National Fuel Gas Co (NFG) 2012 Q1 法說會逐字稿

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 listen-only mode. Later we will conduct 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.

Thank you, Fab, 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.

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 prices, 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 of that sale, Seneca's production was up 40%.

Earnings in the regulated businesses, which are not particularly commodity price-sensitive remained 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 where, as expected, our recent expansion projects contributed to a $0.03 per share growth in earnings. As we place additional expansion projects in service, Pipeline and Storage segment earnings will continue to grow.

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

While we can't control the weather or gas prices, we can and do control our operations. And on 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 recent 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 are not planning to grow at the pace we had contemplated.

Fortunately, as you know, we are under no obligation to drill our acreage. Most of our natural gas rights are held in fee, and most of our leased 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 frac contract.

Our focus in Appalachia will be twofold. First, drilling Marcellus wells that produce the best economics, and second, continuing the delineation of our acreage that is prospective 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 are decreasing the midpoint of the range of Seneca's 2012 East division capital budget by $70 million. Looking beyond 2012, while we are 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 of 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's central Tioga County Extension project, which will extend the Empire Extension line further south in Tioga County. We are 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 development plans. And given our practice of not putting pipe in the ground before capacity is contracted for, it's likely West to East will either be delayed further or built in smaller 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 are tempering the pace of our growth, we are confident that our integrated model -- and remember that three of the four largest profit centers at National Fuel, the Utility Pipeline and Storage in California, are not significantly impacted by low natural gas prices. So we are confident that our model will 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.

Thanks, Dave, and good morning, everyone. Technically we are 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 at 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 the ready availability of billions of cubic feet of new natural gas supplies across the US resulting from the success of hydraulic fracturing and shale gas fields has substantially lowered and dampened the volatility in natural gas prices.

The average delivered gas price for our utility customers for the heating season in New York is projected to be approximately 2% lower than prices last year, and about level 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 lower gas prices posed some near-term challenges for our exploration and production operations, we believe that long-lived 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 interest in natural gas vehicles for fleets that could boost 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 would expect to see it in the normal winter. Other storage customers on 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 on Supply Corp. and our Empire Tioga Extension went into service last quarter. The Line N project is almost fully ramped up to its design capacity of 160 million cubic feet per day. The Tioga County Extension is fully operational and we are collecting our contracted demand charges. However, we are still waiting for the producers to tie in some of their new production volumes. With those two projects under our belt, we 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 are looking to coordinate with Seneca to complete our Trout Run gathering system in Lycoming County and get Seneca's first completed well pad on DCNR Tract 100 tied in and flowing late next month. You will see a pickup in production volume in the third quarter once that gathering system goes in service.

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

Thanks, Ron. Good morning, everyone. For the first quarter Seneca produced 18.2 Bcfe, a 17% increase over 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 am 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 online. Next quarter, I expect to see an impact from our new wells at Sespe, 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 expected, 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, fracked 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 Western 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 plan 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 a 20% royalty interest in wells drilled on our fee acreage.

For our 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 westernmost portion of our Owls 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 spud 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 prospective acreage position, but minimal lease expirations. We are 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 provides a 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.

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 are 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 forecasts. 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 would 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 $3.00 for gas, which is $1.50 drop from our prior forecast and $100 for crude oil, which is a $5.00 per barrel increase.

We also revised the pricing basis assumptions for our Marcellus production to reflect current market conditions. Our new guidance assumes the Dominion Index that is 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 and 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 and Matt mentioned earlier, we are reducing the midpoint of our E&P capital budget by $70 million. In addition, we are 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 all of which is associated with gathering projects at our Midstream subsidiary.

Moving to our cash flows and financing plans, 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 booked was more than 2 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 tenor, we upsized it from $300 million to $750 million in anticipation of our growth in spending. The amended facility has a five-year term, and at our current credit rating, there is interest at LIBOR+1 1/8. 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've said in the past and reiterate today, we are 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.

(Operator Instructions). Andrea Sharkey, Gabelli & Company.

Good morning. 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 like you are pulling back your well drilling at the midpoint of the range, around 35 to 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 me understand what am I missing there, and why didn't CapEx go down by $200 million instead of $70 million?

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

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 wells in our Eastern acreage because they tend to take longer and they are more expensive.

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 greater impact on your 2013 production guidance or not really?

It would certainly have a greater -- 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 2013.

Sure, that makes sense. And then one last question and I'll let somebody else have a chance. Did you have to drop any contracted frac crews since you dropped one rig or are you okay with the frac crews that you have?

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

Okay, great. Thanks a lot.

Kevin Smith, Raymond James.

Good morning, gentlemen. Would you mind giving me an update on the status of Trout Run gathering system and the completions activities there? I believe you were previously targeting to start completion activities in January, February. But I guess based off Matt's comments, that seems a little bit delayed, but maybe I'm looking at that incorrectly.

No, it was a little bit delayed. There was a Teamsters 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 are coordinating so that we are getting them both done together. And it looks like late March.

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

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

Oh, okay. Got you. All right, so that's being done simultaneously. You are not waiting on Trout Run to be completed before you start completion activities?

Well, I mean they are going on now as we speak, but again, we've got to get a whole well -- or I'm sorry, a whole well pad done and that just takes some time.

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?

End of March, early April.

Okay, great. And then switching gears, any updates on the Utica shale tests in Venango County or in Elk County?

Well, I guess one thing that I think we have announced previously is that the well in the Mt. Jewett area, which is kind of at the Elk-McKean border, the vertical well there, we announced that that is dry gas, good-quality dry gas, pipeline quality gas.

The vertical well in our Henderson area that's kind of at the Venango/Mercer border, we don't intend to discuss the makeup of that gas. We don't intend to disclose that in the near future.

Okay. So we won't know for a while whether there's any liquids component to it; is that there?

That's fair.

And then one other question -- did you guys ever get to six rigs or would you just go to five and just drop down to four?

We were at six briefly. Our plans -- our original plans had us -- had us going to six rigs kind of about this timeframe.

Got you.

We are now in the process of dropping two rigs.

Fair enough, all right. Thank you very much.

Craig Shere, Tuohy Brothers.

Hi, thanks for the call. A couple questions. First Matt, if that Henderson well in the 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've got a couple other questions.

Yes, well, obviously it does depend on the well results, but I think you could probably read between the lines and see that there is 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.

Can you at least put some color around 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?

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

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 '13 to ramp up CapEx if the Utica plays out and/or gas recovers in price, or ramped down more if neither of those two things happen?

Yes. 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 to -- 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 could see that becoming somewhat competitive.

All of that said, I can't imagine that we would 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 the four rigs contracted long term. The first of those four rigs -- the first expiration on the long-term contracts in those four rigs is July of 2014. Obviously we can -- if we really felt the need to, we could reduce activity and hold onto that rig; the contract is not 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 maintain our 20% royalty interest on our fee acreage. So that's another lever we can pull if we find the necessity to in a lower gas price environment.

That's like a $200 million line item there.

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 -- let's just call it 50% above methane, could you talk -- even though it's a little less pressure and lower EURs out West, could you talk about the potential economic uplift there?

Yes, as I mentioned with the ethane rejection mode, we get $0.80 to $0.90 an Mcf 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.

Am I remembering correct that system-wide 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?

Well, the further west you go, the more liquids you have. It's fairly simple; the BTU content is higher the further west you go. The Marcellus is less mature, and therefore, in a -- more of an oil window, and less of a gas window. I'm not sure that I have a specific ethane percentage for you without talking about specific locations.

Understood. I appreciate all the color. Thank you.

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 potential timing?

Yes, 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've put out -- this would be kind of just west of that location. So it's kind of Western Elk County and into Forest County. 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 well locations that would fall into that window. What was the other part that you asked?

Just 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?

All I said was we are looking at this as a possibility for 2013 and 2014. And I would say potentially as early as -- fairly early in fiscal '13, potentially. It's something we are still evaluating it.

150 million a day kind of facility, or has size (multiple speakers)

That's part of what we are evaluating, Carl. 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.

Fair enough. And maybe just one other kind of tweaking question from the regulatory side on the pipelines with Line N and Tioga. We've got the $24 million of revenues sort of being allocated to fiscal 2012; is that something where as we've got Line N now almost fully ramped but Tioga we are 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?

Well, it will come in -- well, all across the three quarters, Carl.

Okay. Great. Thanks, guys.

Timm Schneider, Citigroup.

How's it going? 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 the pipeline constraints, and what contracts you have in place over a longer term firm.

Yes. 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 $0.30 below Dominion South Point.

And then meanwhile Dominion South Point is now trading about flat to NYMEX whereas it had been at a premium. Did that answer -- oh you want to know how much we have contracted.

Yes.

We have firm sales on TGP 300. I think April we are up to about 130 million a day.

That's right.

Yes.

Okay, got it. Thank you.

John Abbott, Pritchard Capital Partners.

Hey, thank you for taking my call there. Just -- maybe I missed it here, but these well pads that you're going to be bringing on, how many wells are on each of these pads? And then second, what are your latest thoughts about DOGGR in California, the new administration?

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 Tract 100, it's a four-well pad that we are bringing on.

I'm not sure that I have any comments on the second question in California.

All right.

Mark Barnett, Morningstar.

Good morning. So you mentioned that the West to East pipe was going to be a little bit delayed and potentially done in the series of smaller projects. I think you'd 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 would see there or is it too early?

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 it's just too hard to pinpoint at this point.

Yes, and I think the important thing to recognize is that we won't build that pipe or sections of that pipe without having it contracted for. So we just don't do it on speculation, so we would have to have signed contracts before we start putting that in.

Okay. I guess just regarding any of the smaller planned 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 --

No, no. Northern access is full go. We've got the Line N Extension. We are 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 at the further Tioga County Extension that people are ramping up their interest there -- or central Tioga County Extension. So, no, we don't see any slowdown in what we've talked about before.

Okay. And I -- just a last quick question, maybe sort of a more general question -- with gas prices where they are at, have you thought about your hedging strategy and is maybe that going to be any different this year? Or is it kind of a little -- is that not really going to change?

I think our general hedging strategy will stay the same, where we will take advantage of the contango shape of the curve and layer in 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 percentage. If you go to our IR deck, we have a graph in there that shows 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.

Great. I appreciate the detail. Thanks, guys.

Timm Schneider, Citigroup.

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 in the liquids, did you say that you think all of the 90,000 acres are prospective for liquids or is that just the location of where you'll have to cryo plant, potentially?

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. You can kind of move in a long trend to that same area at Owl's Nest, and we've got quite a bit of acreage that falls into that window.

All right. So if 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?

Right.

Okay, got it. Thank you.

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

Thank you, Fab. We would like to thank everyone for taking the time to be with us today. A replay of this call will be available at approximately 2 PM Eastern time on both our website and by telephone and will 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 56217287. This concludes our conference call for today. Thank you and good bye.

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