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Executives

Timothy Silverstein – Director of Investor Relations

Dave Smith – Chairman and Chief Executive Officer

Ron Tanski – President and Chief Operating Officer

Matt Cabell – Senior Vice President and President, Seneca Resources Corporation

Dave Bauer – Principal Finance Officer and Treasurer

Analysts

Andrea Sharkey – Gabelli & Company

Kevin Smith – Raymond James & Associates

Craig Shere – Tuohy Brothers

Carl Kirst – BMO Capital Markets

Timm Schneider – Citigroup

John Abbott – Pritchard Capital Partners

Mark Barnett – Morningstar

National Fuel Gas Co. (NFG) F1Q2012 Earnings Conference Call February 3, 2012 11:00 AM ET

Operator

Good day, ladies and gentlemen, and welcome to the first quarter 2012 National Fuel Gas Company earnings conference call. My name is Fab, and I will be your operator for today.

At this time all participants are in a 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. Timothy Silverstein, Director of Investor Relations. Please proceed.

Timothy Silverstein

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

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

With that, we will begin with Dave Smith.

Dave Smith

Thank you, Tim, and good morning to everyone.

National Fuel has had a number of very good quarters in a row, and the first quarter of fiscal 2012 was no exception. Indeed, given the headwinds created by the extremely warm winter and significantly lower gas prices, the quarter was exceptional and clearly demonstrates the value of owning diverse assets.

Overall, earnings were up 4% or $0.03 per share quarter-over-quarter. The increase was largely due to a $15 per barrel increase in realized crude oil price and a 17% increase in Seneca’s production, an increase that I should note was achieved despite the sale of our offshore Gulf of Mexico properties in fiscal 2011.

Excluding the impact to that sale, Seneca’s production was up 40%. Earnings in the regulated businesses which are not particularly commodity price sensitive remain steady and were consistent with our expectations.

In the utility, particularly in Pennsylvania and our Pennsylvania division, earnings were off because of warmer weather. But that was offset by growth in our pipeline and storage segment whereas expected, our recent expansion projects contributed to a $0.03 per share growth in earnings. As we placed additional expansion projects and service, pipeline and storage segments earnings will continue to grow.

So, generally and overall, we’re pleased with our consolidated earnings for the quarter. Despite the significant headwinds that I mentioned earlier, earnings of $0.73 per share were virtually spot on our own internal forecast.

While we can’t control the weather and gas prices, we can and do control our operations. And in that front, we had an excellent quarter.

In the Marcellus, Seneca’s production continues to grow at a rapid pace, nearly doubling quarter-over-quarter. And Seneca was also active in continuing to delineate our acreage with respect to the Utica Shale. Assessing the prospectivity of our Utica acreage is one of our top priorities.

Over the remainder of the fiscal year, we plan to drill at least three additional horizontal wells in the Utica. In California, crude oil production was up slightly from the prior year, due in large part to increased steaming at our Midway-Sunset Field. As we said in the past, our California properties are terrific assets and they generate considerable cash flow. For the quarter, EBITDA from our West division alone was nearly $60 million.

In the pipeline and storage segment, construction of the Line N expansion and Tioga County Extension projects were completed this past quarter, and both projects are currently in service.

Our operational folks did a great job despite a very difficult construction season, which was extremely wet. Both projects were completed essentially on time, and, I should also add, on budget. These projects will have a very meaningful impact on our results in this business segment, adding almost $24 million in revenue in fiscal 2012.

Looking to the future, the research sharp decline in natural gas prices and the resulting effect on cash flows have caused us to revisit the aggressive growth plans we laid out at our analyst day last September. In particular, we’ve taken a hard look at the amount of capital we plan to allocate to Seneca’s Marcellus program.

Simply put, at these gas prices, we’re not planning to grow at the pace we had contemplated. Fortunately, as you know, we’re under no obligation to drill our acreage. Most of our natural gas rates are held in fee and most of our lease acreage is either held by production or has a number of years remaining on its lease term.

Consequently, considering a number of different factors, we plan to move to a four-rig program. These rigs are all under longer-term contracts and will be sufficient to meet the requirements of our long-term frack contract.

Our focus in Appalachia will be twofold. First, drilling Marcellus wells that produce the best economics and, second, continuing the delineation of acreage that is perspective in the Utica. Even with this reduced program, we still expect production will grow by roughly 33% in fiscal 2012.

From a capital standpoint, we’re decreasing the midpoint of the range of Seneca’s 2012 East division capital budget by $70 million. Looking beyond 2012, while we’re not prepared to present revised capital spending estimates, it’s safe to say that given a four-rig program, we anticipate spending substantially less capital than we announced last September.

Now, let me emphasize that the reduction in our plan level E&P spending is entirely related to gas prices. Should they improve, we can and will move quickly to add rigs to our program. Should they continue to deteriorate, we have the flexibility to further reduce our capital budget.

Matt will provide more information on Seneca’s operations and the capital budget later in the call.

With respect to our growth plans in the pipeline and storage segment, low natural gas prices should not have an impact on our near-term expansion efforts. Both the Northern Access and Line N 2012 projects are fully subscribed and will be built this summer. Combined, the two projects will cost approximately $100 million to construct and will add about $20 million in annual revenues once full contract volumes are achieved.

In addition, we recently held an open season for Empire Central Tioga County extension project, which will expand the Empire extension line further South, in Tioga County. We’re pleased with the results of that open season and are increasingly confident that this project will be a go.

Looking longer-term, we believe that our West to East project will be needed in the Western portion of our acreage. But with Seneca and other producers scaling down developments and give our practice of not putting pipes in the ground before capacity is contracted for, it’s likely West to East will either be delayed further or built in small phases.

In closing, the current natural gas price environment will be challenging for natural gas producers, but thanks to our integrated model and thanks to our strong balance sheet, National Fuel is well-positioned for the future.

Though we’re tampering the pace of our growth, we’re confident at our integrated model. And remember that three of the four largest profit centers at National Field, the utility pipeline and storage in California are not significantly impacted by low natural gas prices. So we’re confident at our model. We’ll continue to deliver value to our shareholders over the long-term in any environment.

With that, I’ll now turn the call over to Ron.

Ron Tanski

Thanks, Dave, and good morning, everyone.

Technically, we’re in the middle of our heating season in Western New York and Northwestern Pennsylvania. However, the temperatures during the first quarter were about 20% warmer than last year in both of our New York and Pennsylvania service territories. As a result, we saw our utility throughput for the quarter decrease by 3.4 Bcf year-over-year. Pipeline and storage throughput was also down almost 5 Bcf year-over-year as a result of the warmer weather.

That warmer weather combined with a ready availability of billions of cubic feet of new natural gas supplies across the US, resulting from the success of hydraulic fracturing in shale gas fields, has substantially lowered and dampened the volatility of natural gas prices.

The average delivered gas price for our utility customers for the heating season in New York is projected be approximately 2% lower than prices last year, and about leveled in Pennsylvania. Yesterday, the forward 12-month strip price for natural gas closed at roughly $3.08 per MMBtu on the NYMEX.

And while those lowered gas prices post some near-term challenges for our exploration and production operations, we believe that long live gas reserves at stable gas prices are great for our customers and create long-term opportunities for all of our business units.

While we already have most all of the space heating load in our service territory, we’ve seen more and more interests in natural gas vehicles for fleet that could boast our utility load. Longer-term, we expect further replacements of coal-fired electric plants with gas-fired electric generation that will be seeking capacity from our pipeline and storage segment, and our marketing company.

And finally, as the demand increases for these new uses, we expect to see a leveling of commodity prices that will allow our exploration and production company to plan its capital spending with a little more certainty.

Today, the utility has its gas storage space still 66% full, which is only about 2% higher than where we expect to see it in a normal winter. Other storage customers and supply systems also have their storage capacity at about 66%. And we expect that they will adjust their takes to meet all their required ratchet levels through the end of the storage cycle.

Dave mentioned that our Line N project and Supply Corp in our Empire Tioga Extension went into service last quarter. The Line N project is almost fully ramped up to it design capacity of 160 million cubic feet per day. The Tioga County Extension is fully operational and we’re collecting our contracted demand charges.

However, we’re still waiting for the producers to tie in some of their new production volumes. But those two projects under our belt will be focusing on our Northern Access project and a further expansion of our Line N capacity during the upcoming construction season.

In our Midstream Company, we’re looking to coordinate with Seneca to complete our Trout Run gathering system Lycoming County and get Seneca’s first completed well pad and DCNR Tract 100 tied in and flowing late next month. We’ll see a pickup in production volume in the third quarter once that gathering system goes in service.

I’ll turn it over to Matt Cabell to update us on Seneca.

Matt Cabell

Thanks, Ron. Good morning, everyone.

For the first quarter, Seneca produced 18.2 Bcfe, a 17% increase of last year’s first quarter. Considering that we sold our Gulf of Mexico properties last spring, a more relevant comparison is production growth from our East and West divisions, which are up a combined 40% versus last year’s first quarter.

I’m particularly pleased with our increasing oil production in California. Our Midway-Sunset properties are up over 500 barrels of oil per day due to improved steaming efficiency and new wells coming on line. Next quarter, I expect to see an impact from our new wells at Sesby [ph]. And for the fiscal year, I expect our West division production to be up about 3% versus fiscal 2011, with oil production, in particular, up about 5%.

In the East division, our Marcellus production was up about as is expected, well, up 12% versus the previous quarter and 91% versus the first quarter of 2011. We expect a substantial jump in March as we bring on new production from Tract 595 in Tioga County and another jump in April as we bring on our first pad at Tract 100 in Lycoming County that will flow on the Trout Run gathering system.

This new production will have only a modest impact on second quarter volumes, but will increase our fiscal third quarter substantially. At Boone Mountain, in southern Elk County, we have tested two new Marcellus horizontal wells at rates of 3.8 million cubic feet per day and 4.2 million cubic feet per day. One additional well will be coming on next week.

Later this quarter, we will be testing a well in our Rich Valley area in Cameron County, which will wrap up our current delineation program. At that point, we will have drilled, frac and tested horizontal Marcellus wells across a broad swath of our acreage. While additional delineation drilling will be needed, particularly in the wet gas window, we have established anticipated EURs for many areas, with most of the development area in the 3 to 5 Bcf range, and most of the Eastern development area in the 5.5 to 8 Bcf range.

Although rates of return are acceptable even at today’s futures pricing, we must balance our growth plans with our funding needs. Therefore, we are reducing our Seneca operated rig count to four. For the remainder of fiscal 2012, we’re planning to have one rig at DCNR Tract 595 in Tioga, two rigs at DCNR Tract 100 in Lycoming County and one rig drilling Utica wells on our Western acreage.

This Seneca-operated four-rig program will result in a capital spending reduction of about $70 million. Our EOG joint venture program is committed and not expected to change substantially in fiscal ’12. However, if natural gas prices stay low, we will have the option of not participating in the EOG wells in fiscal ’13, while still maintaining the 20% royalty interest in wells drilled on our fee acreage.

For Seneca-operated program in fiscal 2013 and 2014, we are evaluating a possible multi-rig program to develop our Marcellus wet gas acreage in Western Elk and Forest Counties. Initially, this would be the western most portion of our Owl’s Nest area. Utilizing a cryogenic processing plant, running in partial ethane rejection mode, we believe we can achieve an $0.80 to $0.90 per Mcf uplift in revenues from these wells net of the cost of processing.

In addition to the Marcellus, we are continuing our evaluation of the Utica Shale. We have drilled two verticals and just bought our first horizontal well in the Utica. We have two more horizontal wells planned to test the Utica in two additional areas. Depending on the results, our plans for fiscal 2013 and 2014 may involve substantial additional Utica drilling.

Our overall fiscal ’12 CapEx plan has been revised downward by $70 million or 8% while our fiscal ’12 production guidance has been revised downward by only 4.5%. Fiscal ’13 and ’14 spending will be dependent on gas prices and funding needs. However, I should point out that Seneca can continue to grow production in fiscal ’13 and ’14, even without adding additional rigs.

Fortunately, for Seneca and National Fuel, we have a large perspective acreage position, but minimal lease explorations. We’re able to balance our growth plans with our funding needs and focus our drilling where we see the best immediate opportunities.

Seneca’s long-term growth plans remain ambitious but achievable. Our large contiguous and royalty free acreage position provide the distinct competitive advantage, allowing us to be successful even in a relatively low gas price environment.

The shale gas revolution has transformed our nation’s energy future. Looking forward beyond the next year or two, Seneca and National fuel, with our unique acreage position in Pennsylvania will play an increasingly important role in the development of clean, affordable, domestic natural gas.

With that, I’ll turn it over to Dave Bauer.

Dave Bauer

Thank you, Matt, and good morning, everyone.

Overall, our results for the quarter were fairly straightforward. Dave already hit on the main drivers of earnings and all of the specific details were covered in last night’s release. So I won’t repeat them all here.

I would, however, like to emphasize a point that Dave made earlier. Our $0.73 of earnings, while somewhat lower than the Street’s consensus, were right in line with our internal forecast. Looking at a few of the Street’s models, it appears that some of you are using assumptions that aren’t entirely consistent with the guidance we communicated for our regulated segments. And I’d encourage you to talk with Tim to sort out any differences.

Turning to our earnings guidance for 2012, as you read in last night’s release, we lowered our earnings expectations to a range of $2.40 to $2.65 per share. The change in our guidance is mostly attributable to our updated commodity pricing assumptions. The new earnings forecast assumes flat NYMEX commodity pricing for the remainder of fiscal 2012 of $3 for gas, which is a $1.50 from our prior forecast, and $100 for crude oil, which is a $5 per barrel increase.

We also revised the pricing basis assumptions for our Marcellus production to reflect current market conditions. Our new guidance assumes Dominion index that have used to price the bulk of our Marcellus production is flat to slightly negative to Henry Hub. Our previous forecast assumed that Dominion traded at a slight premium to NYMEX.

We also adjusted our realized prices to reflect both firm sales contracts that have been put in place in current basis estimates for any forecast production that is not linked to an existing firm sales contract.

Again, these changes to our pricing assumptions accounted for substantially all of the reduction in our earnings guidance. The 4 Bcf decrease in the midpoint of Seneca’s production forecast was modest in comparison and our earnings expectations for the regulated segments have not changed.

Turning to our spending plans, as Dave mentioned earlier, we’re reducing the midpoint of our E&P capital budget by $70 million. In addition, we’re trimming our corporate and all other budget by a little more than 20 million to reflect a change in the timing of one of our Midstream projects.

To recap, our consolidated capital budget for fiscal 2012 is a range of $950 million to $1.085 billion and is spread across the segments as follows. $55 million to $60 million in the utility segment, $135 million to $165 million in the pipeline and storage segment, $720 million to $800 million in the E&P segment, and $40 million to $60 million in the corporate and all other segment, most of all which is associated with gathering projects at our Midstream subsidiary.

Moving to our cash flows and financing finance. With the revisions made to our earnings and spending guidance, we anticipate a funding need for 2012 on the order of magnitude of $600 million, which is consistent with our previous estimates. Using our updated pricing guidance, I expect Seneca’s cash from operations will decrease by about $80 million. But that will be offset by the $90 million reduction in capital spending at Seneca and Midstream that I just described.

Our funding need will be met by two recent financing transactions. In November, we sold $500 million of new 10-year notes. The transaction went extremely well. The order book was more than two times oversubscribed and the 4.9% interest rate on the new bonds is the lowest in our debt portfolio.

Proceeds from the issuance were used in part to fund a $150 million long-term debt maturity, and the balance will cover most of our fiscal 2012 funding needs. We have a little more than a year until our next long-term debt maturity, which is for $250 million in March of 2013. We have adequate short-term borrowing facilities in place to cover any additional funding needs.

In January, we took advantage of the improvement in the bank loan market and amended our committed credit facility. In addition to tightening the pricing on the facility and extending its tenure, we upsized it from $300 million to $750 million in anticipation of our growth in spending. The amended facility has a 5-year term and at our current credit rating, there’s interest at LIBOR plus (inaudible). With this new facility, our total short term borrowing capacity now totals just under $1.1 billion.

Looking beyond 2012, we plan to continue to fund our growth from within our balance sheet. Lower natural gas prices will affect our internally-generated cash flows. But moving to a four-rig program at Seneca will have a big impact on our capital needs. In spite of reduced spending, we still expect earnings and production growth in 2013 and beyond as we strategically deploy capital where returns are acceptable and funding needs can be adequately met.

As we said in the past and reiterate today, we’re committed to a strong balance sheet. If market conditions dictate, we have the ability to adjust our spending plans accordingly.

With that, I’ll close and ask the operator to open the line for questions.

Question-and Answer Session

Operator

(Operator Instructions) And your first question will come from the line of Andrea Sharkey of Gabelli & Company.

Andrea Sharkey – Gabelli & Company

Hi. Good morning.

Dave Smith

Hi, Andrea.

Andrea Sharkey – Gabelli & Company

So, one question. I was wondering if you could help me out with the CapEx. It looks like you’ve mentioned the midpoint is dropping $70 million on Seneca and it looks you’re pulling back your well drilling at the midpoint of the range, around 35, 40 wells.

And so, just based on the estimate of $5 million per well, that got me to a $200 million drop in CapEx. So I’m just wondering if you could help understand what am I missing there. And why didn’t CapEx go down by $200 million instead of $70 million?

Matt Cabell

There are a lot of moving parts there, Andrea. First of all, the well count we provide is the well spud during the particular fiscal year. So capital spending is, the cost of a well covers the entire gamut from drilling to the top hold and drilling the lateral to completing the wells.

But probably the biggest factor is, we’ve moved from drilling shallower, shorter lateral wells in our Western acreage to drilling deep long lateral Utica wells and deep long lateral Marcellus in our Eastern acreage. So they tend to take longer and are more expensive.

Andrea Sharkey – Gabelli & Company

Okay, that makes sense. And then, I guess maybe thinking about the wells that you’re not going to drill this year, will that have a great impact on your 2013 production guidance or not really?

Matt Cabell

It will certainly have a greater impact on ’13 than it does on ’12. But we still, as I mentioned in the comments, even if we were to stay at this four-rig program, we would still expect a fairly healthy production increase in fiscal ’13.

Andrea Sharkey – Gabelli & Company

Okay, sure. That makes sense. And then one last question and then I’ll let somebody else have a chance. Did you have to drop any contracted frac crudes since you dropped one rig? Or are you okay with the frac crudes that you have?

Matt Cabell

We only have one frac crude contracted full time and the four-rig program is about right to keep that frac crude busy and meet our contractual obligation.

Andrea Sharkey – Gabelli & Company

Okay, great. Thanks a lot.

Operator

Your next question will come from the line of Kevin Smith with Raymond James.

Kevin Smith – Raymond James & Associates

Hi. Good morning, gentlemen.

Matt Cabell

Good morning.

Dave Smith

Hey, Kevin.

Kevin Smith – Raymond James & Associates

Would you mind in giving me an update on the status of Tract Run gathering system and the completions activities there. I believe you’re previously targeting the start completion activities in January and February. But I guess based off Matt comments, that seems a little bit delayed. But maybe I’m looking at that incorrectly.

Ron Tanski

No, it was a little bit delayed, Kevin. There was a teamster strike that affected us for a little bit there. That’s since been resolved and the drilling was going maybe just a little bit slower and that could have slowed down kind of in response to the delayed completion of Trout Run. So we’re coordinating so that we’re getting them both done together, and it looks like late March.

Kevin Smith – Raymond James & Associates

Okay, then late March is when Trout Run will be completed?

Ron Tanski

Completed and the first well pad and DCNR Tract 100 tied in and flowing.

Kevin Smith – Raymond James & Associates

Oh, okay, got you. All right, so that’s being done on a phase [ph]. So it does – you’re not waiting on Trout Run to be completed before you start completion activities.

Ron Tanski

Well, I mean, they’re going on now as we speak, but again, you know, we would – got to get a whole well – or I’m sorry – a whole well pad done. And so that just takes some time.

Kevin Smith – Raymond James & Associates

Got you. So when we – for the Trout, was it 100 or Tract 100, when are we expecting initial production from that? Is that end of March or more April-ish.

Matt Cabell

End of March, early April.

Kevin Smith – Raymond James & Associates

Okay, great. And then switching gears, any updates on the Utica Shale test and Venango County or in Elk County?

Matt Cabell

Well, I guess, one thing that I think we’ve announced previously is that the well in the Mt. Jewett area which is kind of at the Elk and the Kane border, the vertical well there, we announced, that that is dry gas, good quality dry gas, pipeline quality dry gas. The vertical well in our Henderson area that’s kind of at the Venango, Mercer [ph] boarder, we don’t intend to discuss the makeup of that gas. We don’t intend to disclose that in the near future.

Kevin Smith – Raymond James & Associates

Okay. So we won’t know for awhile whether there’s any liquids components to it, is that fair?

Matt Cabell

That’s fair.

Kevin Smith – Raymond James & Associates

Okay. And then, one other question. Did you guys ever get fix rigs or would just – did you go to five and just drop down to four?

Matt Cabell

We were at six briefly. Our plans, our original plans had us – had us going to six rigs kind of about this time frame.

Kevin Smith – Raymond James & Associates

Got you.

Matt Cabell

We’re now on the process of dropping two rigs.

Kevin Smith – Raymond James & Associates

Fair enough. All right. Thank you very much.

Operator

Your next question will come from the line of Craig Shere with Tuohy Brothers.

Craig Shere – Tuohy Brothers

Hi, thanks for the call. A couple of questions. First, Matt, if that Henderson well in northwest there turns out attractive though it may take a little while for us to hear the results, just how much are you all willing or interested in growing the acreage position out there before we start to see big rig deployment? And then I got a couple of other questions.

Matt Cabell

Yeah, well, obviously, it doesn't depend on the well results, but I think you could probably read between the lines and see that, you know, there’s a reason why we don’t want to disclose anything about that well right away. It is a very competitive area for leasing. And, yes, in fact, we would consider adding to that lease position in that area.

Craig Shere – Tuohy Brothers

Can you at least put some color on the contiguous nature of your existing acreage there and the need for fill ins and what you might consider a critical mass for a good play?

Matt Cabell

Sure, I mean, and I think we actually have enough there for some degree of critical mass already. We got something in the order of 15,000 acreage in that area. There are some gaps in there and joining leases that we want to pick up. And, I guess, that’s about all.

Craig Shere – Tuohy Brothers

Okay, and I think your long-term frac contract ends this year. So could you put a little more color around your flexibility heading into fiscal 2013 to ramp up CapEx if Utica plays out and/or gas recovers in price or ramp down more if neither of those two things happen?

Matt Cabell

Yeah, the frac contract expires in – oh, it’s about April of 2013. So we’ll have that frac crew working most of the next fiscal year even without extending it. It would be quite easy, and – today, it would be fairly easy to add additional rigs. We could probably pick up the same rigs we’re dropping if we wanted to. But, obviously, that’s in today’s environment if gas prices recover rapidly, there will be some demand for additional rigs and I can see that becoming more competitive.

All of that said, I can’t imagine that we’d ever be looking at a delay of more than about six months to add a rig. And I think we could probably, if we wanted to, we could probably get a second frac crew as well. To decrease activity, we have four rigs contracted long term. The first of those four rigs – the first exploration on this long-term contract in those four rigs is July of 2014. Obviously, we can – if we really felt the need to, we could reduce activity and still hold on to that rig. The contract is that onerous.

And the second thing on the slowing down activity, as I mentioned, we have the right in the EOG joint venture to not participate in wells and just – just to maintain our 20% royalty interest on our – the acreage. So that’s another lever we can pull if we find the necessity to in a lower gas price environment.

Dave Smith

And that’s – that’s like a $200 million line item there.

Craig Shere – Tuohy Brothers

Okay, I was going to ask about that. Great. And the very last question, I appreciate all this color, is, can you discuss, if we do get an industry ethane solution, and ethane is priced, I mean, let’s just call it 50% above methane, could you talk – even though it’s a little less pressure and lower EUR in southwest, could you talk about the potential economic uplift there?

Ron Tanski

Yeah, as I mentioned it with the ethane rejection mode, we get $0.80 to $0.90 in Mcfe uplift. In a deep cut where we actually recover the ethane as well, obviously, we would have greater revenue increase. And I’m sorry I don’t have a specific figure for you off the top of my head, but the short answer is, a deep cut with ethane recovery would substantially improve those economics of processing the wet gas.

Craig Shere – Tuohy Brothers

And am I remembering correct that system wise you’re about 6% or 7% ethane left in the system but that it’s a higher percentage as you move to that western area you were talking about?

Matt Cabell

Well, the further west you go the more liquids you have. I mean, it’s fairly simple, the BTU content is higher for the west as you go ahead. But the Marcellus is less mature and therefore in a – more of an oil window and less the gas window. I’m not sure they have a specific ethane percentage for you without talking about the specific location.

Craig Shere – Tuohy Brothers

Understood. I appreciate all the color. Thank you.

Operator

Your next question will come from the line of Carl Kirst with BMO Capital Markets.

Carl Kirst – BMO Capital Markets

Thanks, good morning, everybody. Actually, my questions were all hit. But, Matt, I’m not sure if I got my notes down fast enough. Could you go over the cryogenic one more time as far as where you guys were looking at that and the potential timing?

Matt Cabell

Yeah, if you think about the area where we drilled Owl’s Nest wells in the past – so you can see that on the maps that we put out, this would be kind of just west of that location. So it’s kind of western Elk County and into Forest Country. And we’ve got at Owl’s Nest and sort of along that same – on trend to that part of Owl’s Nest, we would have hundreds of oil location that would fall into that window.

What was the other part that you asked me?

Carl Kirst – BMO Capital Markets

Oh, just, David, because I assume this is you guys would be doing it. And so just – did you mention – I’m not sure if I just didn’t get a chance to write it down, did you mention timing and potential investment dollars?

Dave Bauer

All I said was – we’re looking at this as a possibility for 2013 and 2014.

Carl Kirst – BMO Capital Markets

Okay.

Dave Bauer

And I would say, potentially, as early as, you know, fairly early in fiscal ’13, potentially. It’s something we’re still evaluating.

Carl Kirst – BMO Capital Markets

A $150 million a day kind of facility or (inaudible).

Matt Cabell

That’s part of what we’re evaluating.

Carl Kirst – BMO Capital Markets

Got you.

Matt Cabell

Well, the trade-off there is – the bigger the facility you put in, the longer you have to wait to get enough momentum, enough wells coming into the plant to run it. So there’s kind of a trade-off there between the smaller plant and the larger plant.

Carl Kirst – BMO Capital Markets

Fair enough. And maybe just one other kind of tweaking question from the regulatory side on the pipelines with Line N and Tioga. You know, with the $24 million of revenue sort of being allocated to fiscal 2012, is that something where as – we’ve got Line N now almost fully ramped but Tioga we’re still waiting for producer tie-ins – is that something where the vast majority of that happens in the second half of the fiscal or should we be seeing that kind of allocated ratably here in the last three quarters?

Dave Smith

It will come – well, all across the three quarters, Carl.

Carl Kirst – BMO Capital Markets

Okay. Great. Thanks, guys.

Dave Smith

Welcome.

Operator

Your next question will come from the line of Timm Schneider with Citigroup.

Timm Schneider – Citigroup

Hey, guys, how’s it going?

Dave Smith

Hey, Timm.

Matt Cabell

Good.

Timm Schneider – Citigroup

Hey, a quick question. On the new basis assumptions you guys put out there, can you maybe just talk about what’s driving that and what you’re seeing with respect to pipeline constraints and what contracts you have in place over a longer term firm?

Matt Cabell

Yeah, as you’re probably aware TGP 300 is one of the most utilized pipelines for delivering Marcellus gas to the east coast. And consequently, that basis differential has fallen. At this point, we have firm sales anywhere from just slightly lower than Dominion – South Point to Bay 3010s [ph] below Dominion – South Point.

And then, meanwhile, Dominion – South Point is now trading about flat to NYMEX where as it had been at a premium. Did that – did that answer your – oh, you want to know how much we have (inaudible).

Timm Schneider – Citigroup

Yeah.

Matt Cabell

Well, we have firm sales on TGP 300, I think, April, we’re up to about 130 million a day.

Unidentified Participant

That’s right. Yeah.

Timm Schneider – Citigroup

Okay, got it. Thank you.

Operator

Your next question will come from the line of John Abbott with Pritchard Capital Partners.

John Abbott – Pritchard Capital Partners

Hey, thank you for taking my call there. Just to – maybe I missed a few here, but this well pads you’re bringing up – you’re going to be bringing on, how many wells are on each of those pads? And then, second, what are your latest thoughts about DOGGR in California, the new administration?

Matt Cabell

The pads at 595 – there are two pads that we’re going to bring on at 595. One is a six-well pad; one is a three-well pad, and then track one under. It’s a four-well pad that we’re bringing on. I’m not sure that I have any comments on the second question in California.

John Abbott – Pritchard Capital Partners

All right.

Operator

Your next question will come from the line of Mark Barnett with Morningstar.

Mark Barnett – Morningstar

Hey, good morning.

Matt Cabell

Hey, Mark.

Ron Tanski

Good morning.

Mark Barnett – Morningstar

So you’d mentioned that the west to east pipe was going to be a little bit delayed and potentially done in a series of smaller projects. You initially estimated that that could be like a $280 million to $300 million project. If it does end up going forward with some smaller projects, do you have kind of an idea of what kind of spend you’d see there or is it too early?

Ron Tanski

It’s a little bit too early at this point, Mark, because one of the things that will drive where we go with various sections of that pipe is what’s going on in the market generally and where Seneca is doing all its drilling. So it really is a little bit too early at this point. But the concept would be to get these sections in place that we can get that flowing gas into an interstate market. So I – it’s just too hard to pinpoint at this point.

Dave Smith

Yeah, and I think the important thing to recognize is that we won’t – we won’t build that pipe or sections of that pipe without having it contracted for. So we just don’t do it on speculations with – we’d have to have signed contracts before we start putting that in.

Mark Barnett – Morningstar

Okay. I guess, just regarding any of the smaller plan projects with the curtailments and whatnot and with your own ramp down, are there any other projects that are potentially looking at kind of a delayed timeframe or...

Ron Tanski

No, no, Northern Access is full go. We’ve got the Line N extension. We’re adding more compression capacity on Line N to be able to take in more production from range resources. And, again, we’ve gotten more, I guess, we’re surprised that the further Tioga County Extension that people are ramping up their interest there – or central Tioga County Extensions. So, no, we don’t see any slowdown in what we’ve talked about before.

Mark Barnett – Morningstar

Okay, I think – and just a last quick question, maybe, a sort of, a more general question. With gas prices where they’re at, have you thought about your hedging strategy in this and maybe that’s going to be any different this year or is it kind of a little – is that not really going to change?

Dave Smith

Yeah, I think our general hedging strategy will stay the same where we’ll take advantage of the Contango shape of the curve and layer new trades throughout the course of the fiscal year. What I think may be different is that given where prices are, we may be towards the lower end of our range of hedge percentages. If you go to our IR deck, we have a graph in there that show sort of where we generally like to be at different points in the fiscal year. And we may be towards the low end of that range.

Mark Barnett – Morningstar

Great. Appreciate the detail. Thanks, guys.

Dave Smith

Okay.

Operator

Your next question is a follow up from the line of Timm with Citigroup.

Timm Schneider – Citigroup

Hey, guys, just real quick, because I was rushing through my notes here, I just want to make sure I got this right. Did you say, with respect to Owl’s Nest and liquids, did you say that you think all of the 90,000 acres are perspective for liquids or it that just a location of where you’ll have the cryo plant potentially?

Matt Cabell

It’s not all 90,000 acres, no, it would be more the western portion of that, but then, it’s not just Owl’s Nest, we could – you can kind of move and – a long trend to that same area at Owl’s Nest and they’re – we’ve got quite a bit of acreages that falls into that window.

Timm Schneider – Citigroup

All right. So as I look at your map here, recent presentation, page 19, the stuff you have in Mercer, that’s the 15,000 acres, correct? That’s the Henderson area?

Matt Cabell

Right.

Timm Schneider – Citigroup

Okay, got it. All right. Thank you.

Operator

And there are no further questions. I would now like to turn the call back over to Mr. Tim Silverstein for closing comments.

Tim Silverstein

Thank you, Deb [ph]. We’d like to thank everyone for taking the time to be with us today. A replay of this call will be available in approximately 2:00 pm Eastern Time on both our website and by telephone. And we’ll run through the close of business on Friday, February 10, 2012.

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 562-172-87.

This concludes our conference call for today. Thank you and goodbye.

Operator

Thank you very much. This concludes today’s conference. Thank you for your participation. You may now disconnect. Have a great day.

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