent with the role in our integrated system. Our E&P company, Seneca resources increased total production by 20% quarter-over-quarter which was enough to offset the effects of that lower natural gas prices had not only on Seneca's production revenues but also on Supply Corporation's efficiency gas revenues.

Bottom line, we're very pleased with our financial results for the first quarter. We're also pleased with the progress we've made in the field. We continue to execute on our plan to focus our capital and other resources on Appalachia. And we're just beginning to see the fruits of that labor in the E&P segment where in the last quarter we achieved first production from our Seneca operated Marcellus program.

In mid-November, Seneca brought its first two Tioga horizontal wells on line. Production from these two wells for just that limited period of time accounted for almost 30% of the increase in the east division's production for the quarter.

As a result, the Seneca's success in the Marseilles, we are raising our E&P capital budget, and we expect by year's end to employ four rigs in the Marseilles; two in the east, two in the west. Matt will provide a full update on Seneca's operations including the Gulf and West Divisions later on the call.

Complimenting Seneca's efforts, in November NFG Midstream completed construction of the first phase of the Covington gathering system in Tioga County which delivers Seneca's Tioga production into Tennessee's 300 line. Midstream is working on the second phase of that project which will extend that system further south to Seneca's acreage on state track 595, which Seneca expects to begin drilling this summer.

The necessary rights of way have been acquired and the pipe has been purchased, construction is underway and progressing as we speak and we expect like the first phase that the second phase of the Covington system will be completed in time to coincide with Seneca's fist significant production of that acreage.

Turning to the Regulated Pipeline and Storage segment; we continue to make progress on our multiple expansion opportunities. Supply Corporation has secured the market commitments necessary to support the Lamont and Line-N expansion projects. As a result, this are both go projects that will be moving forward, and both are proceeding according to schedule. As you will recall at Lamont, Supply Corporation will build a new $6 million, 1,200 horse power compressor station that will provide an additional 40 million a day of take away capacity at an interconnection with Tennessee.

The station side has been acquired, and the compressor units ordered. Construction is expected to start this March for a June 2010 in service day. The Line-N project is a $23 million pipeline in construction project at the South Western end of our system that will move a $150 million a day of Marcellus production, most of it range resource production. To an interconnection with Texas Eastern.

Supply Corporation began the pre filing process in October and expects to file its FERC application this April assuming all goes well and we think it will the Line-N projects should be in service in November 2011.

I should also note that given the interest producers have indicated for additional capacity on both of these projects the Lamont and line-N projects are being designed to be readily expandable.

Another major pipeline project that will be built is the Tioga county extension project which will extend the empire connector from Corning, New York about 16 miles south through Jackson Township in Tioga County, Pennsylvania an area where there has been significant Marcellus production.

That project which is estimated to cost $45 million will also include modifications to Empire's existing facilities, modifications that will allow for by directional flow ultimately into the TransCanada pipeline system at Chipola.

Empire has executed a binding precedent agreement with an anchor shipper for $200 million a day of firm transportation which is enough in it of itself to support that project moving forward and we are optimistic that we will sign agreements for at least another $100 million a day with other Marcellus producers in the region.

Preliminary routing and environmental work have been completed and engineering work is now underway. We expect to file an application with FERC sometime this summer the projected and service date September 2011. Lastly supply continues to see strong interest from Marcellus producers in the initial phases of its west to east project.

The first phase which would go in service in 2011 is designed to move a $100 million a day of Marcellus production through a new 39 mile pipeline extending through Elk, Cameroon and Clinton Counties to Leidy Hub. The second phase which will provide an additional $325 million a day of capacity starting in 2012 extends the west to east system another 43 miles through Clearfield and Jefferson counties to our line-K system.

Currently Supply Corporation has executed press agreements for a $100 million a day of firm transportation service and is now in the process of finalizing agreements for another 75 million a day. While this not enough to support the entire project we believe the anticipated level of Marcellus drilling in the area will ultimately require the construction of a major pipeline like the west east project and we remain very optimistic that it will be built. We will continue to market its capacity and we will continue to keep you informed on our progress.

In closing this was a great quarter fore National Fuel, particularly with regard to our accomplishment in Appalachia. Well we will continue to focus our efforts and our resources. And to that end and this is probably as good a form as any to announce it Jim Welch who heads our IR efforts will be moving over to Seneca as the Marketing Manager for the Appalachian Production.

Jim did a great job for us in IR and given his work ethic and his prior experience in interstate marketing I have no doubt he would do a great job at Seneca.

Replacing Jim as Director of IR will be Tim Silverstein who like Jim has had the benefit of working with various departments including IR as part of our rotating MDA program. We're all confident that Tim will do a great job in his new position and I am sure you will all get to meet Tim in the near future. So with that I thank you for your attention and I will turn the call over to Matt for an update of Seneca operations.

Matt Cabell

Thanks Dave, good morning everyone. Seneca had a great quarter with production up over 20% versus last years first quarter. West division production was essentially flat while the Gulf was up 42% and the East was up 48%. The gulf production increase is primarily due to the hurricane shut-ins experienced last year that also reflects new production this year from our Cyclops field. We are planning to spend only $15 million to $20 million in the Gulf this year which includes the drilling of a third well at Cyclops which we expect to spud some time this month.

In California, the natural decline was offset by new production from our Ivanhoe acquisition. We recently drilled six new wells on the South Midway Sunset property that we acquired from Ivanhoe with very encouraging results confirming some of the upside potential we had recognized at the time of the acquisition. We have eight more development locations planned at this fiscal year and expect to drill to another 15 to 20 next year. This year's program should add approximately 200 barrels of oil per day by year end.

In the East, we have solved most of our system constraints for our traditional shallow production and also brought on production from the Marcellus Shale. We have had two Seneca operated Marcellus wells producing into the Covington system since early December. These two wells had a combined average rate of about 8.5 million cubic feet per day for the month of December. Since our last earnings call we have fraced two more wells in Tioga county. The first floated in an initial rate of over 10 million cubic feet per day an average 9.5 million a day over seven days. This well had a 5700 lateral and was fraced in 15 stages. We also attempted a zipper frac on two adjacent parallel wells. The first few zipper stages went well but we ultimately had to abandon the zipper frac process due to an operational problem with one of the wells. We completed the fracing of the other well and we will be flow testing it this weekend.

Our average seven day IP over our first three Seneca operated horizontals is 6.7 million cubic feet per day. Last month, we participated in the Pennsylvania DCNR lease sale. We were the high bidder on two blocks. Our total high bids were $71.8 million. Bidding was very close such that we left only $3.6 million on the table. These two new blocks add 18000 acres in Tioga and Potter Counties not far from our Covington area activity.

In the more western portion of our overall acreage position, we are nearing TD on a horizontal well in McKean County and preparing to frac a well in Elk County. These two wells and several others planned for the next few months will be a very important test of the western extent of our acreage. These wells will give us a first indication of potential flow rates and gas processing requirements.

Regarding our Marcellus joint venture with EOG, EOG has now drilled 22 horizontal wells, 12 have been fraced and five are producing. EOG currently has two horizontal rigs drilling in the (inaudible) development area where we are expecting first production by the end of March.

Looking at our Marcellus drilling plans, we are now planning to add a third rig in April or May, and therefore now expect to drill 35 to 45 Seneca operated wells, this fiscal year. We now estimate our fiscal 2010 Marcellus shale capital spending to be $260 million to $280 million including the $72 million we are spending for the new DC in our leases. This will raise Seneca's overall capital spending to a range of $320 million to $370 million.

With this increased activity, and our latest drilling success, we're also upping our production guidance to a range of 44 Bcfe to 51 Bcfe for fiscal 2010, which includes 5 Bcf to 7 Bcf from the Marcellus, mostly from our Seneca operated Tioga County focus area.

In summary, Seneca's first quarter results were excellent. Production increased substantially. We validated the potential of our recent California acquisition, and our Marcellus drilling results surpassed our expectations. We're on track for production growth exceeding 10% this fiscal year and are confident that we will see 20% growth in 2011 and beyond. With that I'll turn it over to Ron.

Ron Tanski

Thanks Matt, and good morning everyone. From a financial reporting perspective, there are no extraordinary items that impacted earnings for the first quarter of fiscal 2010. However, there are a couple of things that I'll point out that may affect analyst's models going forward.

Now Matt already mentioned an increase in the CapEx budget for the exploration and production segment. The E&P budget range that I talked about on our November call was between $245 million and $293 million. The current range is between $320 million and $370 million with the following allocation

$120 million and $370 million with the following allocation among divisions. In the Gulf Coast, we have allocated $15 million to $20 million. In the West Coast, $25 million to $35 million, Appalachian shallow Devonian $20 million to $35 million and Appalachian Marcellus $260 million to $280 million.

If you use the middle of that budget range for the exploration of production segment or $345 million the consolidated CapEx budget for the company is now targeted at $502 million. The increase in the CapEx results primarily from Seneca's most recent lease acquisition of Pennsylvania, and while we will be out spending our cash flow this budget increase is not large enough to drive us to the capital markets.

From a cash flow perspective factoring into $502 million in capital spending for the year and using the middle of our earning guidance range, we expect to be cash flow negative for the entire year by roughly $110 million. We still have cash reserves and plenty of credit capacity that cover our working capital needs and to handle this extra $110 million cash requirement.

The other item that I wanted to point out was the assumption for the DD&A rate to use for Seneca's production. Last August our preliminary guidance was to use your rate around $2.35 per Mcfe. Now after the finalization of our reserve study and the year end calculations for our depletable base and projected production volumes, we think the rate for our 2010 fiscal year will be more in the range between $2.15 and $2.20 per Mcfe.

Looking forward through the remainder of the fiscal year, there are three main items that can cause variances in our projected earnings. The first is variations in weather. As we reported in the back pages of last evening's release, weather for the first quarter was slightly warmer than last year and we saw a corresponding decrease in throughput across our pipeline and utility systems.

Notwithstanding that decrease in throughput, earnings in the pipeline and storage segment were not dramatically affected because of their straight fixed variable rate design. At the utility, the weather normalization clause also operated to maintain our margin and our continued focus on controlling costs in the utility helped us to achieve a slight uptick in earnings.

The second item that can affect our earnings volatility or can affect our earnings is volatility in commodity prices. We've again included an updated sensitivity table at page 21 of yesterday's release to give you an idea of the impact of changing commodity prices on our earnings.

The third item is the timing of getting new Marcellus production online. The production guidance range between 44 Bcfe and 51 Bcfe is as wide as it is to accommodate the uncertainties of getting the new Marcellus gas flowing from both Seneca operated wells and our non-operated joint venture wells as well as a possible shut-in of gulf coast production during hurricane season later in the year.

Before we open up the line for questions, I'll point out that the hedges that we have listed on page 19 of the release reflect the hedging of approximately 56% of the production for the remainder of the year if you use the midpoint of our production guidance. With that Jasmine, we'll open up the line for questions.

Question-and-Answer Session

Operator

(Operator Instructions). Your first question comes from the line of Jonathan Lefebvre with Wells Fargo Securities.

Jonathan Lefebvre - Wells Fargo Securities

In the release you mentioned that the pipelines were impacted by $0.08 due to lower efficiency on gas revenues mainly due to lower commodity prices. My question is the gas efficiency, is that essentially retained fuel on the pipes and then going forward how should we interpret this to impact the earnings for this year?

Dave Smith

Yes it does retain gas and I don't think it was $0.08, I think it was more in the range of $0.02 to $0.03, that was the efficiency gas and moving forward there is no question that the gas commodity price is going to ultimately impact that efficiency gas number and I think last year it probably averaged first quarter less than $4 or so, so it's a pretty skinny number, this first quarter compared to the prior year.

Jonathan Lefebvre - Wells Fargo Securities

Should we be thinking about this impacting, it was offset partly by Empire connector, can we get a sense for how much that offset there and then is there any sensitivity in terms of gas price that you can give us for how that might impact this year.

Dave Smith

Well we have the gas price sensitivity table in the back include both the impact for on efficiency gas and Seneca production. So that those are both rolled in there together and I don't have the breakout right at my finger tips as to what that is. But yes, I guess a very, very rough approximation and again this is rough, we had normally seen about 3 BCF of efficiency gas in a normal year at normal transportation volumes. So if you use that as a rough guideline and compare that to the throughput numbers that we have in the back pages and get a sense for where that might be headed.

Jonathan Lefebvre - Wells Fargo Securities

And then going forward are you going to breakout the Marcellus production from the Appalachia production as you ramp up or will it be consolidated?

Dave Smith

Yes, I mean it will probably just still report the Appalachian, we've already got a large breakout. We broke out the number of wells, Marcellus wells drilling activity, but again much more detail I don't know that you gain all that much.

Operator

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

Carl Kirst - BMO Capital

Ron, you had mentioned about the range of the production for this year. When we look at the number of Marcellus Shale wells being drilled, should we still think of that as roughly half of those been turned to sales, and can you remind there is kind of post Covington coming on line this summer, what's going to be the biggest constraint towards ramping that up?

Ron Tanski

The base forecast that we have Carl, normally had a six-month delay built in terms of the drilling activities from the completion of drilling activities to the turning into line, to the extent that those wells are drilled in the Tioga area, we obviously won't have that constraint, so it's really a matter, Matt maybe can help me out in terms of where the locations are.

Matt Cabell

I just wanted to expand on Ron's comment about Tiago County. Even in Tiago County, we will have cases where the particular pad we are drilling on now is a six-well pad. We will drill all six of those wells before we frac any off them. So the production will be lumpy. It's most efficient, most cost-effective, if we drill up a pad, frac the whole pad and then put it all online, so the first well on that pad maybe drilled six months before it comes online.

I think that's really what, that's a big impact plus there are wells that we'll drill in the Western side of our acreage there more kind of get a flow test and determine whether that's the next development area, which won't necessarily go online for a long time. And then there is the EOG piece of the production which we have less control over, and it's a little more difficult for us to predict.

Carl Kirst - BMO Capital

With respect to the two Western wells right now, the one that's being fraced, the one that's getting close to TD. Is that something where if those are material I guess and as much as perhaps you are close to mimicking Tioga. Would you guys be press releasing those or this is something that essentially we should be waiting till next quarterly conference call or is that something you can even address at this point?

Dave Smith

Carl, I would expect that given there is a well, Matt talked about in the eastern area that we would have talked about today and then in these western area, I would think we would lean towards disclosing that, if it were material.

Carl Kirst - BMO Capital

Okay. And then last question if I could, I'll jump back in the queue, but with respect to the results this fourth quarter, the LOE looks like it was very nice number, low number ex-taxes. Is that something that we think can be sustained or are we going to see that rise back up?

Matt Cabell

Well, one of the things that affects LOE is our production rate. So as production goes up, the unit LOE goes down. The other thing that has a big impact on our LOE is the cost of the gas that we need for steam fuel in California. So, higher Natural gas prices while we still prefer them for our revenue side actually, the higher the gas prices, the more it hurts our LOE in California.

Carl Kirst - BMO Capital

Maybe I can ask that in another way but to the extent that gas prices kind of currently stay in sort of this $5 range, and if you annualize fiscal first quarter production, it basically gets you roughly to the midpoint or around there. Under those two, if we kind of keep the production where it is and where gas prices would LOE basically be staying in the same range then?

Dave Smith

I think that's probably a reasonable assumption Carl if the average gas price for the year is equivalent to the average gas price for the quarter in California.

Operator

(Operators Instructions). Your next question comes from the line of Becca Followill with Tudor, Pickering, Holt. Please proceed.

Becca Followill - Tudor, Pickering, Holt

Matt, can you walk through again, I missed some of what you were talking about in Tioga County on the zipper frac on what happened and you said the average of the there wells were 6.7 million a day. I assume that excludes the wells that we've had to ban in the frac. Can you just walk through that again?

Matt Cabell

Sure. We started the zipper frac and the way the zipper frac works we have two parallel horizontal well bores and we alternate stages in that fracture treatment. So we're fracing one well bore, then the next well bore back and forth as we walk our way from the toe of the well to the heel. We got through the first several stages in both wells. Then we actually had a proliferating gun stuck in one of the wells. We rather than taking the time to fish that proliferating gun, we just continued to frac the other well. So we've completed the frac of one well. That well will begin flowing this weekend actually. I think it's probably beginning to flow as we speak but I don't want to bray on it yet. The other we'll have to go back in there and fish out that proliferating gun before we finish that completion.

Operator

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

Carl Kirst - BMO Capital

I just wanted to follow-up with one last item. With respect to the lease sale that was just done, as you guys are evaluating capital spent between the west and the east, the west is kind of slowly in this nascent stage. Should we be expecting perhaps more acreage being added in the east whether its to through lease sale or perhaps even other agreements or is it now that we're getting kind of a critical mass in the east, we are going to stay and pat. Lets see what we get in the west and perhaps ramp up dollars in the west if it so demands it.

Dave Smith

Carl, I guess I'll repeat our strategy for lease acquisitions in the Marcellus. We acquire acreage that is a adjacent to our exiting acreage. That makes sense to acquire. And we also will look at large contiguous blocks in an area that we think may in someway be superior to some of our existing acreage. These TCNR blocks are in a very, very good part of the Marcellus. So these are big blocks that we like and that we're able to acquire at we think is a very favorable price per acre.

There is no reason why we would stop looking at those kind of opportunities and it really has no baring on what we're doing on the west side. In other words we've got a plan for the west which is drill a handful of kind of test wells this year, get flow rates, understand gas processing requirements, then determine focus areas to develop and prioritize those focus areas.

Operator

Your next question comes from the line of Tim Winter with Gabelli & Company. Please proceed.

Tim Winter - Gabelli & Company

I have more of a big picture question. Can you talk a little bit about strategy going forward as the CapEx budget grows and resources necessary to take advantage of the Marcellus growth, should we just assume come 11, 12 just straight debt and equity financing to fund the capital expenditure program or how are you considering other creative structures like in MLP or may be a portfolio approach to the west assets versus the east assets may be deploying selling some of those and deploying cash into the east, can you talk a little bit about that.

Dave Smith

Yeah there are a lot of questions in there Tim but let's just generally talk about the CapEx which does increase from about $500 million this year to over $900 million in 2012. So there's no question that we will be increasing the CapEx, much of that is in that pipeline and storage area because of those big projects we talked about and much of it is ramping up in the Marcellus.

Right now even with all of the projects we have on the table, number one we still have a fair amount of cash, number two I think this year went may be negative cash flow a $103 million.

So we are really in a pretty good position to lever up over the next couple of years and even with the projects we have on the table we are still within our 50-50 debt equity ratio that we target. So we are in pretty good shape in terms of being able to allocate capital in particular to those two areas.

Now with regard to things like MLPs, we have a study that's looking at the advisability of MLPs. We're always looking at various alternatives certainly a number of different priorities have approached us with regard to things like joint ventures, so all of those kind of mechanisms, all of those opportunities, we will measure on a case-by-case basis, but it has to be pretty compelling given that I think we're in a pretty good position right now with where we are in our ability to lever up.

Operator

Your next question comes from the line of Brian Horey with Aurelian. Please proceed.

Brian Horey - Aurelian

Thanks for taking my question. It sounds like things are going well generally in the Marcellus and the question I had was there's been a lot of commentary about the issue of water use in the region and processing of frac water and so forth and I'm wondering if you can provide some commentary, one on from a little bit more of a macro perspective, how bigger constraint do you think that is for the play in general and what do you see the industry doing to try to manage that and secondly specifically what do you guys have in place to deal with those issues?

Dave Smith

We're actively recycling all of our frac water and I think more and more, that's the direction and the industry is headed. I think long-term there the processing of frac water, maybe one of the more important factors in kind of limiting the pace of which industry can move but so far I think industry is doing a good job of staying ahead of it and I don't think we have any significant impact to our program.

Jim Welch

Yes, and Brian it would be I think, its fair to say more significant impact if we were in New York as suppose to Pennsylvania. I'm aware that certainly the New York City, communication lets say, the New York City group has clearly working pretty hard, in the water scenario of New York City in the Marcellus to keep that fracing out and but in our case we have been fracing for 40 years probably since the sixth.

Matt Cabell

If the quarter is also about hydrofracing, that's a whole other different case and we are not having any problems in Pennsylvania and the industry is addressing the issue of hydrofracing and potential regulation at the federal level and frankly the EPA has determined there is no significant risk and the fracture stimulation is effectively regulated at the state level.

Operator

Your next question comes from the line of Holly Stewart with Howard Weil. Please proceed.

Holly Stewart - Howard Weil

Good morning guys, just quickly can you talk about some of the recent well results under the EOG (JV) and then how much that contributed to production during the quarter?

Matt Cabell

Sure. Holly, the EOG MO has been not to frac in the winter months. So they drilled, I think I said it in here, they drilled 22 wells and frac. I don't remember exactly what the number is, the frac, 12.

Holly Stewart - Howard Well

I guess 12.

Dave Smith

Yeah the frac 12 and 5 are producing. The area where they're most active is the Punxsutawney development area. None of those wells are online. We expect that first production toward the end of March and they'll bring on several wells kind of back-to-back and ramp that production up gradually in that area. I really don't have any new flow test results because it's been a long time since they have fraced a well but in general these have been wells in Punxsutawney that are all from, maybe the weakest wells are little less than 2 million a day IP's and the best are approaching 4 but little less than 4.

Holly Stewart - Howard Well

And then production impact during the quarter?

Dave Smith

During the first quarter, our first quarter the production impact we had about pretty close to half a Bcf of production from the Marcellus and 60% of that was from our two wells of Tioga County and is net production and the remainder is from the EOG wells.

Holly Stewart - Howard Well

And if you want to talk about the upcoming quarter you can do that as well.

Dave Smith

Well as we stand today our Marcellus production right now is about 80% from our three wells in Tioga and about 20% of our net production is from the five producing wells from EOG. Keep in mind two of those EOG wells, the two earliest wells are wells where we have a minority interest. The other three we have 50% working interest and 60% NRI.

Holly Stewart - Howard Well

Perfect. That's all I had.

Operator

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

Ray Deacon - Pritchard Capital

I have a question for Ron about the pipeline announcements. Do these smaller projects you announced, do they change the scope of west to east line and can you just talk about what the earnings contribution could be from that by the time it is online if it does more forward?

Ron Tanski

We really don't change the overall scope rate. They change the timing we had talked about through time that the entire west to east appellation lateral was such a big project that it is tough to get all of the market support all at once to allow us to move forward. So we broke that into smaller pieces and essentially the projects that we have now that Dave talked about and that we haven't released and of the central portion of the west to east corridor and on either and end. And then ultimately we're going to hook that all up together with smaller projects. I think it's a little early to start talking about the earnings contributions and specifically the timing of those because most of these are projects that will be coming out in late 2011 and they may not even affect or impact earnings for 2011. We're talking more 2012 time frame.

Operator

At this time there are no further questions. I would now like to turn the call back over to your host for today Mr. Jim Welch. Please proceed.

Jim Welch

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 PM Eastern Time on both our website and by telephone and the run to the close of business on Friday February 12, 2010. To access the replay online visit our investor relations website at investor.nationalfuelgas.com and to access by telephone, call 1-888-286-8010 and enter pass code 42539167. This concludes our conference call for today. Thank you and good bye.

Operator

Ladies and gentlemen that concludes today's conference. Thank you for your participation. You may now disconnect. Have a great day.

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