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National Fuel Gas Co. (NYSE:NFG)

F2Q12 Earnings Call

May 3, 2012 11:00 am ET

Executives

Tim Silverstein - Director, IR

Dave Smith - Chairman & CEO

David Bauer - Treasurer and Principal Financial Officer

Ron Tanski - President & COO

Matt Cabell - President, Seneca Resources

Analysts

Andrea Sharkey - Gabelli & Company

Holly Stewart - Howard Weil

Tim Schneider - Citigroup

Craig Shere - Tuohy Brothers

Kevin Smith - Raymond James

Operator

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

At this time, all participants are in a listen-only mode. Later, we will facilitate 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. Tim Silverstein, Director of Investor Relations. And you have the floor, Mr. Silverstein.

Tim Silverstein

Thank you, Jeff 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. As you read in last night's release, National Fuel's earnings for second quarter were $0.81 per share. Excluding the $0.08 per share charge related to the new Marcellus impact fee on Pennsylvania most of which relates to Marcellus wells drilled in prior quarters, operating results for the quarter were $0.89 per share, which is $0.11 less than last year's second quarter. This drop was largely due to three factors.

First; the winter of 2011 and 2012 was unseasonably warm. In fact it was the warmest on record on our service territories. The mild weather impact the earnings by $0.05 per share in the Pennsylvania service territory of our utility and was the significant contributor to the $0.03 per share drop in earnings at National Fuel Resources, our non-regulated energy market subsidiary.

Second; and as you all know, natural gas prices continue to decline throughout the second quarter. While our hedging program did help, our actually realized natural gas price still decreased by $0.68 per Mcf quarter over quarter. That decrease in the sale of our offshore Gulf of Mexico properties last April which is the third factor was the largest contributor to the $0.05 per share drop in operating results at Seneca.

Of the three, only the sale of the Gulf, which incidentally we believe was the right decision, was within our control. Since we can't control gas prices much less the weather, we focused on managing our businesses and put particular emphasis on controlling our budgets. We also continue to execute on our plans to grow our Midstream assets all with a view to maintaining our strong balance sheet in creating long-term shareholder value.

In the Pipeline and Storage segment, our ongoing expansion efforts are progressing according to plan. Construction has actually commenced on the Northern Access and Line N 2012 projects with both projects still scheduled to be in service by November 1, 2012. When these projects ramp up to their fully contracted volumes, they will add just about $20 million in annual revenues. At our National Fuel Midstream subsidiary, construction of our Trout Run project was completed last week and will go into service when Seneca's Tract 100 wells are connected which should be in the next few weeks and Matt will address that in his remarks.

In the E&P segment, excluding the impact of last year's sale of our offshore Gulf of Mexico properties, Seneca's consolidated production grew by 18%. In the East, Seneca's natural gas production increased by 2.4 BCF or 22%. So that's an impressive rate of increase, it actually understates what could have been produced.

As we announced at the end of March, low spot natural gas prices from the Tennessee 300 line led us to curtail an average at 15 million a day of production into the Covington Gathering System for most of the month. That impacts the production for the quarter by more than 4/10ths of the BCF.

Looking forward to the third quarter, we expect the significant jump in production, when we bring on our first four wells at Tract 100. That production will be delivered by our Trout Run System into the Transco System to the south where pricing in stronger. In addition should gas prices rise, we have the ability to immediately resume full production in the Tennessee 300 line.

In California, crude oil production was up 11.5% from their prior year, largely due to our drilling programs at South Midway-Sunset, which as you know we acquired from Ivanhoe in 2009 and [SSP]. Our California folks continue to do a great job and at these oil prices we'll look to be as aggressive as we can with our development program in Pennsylvania and California.

Looking to fiscal 2013. With the decline in natural gas prices, we expect to allocate less capital to the development of our Marcellus acreage. As you read in last night's release, we plan to move to a three rig program by this summer. At current gas prices, the returns don't justify our aggressive development program. At least not as aggressive as we'd previously outlined.

Fortunately, we're on no pressure to drill our acreage as most of our natural gas rates are held in fee and most of our non-fee acreage is held either by production or has a number of years remaining on its lease term. Given these and a variety of other factors, we think the best answer for our shareholders is to pull back on our Appalachian drilling program and focus on three areas.

First is the Utica. Given the depth and the pressure of the Utica and given the size of our acreage position, we're optimistic that we will get significant opportunity. Well assessing its potential is a top priority. Evaluating our Marcellus wet gas potential is another important initiative, should the prices lift from liquids (inaudible), the Owls Nest area could be an attractive area to pursue, particularly if gas prices improved.

We expect one rig will be dedicated to these delineation efforts. In the eastern development area two rigs will be devoted to a scaledown development program at Tracks 100 and 595. Wells on this acreage currently generate our highest returns in Appalachia. Overall, even with this reduced three rig program, we still expect Appalachian production to grow by 25% in fiscal 2013.

Moving from a four to a three rig program will have little effect on our 2012 capital budget, but the impact on fiscal 2013 is more substantial about $75 million. Our new E&P capital budget for fiscal 2013 is $450 million to $550 million, which is roughly half the amount we set forth at our Analyst Day meeting last September when we anticipated a very robust 6.5 rig drilling program. Some of the reduction in CapEx was simply a function of lower cash from operations caused by the drop in gas prices and a desire to maintain our strong balance sheet, some of the present capital that we plan to redeploy to Midstream opportunities. That is both our FERC-regulated pipeline and storage projects and the non-regulated gathering projects of our NFG Midstream subsidiary.

Since its formation in 2008, Midstream’s primary mission has been to deal the gathering infrastructure needed to get Seneca’s production to market. Despite that limited object, it has been quite successful as evidenced by the Covington and Trout Run systems.

Along the way we've had discussions with numerous third-party producers who are interested in having Covington and Trout Run expanded for their use or in having NFG Midstream build their infrastructure. While we were certainly open to the idea and a higher gas price environment, capital allocation was the issue. The returns on third party gathering projects really could not compete with the returns from our drilling program.

In today's gas price environment, the returns on Midstream projects are much more competitive with our E&P returns and we think that it makes sense to allocate additional capital for projects with unrelated producers, particularly given Seneca’s more modest program. Given our relationships with most of the major producers in Appalachia, all of whom have worked with one of National Fuel subsidiary companies, given our existing assets, particularly Trout Run and Covington, both of which can be expanded to other producers and given our over 100 years of experience in putting pipe under ground, we believe we are well positioned to take advantage of opportunities with other producers, in addition to Seneca in the unregulated Midstream space.

In addition, we will also continue our ongoing project development efforts in our FERC regulated businesses. Over the past several quarters, Ron and I have reviewed a long list of projects that are currently on the drawing board and Ron will update you on some of those later in the call. Needless to say, as we always have, we will aggressively pursue those initiatives in seek out new opportunities. Our FERC regulated system is located in the heart of the Marcellus and the Utica and I am confident our development team will continue to conceive many new additional projects in the years to come.

In closing, the natural gas pricing environment will present challenges, particularly for independent natural gas producers. It will present challenges for National Fuel as well. But relative to most we’re well positioned. Our balance sheet is strong and our regulated business provides a stable piece of earnings and cash flows without regard to commodity prices. Our Midstream businesses should continue to grow and we have great oil assets which generate significant cash flow.

We have diverse business mix and importantly an expertise in our employee base that allows us the flexibility to redeploy capital as we see that to the best opportunities.

With that I thank you for your attention and I will turn the call over to Ron.

Ron Tanski

Thank you Dave and good morning everyone. As a result of the warmer weather, we expected and saw a decrease in our year-over-year throughput in our utility segment and in the legacy contracts and our pipeline and storage segment. Simply stated, because of the space heating needs were lower in our all utility service territory and in the service territories above the utilities that ships gas to our interstate pipeline system, related throughput was lower.

Offsetting those decreases from our traditional utility customers, we saw an increase in throughput from shippers, moving gas out of the Marcellus production areas through our system and off the East Coast and New England markets. In addition, because of the lower price of natural gas, besides gas-fired electric co-generation plant near (inaudible) was running quite a bit during the quarter and we saw increased throughput in our Empire pipeline as a result.

When the producers get all their gathering lines tied into the Tioga County extension, we should see a very slight increase in throughput on the Empire pipeline system and will only be slight because the producers have temporarily released our capacity to replacement shippers who actually use the capacity during the quarter. With respect to field operations, the mild winter weather allowed our construction and maintenance crews to work pretty steadily on all of our maintenance and system upgrade products and we are right on target with our capital spending for our ongoing pipeline integrity field board.

We are also moving along with our spending on a couple of near-term, new infrastructure projects. Supply Corporation, we begun construction of a compressor station for our Northern Access project and we expect to have all the metering changes and other bits and pieces of that project complete this November so that we can provide service as originally scheduled.

Our Line N 2012 project, which is the second expansion of this legacy pipeline, there is more compression being added along with some pipeline upgrades that increase capacity on that line by an additional 164000 Dth per day. We also expect to have this new compression capacity operational in the fall.

And our unregulated Midstream gathering operations, as Dave said were exiting the place for Trout System in operation to coincide with Seneca’s completion for its initial well paid on Tract 100 Lycoming County later this month. Remember that the Trout Run pipeline will deliver Seneca’s production from Tract 100 to Transco and has a design capacity of 466 million cubic feet a day. Currently, realized pricing on the Transco system is about $0.30 per Mcf higher than on the Tennessee system for term deals and $0.15 to $0.17 higher per spot deals. On the regulatory front, I am pleased to report that Supply Corporation has reached a settlement in principles with the parties in its rate case that it filed last October. We put the new settled rates into effect on May 1st on a temporary basis until the settlement is finalized there is still a lot of work to be done in putting a complete settlement agreement together and it could take four, five months to reach final agreement and have that agreement approved by the Federal Energy Regulatory Commission.

Before we turn the call over to Matt for an update on Seneca’s operation, I will point out that Seneca as part of the Appalachian Shale recommended Practices Group recently published a list of operations standards for drilling in Appalachia that were developed by the group to address safety and certain environmental and health concerns, the development of oil and Gas properties in Appalachia.

National Fuel and all its operating subsidiaries believe that the responsible development of domestic clean burning natural gas can be an economic benefit to the communities where the development is occurring and to the energy security of the nation. Seneca is pleased to be a part of the group in the forefront of that responsible development.

Now I will turn over the call to Matt to update us on Seneca.

Matt Cabell

Thanks Ron. Good morning everyone. East division production was 13.3 Bcfe, up 22% while West production was 5.1 Bcfe, up 9%. Overall production was 18.4 Bcfe, up only slightly due to sale of Gulf of Mexico assets last year.

Focusing on California first, we are continuing to grow production with significant increases at both South Midway-Sunset and at Sespe. We plan to drill a total of 23 new wells at South Midway-Sunset this year. Recent drilling has extended the size of the two primary envelopes and reservoirs and allowed us to increase production from about 700 barrels of oil per day last year to 1050 barrels of oil per day now.

At Sespe four wells were drilled in fiscal 2011 that are producing at a combined rate of about 300 BOE per day. We have six wells planned for this year including two more five acre infield wells, two cold water formation wells and two wells on our new Oak Flat lease.

Also in California, our non-operated Monterey well at the Belridge field is producing about 50 barrels of oil per day. Three to four delineation wells are planned there including at least one horizontal. But we only have a 12.5% interest if the delineation drilling is successful there could be hundreds of additional locations.

In Pennsylvania, we continue to develop our Eastern Marcellus acreage in Tioga and Lycoming Counties. Our combined Covington and Tract 595 wells in Tioga County are capable of about 140 million cubic feet per day. But we are currently curtailing production to about 130 million cubic feet per day for which we have firm sales contracts.

In Lycoming County, the Tract Run gathering system is fully installed and our first four well pad has been fracked. We are currently drilling out plugs and running production tubing and expect to initiate production before the end of the month. We are a few weeks behind schedule due to a delay in getting a 10,000 psi snubbing unit that could handle these higher pressure wells. Once this pad is on line, we expect overall Marcellus net production to be over 108 million cubic feet per day.

We completed our third well at Boone Mountain in the second quarter. It came on at 4.6 million cubic feet per day. We have derisked this portion of our acreage and will begin development when gas prices improve.

Later this summer, we will be drilling three Marcellus white gas test to determine Btu content and potential EURs in Western Elk County. This data will help in designing the cryogenic processing facility and in determining minimum gas pricing needed for this development project.

We are also closely watching NGL pricing. We do expect some downward pressure on C3 plus and will consider this prior to a go add decision on a processing plant.

In the EOG joint venture, the two most recent wells came on at rates of 3.5 million and 4.5 million cubic feet per day. We are encouraged to see higher initial rates as compared to last fall’s disappointing IPs. However, we will be evaluating the economics of the EOG wells and considering non-participation until prices improve.

As I have mentioned before, even if we do not participate, we will return a 20% royalty interest on JV wells drilled on our fee acreage.

In the Utica, we are drilling our second horizontal well. Our first Utica horizontal at Mt. Jewett will be fracked in July. Our latest production guidance is 81 Bcfe to 90 Bcfe in fiscal 2012 and 100 Bcfe to 115 Bcfe for fiscal 2013.

Capital expenditures are expected to be $610 million to $690 million in fiscal year ’12 and $450 million to $550 million in fiscal year ’13. This assumes that we continue to curtail some production through the summer and it also assumes we drop another Seneca operated rig this summer; leaving only three Seneca operated rigs for fiscal year ‘13. We’re also assuming that we will not participate in some portion of the EOG joint venture program in fiscal year ‘13.

Note that we’ve cut our spending considerably; expect to reduce it further in fiscal ‘13 and at the midpoint of our guidance, we still expect production growth of 25% both this year and next year.

On the cost side, we’re currently in the process of negotiating to lower our pumping charges and sand acquisition cost. We have succeeded in gaining substantial reductions to our (inaudible) cost and continue to move forward with the purchase of some items, such as frac tanks and rig mats that we once leaved.

We have slowed our hiring substantially and are currently at a headcount of about 40 less than what we had budgeted. As production grows this quarter, we will see substantial drop in our G&A per Mcfe, such that 2012 will be lower than 2011.

In conclusion, we have responded to the current commodity price environment by expanding in California and reducing our spending in Pennsylvania. California production is up and we expect to increase our spending there in fiscal 2013.

Our Marcellus program has great momentum even as we tamper our activity there, production will continue to grow. When gas prices improve, we will be well positioned for further growth.

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

David Bauer

Thank you, Matt and good morning everyone. Overall, our operating results for the quarter were lower than last year had a number of bright spots.

In the utility, if you put aside the effect of unseasonably warm winter, earnings in that segment were actually ahead of forecast due to lower than anticipated O&M expenses.

In the pipeline and storage segment, this was the first quarter to reflect the full year impact of the Tioga extension and Line N expansion projects to replace and service last fall. For the quarter, the two projects added $7.8 million in revenues.

At Seneca, operating results fell short of our previous projections mostly because of lower natural gas prices, but production growth and strong oil prices led to improved results from our California properties which mitigated some of this impact.

All of the specific drivers of the quarter’s results are covered in last night’s release, so I won't repeat them all here. However, I would like to expand on Seneca’s per unit operating expenses for the quarter which were a little higher than we anticipated, but which we expect to trend downward over the remainder of the fiscal year.

On a sequential basis, Seneca’s $1.14 per Mcfe LOE expense for the quarter was higher than the $1.02 rate for the quarter ended December 31, 2011. Most of that increase is attributable to higher LOE on our non-operate joint venture wells including an out of period adjustment from EOG that by itself increased our LOE rate for the quarter by $0.04 per Mcfe. We've updated our forecast and expect our LOE rate for the last six months of the year will be in the range of $0.95 to $1.10.

Seneca’s DD&A rate for the quarter was $2.30, up $0.03 per Mcfe for the quarter ended December 31st. Much of this increase is due to the timing of our reserve additions relative to our capital spending. As our wells on track 100 come online, we expect meaningful reserve additions in the upcoming quarters which should cause our DD&A rate to come down. Thus, we’re still comfortable with our $2.20 to $2.30 per Mcfe guidance for DD&A expense.

G&A expense is on pace to be within our guidance of $54 to $58 million for the fiscal year. As Matt said earlier, we expect a significant jump in production in the third and fourth quarter which should cause the per unit rate to come down. As we said in last night's release property franchise and other taxes increased due to a $9.8 million accrual for the Marcellus Shale impact fee. $5.9 million of that accrual is related to prior fiscal years. Going forward assuming a three rig program and current gas prices, our impact fee accrual should be approximately $2 million per quarter for the last six months of fiscal 2012.

Assuming current gas prices and our three rig program we expect to impact fee will trend upward in 2013 and average about $2.5 million per quarter. However changes in gas prices and the timing of when we spud our wells could impact the ultimate amount we incur.

Turning to earnings guidance, we are lowering our GAAP earnings expectations for fiscal 2012 to a range of $2.30 to $2.45 per share. Our previous guidance was $2.40 to $2.65 per share. The change in our guidance is mostly attributable to the Marcellus impact fee and a further reduction in our NYMEX natural gas pricing assumption which is now 225 per MMBtu for the remaining 6 months of the year.

On a positive note we are seeing higher than expected firm transportation revenues and Pipeline and Storage segment and lower than expected O&M expense across both regulated segments. We expect those trends to continue into second half of the fiscal year which should add a few cents to earnings and this has been reflected in our new range. Our earnings guidance also reflects the terms of the settlement of Supply Corporation's rate case, but that settlement should not have a material effect on this year's results.

In terms of our capital budget, our spend plans for 2012 are unchanged from the $900 million to $1.045 billion range we included in our most recent IR slide deck. With respect to 2013, as Dave said earlier, we've lowered Seneca's spending forecast by $75 million to reflect the new three rig program. The forecast for the other segments have not changed.

A recap of 2013's spending by segment is as follows; $55 million to $60 million in the utility; $30 million to $50 million in pipeline and storage; $450 million to $550 million in E&P; and $75 million to $125 million in Midstream and all other. Our consolidated financing needs for fiscal 2012 are essentially unchanged. Seneca’s operating cash flows are expected to be a bit lower at our new $2.25 natural gas price assumption but that will be offset by a lower cash needed utility for purchases of store gas inventory.

At March 31, we had a $172 million of net cash on our balance sheet. Over the next six months, we will incur significant expenditures at Seneca for its drilling program at Supply Corporation for the construction of the Northern Access and Line N 2012 projects and at the utility for the purchase of gas inventory.

As a result by fiscal year end, I expect we will be in net short-term borrowing position of around $50 million. Before closing I would like to highlight a change we've made to our hedging program. As you saw on last night’s release we added a modest player of natural gas hedges that extend through fiscal 2017. This is a bit of a shift from our historical hedging strategy which generally had gone out only two years beyond the current fiscal year.

Given the slope with the NYMEX Futures curve, we intend to establish a meaningful long-term hedge position to lock in the economics of our drilling program. We started layering in these positions this past week and we’re expecting them to build in the quarters to come.

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

Question-and-Answer Session

Operator

Thank you (Operator Instructions). Our first question comes from the line of Andrea Sharkey - Gabelli & Company. Please proceed.

Andrea Sharkey - Gabelli & Company

I was wondering if you could us some more guidance towards 2013 on California, you guys have done a great job increasing that oil production. I think it's up about 10% so far at the first half of this year. You seem to be ramping up more drilling. Can we expect a similar type of growth rate, you know 2013 and beyond or is there a level where you sort of tap out on the California area?

David Bauer

You know we haven’t given any guidance yet for specific by division for fiscal 2013, but we will spending a bit more in 2013 in California than we did this year in 2012. So I think we would anticipate some growth in production between and 2012 and 2013 but I don’t think we are really prepared to quantify that yet, Andrea.

Andrea Sharkey - Gabelli & Company

Okay, that’s fair enough. And then I guess the next question would be I think you guys have about $250 million in debt that's maturing in 2013 and you might be a little bit have a short follow on your capital spending this year. So I guess how do you plan to address that, will that just be new debt equity, what are you thinking there and then also looking at 2013, do you plan to sort of stay within cash flow there?

David Bauer

In terms of the 250 million, at this point I think we plan on refinancing that with another long-term debt issuance. I wouldn't see us needing to issue equity that's not in the plans. And then in terms of fiscal 2013 spending versus cash flows, we haven't initiated guidance yet. But I think it's safe to say that we will be much, much closer to living within cash flows.

Andrea Sharkey - Gabelli & Company

And then just last question for me and I will give somebody else the chance. You guys have significant hidden value in all of your assets and there's a lot of options out there for you to service that value. For example we've talked about before monetizing the pipeline by maybe an MLP structure, I guess where are you guys on evaluating any of that potential financial engineering options?

David Smith

I think at this point Andrea we are fairly comfortable with where we are. Certainly as we move forward and look to devote more capital to the Pipeline and Storage segment, in the Midstream segment and we have a higher tax basis assets there, we would be looking much more toward an MLP at that point. I think right now we have some room to lever up a little bit, a couple of 100 more million dollars and certainly that's very active in our thoughts and considerations as we move forward.

Operator

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

Holly Stewart - Howard Weil

I guess just a couple of follow-ups, remind us Matt on the limitations in California because I think obviously as you look out to the macro environment right now. People think great cash flows in California so why wouldn't you be going faster so can you just remind us of the limitations out there?

Ron Tanski

Well, let’s think about our two biggest growth areas which would be South Midway Sunset and Sespe. At South Midway Sunset, we’re extending reservoirs as we drill those wells. Really if you try to get it heavier yourself you might out drill the limit of the reservoirs.

So you need to -- each well is depended on the previous one and at Sespe, the primary source area at Sespe is the five acre in field program. We really want to get some production history before we determine how aggressive we want to get on that program. We’ve got a little bit of production history from the 2011 drilling.

We will get some production some further history from those wells plus some from our 2012 drilling that we may be able to accelerate it a little in fiscal ‘14. But there is some limit even if we felt like it was something we want to get more aggressive on there are some limitations too how much we drill at Sespe. We have a limited drilling window. It’s a fairly environmentally sensitive area. So there would still be some other space on that.

Holly Stewart - Howard Weil

And two rigs running right now?

Ron Tanski

In California? No, one rig in California right now.

Holly Stewart - Howard Weil

One rig, okay. And then kind of I switch to the Marcellus, talk about the decision to drop the rig, I guess more specifically was there a financial impact of that decision? Under rig contracts and services?

Ron Tanski

We fully expect that we will be able to have that rig placed in another basin and that our cost will be minimal. We do have an obligation on the rig that would be on the order of $6.5 million a year or a non-placed.

Holly Stewart - Howard Weil

Another basin?

Ron Tanski

Yeah, not for us.

Holly Stewart - Howard Weil

And then just a remainder on I think, Dave said now looking for a 25% growth rate in 2013 in the Marcellus. What was the previous announced growth rate there?

David Bauer

Yeah, with 35% to 40%, I think previously.

Operator

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

Unidentified Analyst

It’s actually [Denivo]. There was mention of the Niagara capacity turn backs in the pipelines and those turn backs offsetting revenues from the expansion projects. I am just curious if this is something incremental to what we've sort of been talking about already.

Dave Smith

[Denivo] You are kind of breaking up there, do you repeat that?

Unidentified Analyst

Yes there was a mention of Niagara capacity turn backs. I am just curious if this was something that was incremental to what we have already been talking about.

Dave Smith

No, I mean those were kind of all planned and as we move forward by the end of this year when we get the Northern Access project in place that's all pretty much going to be offset by gas flows going the other way.

Unidentified Analyst

And finally on the utility, can you please tell us what the pretax dollar impacts from that was for the quarter?

Ron Tanski

I'm pretty sure it was $0.05.

Unidentified Analyst

Okay.

Ron Tanski

It’s in the back of press release.

Unidentified Analyst

The $0.05 is after-tax, right?

Ron Tanski

I am sorry that's after tax. I don't have that number here.

Unidentified Analyst

(Inaudible) pretax number.

Ron Tanski

I’ll get you back on you on that.

Operator

Our next question comes from the line of Tim Schneider with Citigroup. Please proceed.

Tim Schneider - Citigroup

First question how many more wells are you guys planning to drill at Owl’s Nest this year.

Dave Smith

Let's say we've got two more Owl’s Nest wells planned in the coming months. They won't necessarily fall in this fiscal year. If I had to guess I would say one would be this fiscal year, one would be next fiscal year just because the rig will be there at the time that overlaps the end of our fiscal.

Tim Schneider - Citigroup

And if possible can we get an update on the Henderson well, are you guys still doing the data on that.

Dave Smith

We are still keeping that one tight for now.

Tim Schneider - Citigroup

Okay, with respect to the down spacing at Sespe, what could the incremental locations be there if it’s in fact towards?

Dave Smith

I am going to put a range on it and say 20 to 50.

Operator

Our next question comes from the line of Chris (inaudible) with UBS. Please proceed.

Unidentified Analyst

Just a quick question, Matt when you were talking about curtailments in the east due to takeaway and limitations, do you think, I mean I guess remind me how long will that be in place, how long are you going to be curtailed there?

Matt Cabell

Well, that's a function of pricing, so if we've got to the point where our spot pricing at TGP 300 was in excess of $2.30, we would probably stop curtailing there.

Unidentified Analyst

Okay that's just discounting to get in to outline essentially?

Matt Cabell

Yes.

Unidentified Analyst

Okay, and then Dave switching gears a little bit, when you spoke about the impact of the impact fee, 2 million I think, it was what you said and at the back two quarters in the year. Is that, might think about in addition to what we sort of saw in the run rate in 1Q? So, I mean you guys had sort of tax line if you will in AMP of like 2.5 million in the first quarter. So I might think about the third quarter as being somewhere around 4.5 and incremental to what you had.

Dave Bauer

Well, we have some franchisee and of Lawrence Gas in California. It would be in addition to the impact fee.

Unidentified Analyst

Right. So you were talking only about the impact.

Dave Bauer

Right. So that 2 million, if you were to go back to last years third quarter, that’s what you are trying to do. That 2 million would be incremental to whatever that previous rate in that.

Unidentified Analyst

Okay. Got it. And then I appreciate the color on your hedging strategy change. I saw incidentally it wasn’t employed on the oil side. Obviously, we have backward day curve there. So is this more of and if I thought about your hedging profile in the past or hedging behave in the past, it was around cash flow protection and making sure you guys could forecast the quarter. Now it looks to me more of a, I don’t want to say commodity that but it maybe your viewpoint that you know that can (inaudible) on the natural gas curves, make it such that you guys can make attractive returns. So you just opt to lock it in. Is that the way I think about what you are doing there?

Dave Bauer

Yeah, I think that’s right. Where if you look at the upward slope, we would hedge it on an average price of around $4 Mcf. We can lock in a pretty good return at that level, given the downside on commodity prices. Thought that was the right thing to do.

Unidentified Analyst

Now there has been some questions right I think of that, the out years of the curve, how liquid is, and why not you guys are starting small, can you talk about adding a little bit on as time sort of progress, but any issue with regard to that as you’ve seen it?

Dave Smith

Yeah, we’ve heard the same things from our counterparties where at times the big producers may have been doing some good size trade that’s upped the liquidity. But we are patient unlike the levels that we’ve got.

Operator

Our next question comes from the line of Craig Shere with Tuohy Brothers. Please proceed.

Craig Shere - Tuohy Brothers

May I a couple quick questions on the EOG JV participation; I thought that was running maybe a 150 a year, is that right and do you have a rough portion of that that you might choose not to participate for fiscal ‘13 and would any of that effect the second half of this year?

Dave Smith

It’s important to understand when you think about the our participation in a well that’s spud today that a whole lot of a cost, let me rephrase that. If you look at 2013 a lot of whole what we’ll spend on the EOG program, is completion of wells that are already drilled or they are being drilled as we speak. So even if we non-participated in very time the impact to 2013 is probably only in order of about $50 million.

Craig Shere - Tuohy Brothers

I got you.

Dave Smith

Now, if we continue to non-participate, it would have a, you are probably right probably gets to be more like $150 million overtime.

Craig Shere - Tuohy Brothers

And then on the Sespe questions; you are talking about the down spacing, but didn’t you have a deeper delineation well you are working that’s kind of separate from that?

Dave Smith

Yes.

Craig Shere - Tuohy Brothers

And what’s the progress of that.

Dave Smith

We haven’t drilled yet.

Craig Shere - Tuohy Brothers

When will that be done?

Dave Smith

It will be in fiscal ’13.

Craig Shere - Tuohy Brothers

Okay, any idea how…

Dave Smith

It will be in fiscal ’12.

Craig Shere - Tuohy Brothers

So you’ll have results report by the year end for the fiscal year?

Dave Smith

I wouldn’t count on having production results in ’12, no; probably more likely be ’13 by the time we’ve completed it.

Craig Shere - Tuohy Brothers

And Dave, you are talking about at the lower commodities drop about – the competitiveness of Midstream expansion, serving third party producers versus CapEx to E&P; that makes a lot of sense, but could you put some additional color maybe around just how much the Midstream could grow overtime?

Dave Smith

I think in large part, we have a number of projects that now on the drawing board let’s say over the next three years we have probably about $400 million right now. Now the likelihood is that won’t all happen and many of those coming from our actual Midstream subsidiary, the unregulated side are devoted to Seneca.

But I could see a scenario working with other producers particularly expanding Trout Run, expanding Covington and working with other producers, I could spending an incremental $200 million there lets say over the next two or three years. But there is a lot of moving parts to it; so it will depend on how many of those projects for example we presently on the joint board we do a little spend on our ability to work those relationships that I talked about, but certainly, we think those are very, very good projects and a great opportunity for us to grow.

Craig Shere - Tuohy Brothers

If I may dovetailed out with the question about the MLP status, do you think if we fast forward say 24 months and you've got an extra couple of $100 million of midstream CapEx well on its way that you are getting close to the point of critical mass to think about improving your cost of capital and some of the parts multiple with an MLP?

Dave Smith

Yeah, absolutely.

Operator

Our next question comes from the line of Kevin Smith with Raymond James. Please proceed.

Kevin Smith - Raymond James

Just I have one and maybe two, first are you going to be able to produce everything on a Tract 100 at capacity, where do you stand I guess with firm capacity out of there?

Dave Smith

We have about 30 million a day of firm sales, now close to 50 million in November. I would say there is a pretty big, pretty high likelihood that we will be above that from sales level. So spot market is okay there right now and the reason why we can't produce above our firm sales, I mean also we are looking at potentially locking in additional.

Kevin Smith - Raymond James

Sorry I think I lost you, you said you are looking at an additional firm capacity?

Dave Smith

Yeah, I wouldn’t think of it as a firm capacity, more as firm sales, but yes we are looking at additional firm sales.

Kevin Smith - Raymond James

And then lastly, when do you think you are going to be able to talk about Utica well results and what that play mean for you, do you guys have a targeted year from now or six months from now or what's your timetable on thinking on that?

Dave Smith

Maybe a way to look at it Kevin as we’ll have to wells drilled and fracked by the end of this fiscal year and we may have some test results from sometime in the fall. So I would say, if what you are trying to think about is when are we going to be talking about how significant this potential is to us and what does it mean for our capital spending going forward at target sometime in the fall.

Kevin Smith - Raymond James

Is anybody else drilling – do have any competitors are drilling around that acreage?

Dave Smith

We only permitted wells around that acreage.

Operator

Ladies and gentlemen that concludes the Q&A portion of our call. I would now like to turn the presentation over to Mr. Tim Silverstein for closing remarks.

Tim Silverstein

Thank you, Jeff. 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 we’ll run through the close of business on Friday, May 11, 2012.

To access the replay online visit our Investor Relations website at investor.nationalfuelgas.com and to access by telephone call 1888-286-8010 and enter pass code 11631131. This concludes our conference call for today. Thank you and good bye.

Operator

Ladies and gentlemen that concludes the call. Thank you for participation. You may now disconnect. Have a wonderful day.

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