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Executives

Timothy J. Silverstein – Investor Relations

David F. Smith – Chairman and Chief Executive Officer

Matthew D. Cabell - Senior Vice President

David P. Bauer - Treasurer and Principal Financial Officer

Analysts

Andrea Sharkey – Gabelli & Company

Kevin A. Smith – Raymond James & Associates, Inc.

Mark Rogers – Soroban Capital Partners LLC

Timm Schneider – Citigroup Global Markets

Mark Barnett – Morningstar Inc.

Becca Followill – U.S. Capital Advisors LLC

Carl Kirst – BMO Capital Markets

National Fuel Gas Company. (NFG) Q3 2012 Earnings Call August 3, 2012 11:00 AM ET

Operator

Good day, ladies and gentlemen, and welcome to the third 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.

Timothy J. 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.

David F. Smith

Thank you, Tim, and good morning to everyone. Last night National Fuel reported third earnings of $0.52 per share. Continuing the trend from the first half of the fiscal year, lower realized natural gas prices had a significant impact on our consolidated results. Quarter-over-quarter Seneca’s Natural Gas prices after hedging were $1.55 per Mcf lower, which reduced E&P earnings by about $0.20 per share.

Despite a drop of 28%, and realized natural gas prices. Consolidated earnings overall were down only 7% or $0.04 per share. Thanks in large part to our diversified business model and our continued focus on long-term growth particularly in our midstream businesses.

There were multiple bright spots across all of our major business segments. At Seneca, consolidated production was up 31%. In the Pipeline and Storage segment the Line N and Tioga County extension projects help drive a $0.10 per share increase in earnings.

The Trout Run gathering system was just recently placed in service, and while utility earnings were down slightly by $0.02 per share our employees in both of our regulated business segments did a great job and keeping an eye on spending, which help to limit the overall impact of the 17% warmer than normal winter.

Operationally, National Fuel had a great quarter, as I just mentioned Seneca‘s consolidated production of 22.1-Bcfe increased 5.2-Bcfe or 31% despite a reduction in CapEx. Most of this increase in production occurred in each division where in late May we commenced production on four very good wells on our Tract 100 acreage in Lycoming County.

Despite voluntary curtailments into the constrained and discounted Tennessee 300 Line, we achieved just a few days ago our major milestone of 200 million cubic feet per day of net production from the Marcellus Shale.

We expect production will continue to grow as we bring on additional wells like Lycoming County in the coming quarters. In California, Seneca’s after hedging crude oil prices increased by more than 6%, while production increased by about 7.5% over the prior year. Our California team has done a terrific job of extracting value from those assets. To put the reference into perspective, oil production from Seneca’s California acreage is now at its highest level since 2003. At today prices, these properties continue to generate significant cash flow nearly $175 million of EBITDA for the first nine months of the fiscal year.

Looking ahead to the next year, our Seneca operated program will be largely unchanged from what we presented on our last call. Seneca’s three rig program in Appalachia will focus primarily on a scale down development plan at Tracts 100 and 595, and on Utica & Marcellus delineation efforts in our western development area. Even with this reduced program and considering lower than anticipated production from the joint venture with EOG. We expect Appalachian production will increase by nearly 30% in fiscal 2013.

We think this is the right measured rate at which to grow in the current price environment. Should gas prices further improve, we’ll consider increasing the pace of Seneca’s program. In the meantime, as most of you know, we’re under no pressure to drill up our acreage, most of our natural gas rates are held in fee and the vast majority of our non-fee acreage is either held by production or has several years remaining on its lease term.

With respect to our EOG joint venture, as we announced last month, we expect the significant slowdown in activity. Though disappointment EOG’s decision was not unexpected given the decline in natural gas prices and given their publically stated intension deemphasize dry gas.

Overall from our perspective the JV accomplished what we hoped it would, with very little investment, we were able to ride the shale learning curve with the strong and experienced operator. Along the way, we assembled our own Marcellus team, a team that has shaped our program and will continue to lead its growth into the future. And Matt will have a full update on Seneca’s operations later on the call.

Turning to our Pipeline and Storage segment, construction is well underway on the Northern Access and Line N 2012 projects and both projects are on schedule to be in service by the end of the first quarter of fiscal 2013. These are significant projects for National Fuel that will add about $20 million in annual revenues, when they are ramped up to their fully contracted volumes. Entering Midstream, the Trout Run gathering system was placed in service at end of May. Though not a big factor in our third quarter results, as Seneca brings on additional wells in Lycoming County and is gathering volumes continue to increase. The Trout Run system will be a meaningful contributor to our consolidated earnings. We continue to be aggressive in pursuing additional opportunities to grow our Midstream businesses.

Our short-term focus is on the wet gas area of the Marcellus and the Utica. In particular, multiple reproducers have expressed series interest in a further expansion of our line N system. We’ll keep your updated as their project develops.

We also continue to pursue projects on the dry gas area of the Marcellus, such as Empire Central Tioga extension project and a National Fuel Midstream’s expansion of its Covington and Trout Run systems. These projects are largely dependent on gas prices and given the current pricing environment are likely to be longer-term in nature.

That said as gas prices recover we’re optimistic that they will ultimately be developed. Lastly, at the utility, as a result of the growth in the Marcellus and the related drop in the prices over the past year, which has provided a great benefit to our retail customers, we’re seeing renewed interest in natural gas from commercial and industrial customers in our utility service territory.

The utility is pursuing transportation agreements with several large customers primarily in Pennsylvania, and we’re starting to see results. While the immediate impact will be modest, we see this as a good sign for future increased demand in natural gas in an area where normalized throughput volumes have been declining for years.

In conclusion, National Fuel had a great quarter, particularly with regard to those matters within our control. Commodity prices have caused volatility in our E&P results, but our strong balance sheet and our stable base of earnings provide a solid foundation, a foundation that positions us for continued growth into the future.

And with that, I’ll now turn the call over to Matt.

Matthew D. Cabell

Thanks, Dave. Good morning, everyone. It was another good quarter for Seneca. East division production was up 38% and west up 6%. Focusing on California first, our fiscal 2012 drilling program has gone well with 22 new producing wells on line at South Midway Sunset, another 20 in North Midway. At Sespe we drilled six wells, including two more five-acre infill wells and two cold water tests.

We plan to frac these wells sometime this fall. We also drilled a horizontal etchegoyen well at North Lost Hills, which is producing 50 barrels of oil per day. A good rate considering this is a relatively shallow, $400,000 horizontal well. A second horizontal is planned for North Lost Hills in fiscal 2013.

Moving on to Pennsylvania, we brought on our first four well pad at Tract 100 in Lycoming County. These four wells all came on at rates in excess of $10 million a day. And have averaged estimated ultimate recoveries of about 10 Bcf with the best well and 8,100 foot lateral, expected to produce approximately 14 Bcf. We’ve just finished fracking another three well pad at Tract 100, and expect to have those wells on line in about two weeks.

Two of these wells were fracked using reduced cluster spacing, such that frac stages and clusters are more closely spaced, potentially increasing both the production rate and the recovery per foot of lateral. We will test this in a few other locations over the course of the next several months, in order to evaluate the cost benefit trade off. We’re very excited about the results we’re achieving in Lycoming County. This is a challenging area operationally, due to the rugged terrain, deep drilling depths, and high pressures.

While cost maybe a bit higher here, we are hoping that EURs of 10 plus Bcf are the norm. In Tioga County our latest six well pad on Tract 595 has had average IP rates of 7.2 million a day. These wells appear to be consistent with our EUR assumption for this area of about 7 Bcf.

Overall, Seneca’s net Marcellus production is now approximately 200 million cubic feet per day. Of that 200, approximately 44 million cubic feet per day, or 22% comes from our interest in the EOG joint venture.

Recently EOG informed us, but they are unlikely to meet their minimum drilling requirements for calendar 2012. This means the joint venture area will shrink and much of the acreage once dedicated to it, will be available to Seneca at a 100% interest.

To-date, EOG has earned a 50% interest and approximately 34,000 Seneca acres. EOG’s reduced activity will result in changes to our forecast for both production and CapEx in fiscal 2013, but will not impact fiscal 2012.

In fact, our total spending on the joint venture in fiscal 2012 will be greater than what we originally forecast. Consequentially for the year, we expect to be very close to the top end of our guidance range at $690 million.

We don’t have two rigs on Tract 100, one rig will be moving to the western development area in September to drill four delineation wells. Two in the Owls Nest wet gas area. One at Church Run also testing wet gas, and one in an area we call Ridgeway where we expect dry gas. With the recent drop in NGL prices, we see a smaller uplift for wet gas. And we may find that it makes more sense to focus on our best WDA dry gas areas that do not require a significant upfront investment for a processing plant.

However, it’s important to fully delineate our options. With essentially no expiring leasehold on our western acreage, we have the flexibility to choose our next development areas based on all of the factors that impact their economics, including EURs, well costs and relative pricing of natural gas and NGLs.

In the Utica, we plan to frac our first Utica horizontal this month and the second in September. We plan to soak both of these wells for 60 days before producing them. We believe that in these low water saturation shales, it’s important to wait for a period of time between the frac and the flow back, giving the frac fluid a chance to dissipate within the reservoir.

Therefore, we will not have results from these wells until sometime this fall. With three quarters of fiscal 2012 complete, we are expecting our annual production to be in the range of 81 to 85 Bcfe, including the impact of 2 to 3 Bcf of production curtailments due to the extremely low spot prices we’ve seen on the TGP 300 line. And another 3 to 4 Bcf related to completion delays, also in response to low spot price. Absent for low spot price and the associated curtailments and completion delays, our production forecasts would have been 85 to 90 Bcfe.

For fiscal 2013, we’re projecting production of 92 to 105 Bcfe, or about a 10% to 25% increase over fiscal 2012. Meanwhile, we will be reducing our capital spending substantially to a range of $400 million to $500 million. This assumes a three rig Seneca operated program for our east division and assumes essentially zero spending on the EOG joint venture.

Let me conclude with a few comments about the natural gas market despite yesterday’s reaction to the storage report, in our view natural gas is poised to recover the impending gas storage crisis seems to be far less likely as coal to gas switching has increased demand.

The gas directed rig count has fallen and with the fall in NGL prices growth in wet gas plays is likely to slow, such that the overall gas market will begin to reflect the true economics of shale gas plays. To me this means gas price will once again exceed $4 per Mcf. Of course we can’t predict exactly when that will happen and we can’t predict the weather.

But we feel good about the economics of our long-term program. Unfortunately with our acreage position, we have the luxury of gearing the pace of our program to market conditions.

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

David P. Bauer

Thank you, Matt and good morning everyone. As Dave said earlier considering the significant drop in natural gas prices, the third quarter was a good one for National Fuel, the earnings of the regulated segments are pretty straightforward. And last night’s release hits on all the major drivers. So I won’t repeat them. At Seneca there was some variability in per unit operating expenses that’s worth commenting on.

Seneca’s $0.91 per Mcf of LOE expense for the quarter improved from the $1.14 rate that we saw in the second quarter. Most of that decrease is attributable to the jump in Seneca operated production in the Marcellus, which carries a lower LOE burden. A reduction in LOE on our non-operated joint venture wells was also a factor.

Per unit G&A expense dropped to $0.59 per Mcf, again mostly due to the growth in Seneca's Marcellus production. DD&A increased to 237 per Mcf; we have seen an upward trend in that rate over the last few quarters, which is generally due to our delineation efforts in the Western Development Area, which tend to be expensive wells that don’t initially add much in the way of reserves and our spending in California. Also in the third quarter, we were forced to write-off a fair number of reserves associated with the EOG joint venture, which further increased our DD&A rates.

Property franchise and other taxes were $4.3 million, including a $2.6 million accrual for the PA impact fee. Going forward, assuming current gas prices and a three rig program, we expect the impact fee to average about $2.7 million per quarter. However changes in gas prices and the timing of when we spot our wells could impact that amount.

Switching to guidance, we’re increasing and tightening our fiscal 2012 earnings guidance to a range of $2.38 per share, $2.48 per share; the increase reflects our third quarter results, our updated production guidance of 81 Bcfe to 85 Bcfe, and NYMEX commodity prices of $3 for gas and $85 for oil.

You should note that there was a typo on page seven of last night’s release. The earnings guidance section refers to $100 per barrel pricing assumption for the remainder of 2012; it should be $85. The press release on our website has been updated to reflect this change; our earnings guidance is not affected.

We’re initiating preliminary fiscal 2013 earnings guidance in the range of $2.45 per share to $2.75 per share; midpoint to midpoint, $0.17 per share increase over 2012.

Let’s review the major assumptions that are reflected in our forecast; starting with E&P, as we announced last month our 2013 guidance now assumes Seneca’s production will be in the range of 92 Bcfe to 105 Bcfe. It also assumes flat NYMEX commodity pricing for our unhedged production of $3.25 for MMBtu for gas and $85 per barrel for oil.

Our flat pricing assumptions were set based on NYMEX strip prices at the time we were putting together the forecast. The today’s strip is a bit higher than our pricing assumptions, but we’ve included a sensitivity table on yesterday’s release that can be used to estimate the impact of different commodity pricing assumptions on our forecast.

From expense standpoint, we expect our per unit LOE rate will be in the range of $0.90 to $1.10 per Mcf. We see a fair amount of variability in our rate from quarter-to-quarter. So we’ve set a wider range that reflects the uncertainty of water handling cost in the east, and steaming cost in California.

G&A expense will increase in nominal dollars, but with the forecasted increase in production, we’re expecting a drop in G&A expense on a per unit basis. At the mid point of our guidance, per unit G&A in fiscal 2013 to be about $0.60 per Mcfe. This compared to the $0.70 rate for the most recent nine months.

Per unit depletion expense should be relatively consistent with our current rate. Now there are a lot of moving parts in the DD&A calculation, so that trend could change based on the timing of our reserve additions particularly at the end of the fiscal year.

Turning to the regulated businesses, you can expect the significant increase in Pipeline and Storage earnings in fiscal 2013 mostly as a result of our recent expansion projects. The Northern Access and Line N 2012 projects, which will go on service in the first quarter of fiscal 2013, will add about $20 million of revenues.

On top of that, contracted volumes on the Line N 2011 and Tioga County expansion projects will continue to ramp up in 2013 adding about $6 million to revenues and making the total impact of our recent expansion projects approximately $26 million. However, we continue to experience turn backs of capacity on the spy system, particularly at Niagara, which we forecast will reduce 2013 revenues by about $4 million to $5 million.

Assuming normal weather in Pennsylvania, utility segment earnings will most likely increase in 2013, as you saw in last night’s release warmer than normal weather in Pennsylvania reduced earnings at the Utility by $0.12 per share for the most recent nine months. Partially offsetting any increase from normal weather is an expected 3% rise in O&M expense in both jurisdictions. In spite of that increase we don't see ourselves needing to file a rate case in either jurisdiction.

With regard to capital spending, we're updating our guidance for both fiscal 2012 and 2013. Starting with 2012, we now expect consolidated spending will be in the range of 980 million to 1.035 billion. The break out by segment is as follows. $55 million to $60 million in the utility segment, $160 million to $175 million in the Pipeline and Storage segment, $675 million to $690 million in the E&P segment and $90 million to a $110 million in all other, which is largely from Midstream’s Trout Run gathering project.

For fiscal 2013, excuse me, our preliminary budget is a range of $555 million to $710 million. We’re still reviewing the proposed capital budgets of our regulated segments, but I don’t expect any significant changes. A breakout of the consolidated total this is as follows, $60 million to $70 million in the Utility segment, $45 million to $65 million in the Pipeline and Storage segment, $400 million to $500 million in the E&P segment and $50 million to $75 million for our non-regulated gathering projects at NFG Midstream. Financing needs in 2013 should be modest.

Based on our earnings and capital spending guidance, we expect from a cash from operations should equal or, depending on changes in working capital, slightly exceed our capital spending. We have $250 million of long-term debt that matures in March of 2013 and the refinancing of that debt will be our principle financing activity next year. Our balance sheet is in great shape, our equity-to-cap ratio was a little higher than 57% at June 30 and should stay in that vicinity through the end of fiscal 2013.

Lastly, with regard to our hedging program, for the reminder of fiscal 2012, our gas production is about 65% hedged in oil about 55%. For fiscal 2013, we’re hedged in the mid 50s for both gas and oil and we continue to add positions with the goal of being about 60% hedged prior to October 1.

As I mentioned on the last earnings call, we intend to establish a fairly substantial long-term hedge position, a lock in the economics of our drilling program. During the quarter we built an 18 Bcf layer through fiscal 2017 at $4.07 per Mcf. We think this is a good start, and we'll look to add new trades as market conditions warrant.

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

Question-and-Answer Session

Operator

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

Andrea Sharkey – Gabelli & Company

Hi, good morning.

Matthew D. Cabell

Good morning.

David F. Smith

Good morning, Andrea.

Andrea Sharkey – Gabelli & Company

I guess my first question would just be if, have you guys seen any issues with water sourcing in the Marcellus? I know a lot of your peers have had some issues. I would assume if that hasn’t been a big impact for you guys, but just wanted to get your thoughts on that?

Matthew D. Cabell

Andrea, this is Matt. It has not been a big issue for us, largely because we're staying ahead of it. So we've got water that we need for the fracs that are coming up. In addition, one of our primary water sourcing points in Tioga County comes from a stream that's fed by an abandoned coal mine, so it's actually a place where they, the river basin commission want us to take that water, because it actually cleans up the stream and removes some of the acid mine drain.

Andrea Sharkey – Gabelli & Company

Okay, great. And then on the EOG reserve that you guys had to write-off, is that just a timing issue, because you’re not planning on drilling that within, I guess the next five years or whatever the rule is on that?

Matthew D. Cabell

It’s a combination of things, Andrea. Some of it is simply pricing, as we evaluate these, we have to use the current pricing to evaluate the economics of the, the crude undeveloped wells. We’ve also had some weaker performance on the last set of wells that we drilled with EOG, so there were some negative revisions associated with that as well.

Andrea Sharkey – Gabelli & Company

Okay, that’s helpful. And then I guess just the last thing for me is actually on the pipeline. With northern access in line and going into service, you gave the top line impact for the full year, but I guess, how should we think about that maybe sequentially ramping up through the year and then is there more impact to come from that into fiscal 2014. I guess, meaning it won’t be fully ramped up in 2013 or I guess just help with the timing on that maybe?

Ronald J. Tanski

Andrea, this is Ron Tanski, line in will be pretty much fully in service for all of 2013. However, Northern Access does ramp up a little bit and I’m trying to think if I've got those numbers here. I don't have them right at my fingertips, but most of that, there shouldn't be a whole lot of ramp up there with Northern Access. Once we get the compression in place that will be pretty set to go.

Unidentified Company Representative

I think by 2014 it’s ramped up.

Andrea Sharkey – Gabelli & Company

Okay, thanks guys. That’s really helpful.

Operator

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

Kevin A. Smith – Raymond James & Associates, Inc.

Hi, good morning gentlemen. Nice quarter.

Matthew D. Cabell

Thanks.

Kevin A. Smith – Raymond James & Associates, Inc.

Matt, is any Marcellus production still curtailed or is everything on line now?

Matthew D. Cabell

No, we're curtailed about $25 million a day right now.

Kevin A. Smith – Raymond James & Associates, Inc.

And what’s outlook for that?

Matthew D. Cabell

It’s probably going to stay that way for at least another couple of months. The spot price on TGP 300 has been consistently below $2 and frankly we're just not in any rush to produce into that price. For the foreseeable future, at least most months we have 130 million a day of firm sales, so it's probably just made at production rate on TGP 300.

Kevin A. Smith – Raymond James & Associates, Inc.

Okay, so we’re just waiting for, is there any I guess potential for any increase firm sales or is it just more of just you're max out the backside of it so you're waiting for pricing?

Matthew D. Cabell

It’s difficult to increase firm sales at an index price that we're happy with.

Kevin A. Smith – Raymond James & Associates, Inc.

Got you.

Matthew D. Cabell

But for now, I would just assume the status quo and we'll see what happens with market.

Kevin A. Smith – Raymond James & Associates, Inc.

Okay, fair enough. How much more expensive are the cluster spacing completions?

Matthew D. Cabell

Good way to look at it is assume that an RCS will reduce cost for spacing well has twice as many stages and each of those stages costs 60% of what an ordinary well would, so let’s say, you had a 20 stage frac job, you turned into a 40 stage frac job, you will be adding about $1 million to the cost.

Kevin A. Smith – Raymond James & Associates, Inc.

Okay, great. And then lastly any updates on the three wet gas Marcellus wells you are drilling in western Elk County. I think you’re supposed to start fracking them sometime right about now.

Matthew D. Cabell

Actually Kevin, we haven’t drilled them yet.

Kevin A. Smith – Raymond James & Associates, Inc.

Okay.

Matthew D. Cabell

Its part of our slowdown; we’re not going to start drilling those wells till really probably the beginning of the next fiscal year roughly.

Kevin A. Smith – Raymond James & Associates, Inc.

Got you, okay. That’s all I have. Thanks.

Operator

Our next question comes from the line of Mark Rogers with Soroban Capital. Please proceed

Mark Rogers – Soroban Capital Partners LLC

Good morning guys

Unidentified Company Representative

Good morning, Mark.

Unidentified Company Representative

Good morning, Mark.

Mark Rogers – Soroban Capital Partners LLC

So Dave, I just wanted to touch on the MLP question briefly, I know you are often asked the question and I think you typically say your open to it, but you kind of stop there, but with your close period, QT recently forming MLP and trading well and quite frankly the under performance of NFG versus the period of over last 18 months or so, I think equity is up 20% of that period and NFG is down about 25 over the same period, I wanted to see you could possibly put some tighter goal post around potential timing of the formation for MLP, particularly with midstream is top steady growth curve already for the company now.

David F. Smith

Yeah, I think what we have said is not only, we have said that we are open to an MLP, but what we said, it’s largely going to be driven by the need for capital and as we look to all of these various projects that are coming down the pike and there are 10 or 11 that we’ve talked about. Obviously that will drive a significant need for capital in the future. And we’ve regarded an MLP and I think the equitable experience verifies that, that is a good financing vehicle.

So through the expansion, looking for timing, we’re looking at a couple of years, but there are moving parts, I mean, we can use our balance sheet. So they are number of other options as well. But we do look to an MLP as a potential financing vehicle next year or so.

Mark Rogers – Soroban Capital Partners LLC

And then…

David F. Smith

Depending upon as the projects developed.

Mark Rogers – Soroban Capital Partners LLC

Okay, it makes sense. And then just one follow-up on that and I realized that one school of thought obviously is that you wait until you have identified growth projects and it's a funding mechanism before forming an MLP, but is there also an argument that maybe the lack of MLP it might really be an impediment to you winning more business and deploying more capital in the Marcellus and Utica, both from the cost of capital and management focus perspective?

You guys seem to have to really be in a pole position with your current assets and quite frankly it’s a little surprising you have been able to deploy more and more quickly, given the advantage you have with the pipe in the ground, so I'm just thinking out loud, but just wonder if MLP could potentially accelerate that both from a focus and cost of capital perspective?

David F. Smith

Yeah, there is an argument for that, but at the end of the day, we've talked all that through and we will be driven by the need for capital.

Mark Rogers – Soroban Capital Partners LLC

Okay, thanks.

Operator

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

Timm Schneider – Citigroup Global Markets

Hey, guys. So far all is well. Just a quick question on the gathering side, what’s your incremental gathering cost in the Marcellus on the new stuff you're hooking up and how does that, what portion of the LOE guidance that you gave in 2013 is a...

Unidentified Company Representative

Well, what proportion of the – oh, okay. I think I understand your question. As we bring on Trout Run system our gathering costs are higher there. So, Covington is $0.32 range and Trout Run will be pushing 50. So it is higher…

Timm Schneider – Citigroup Global Markets

But it is ulnar company.

Unidentified Company Representative

It is ulnar company, right, we pay it to ourselves. In terms a portion of our total LOE it's, it's a quarter of it, roughly.

Timm Schneider – Citigroup Global Markets

Got it. That was it…

Unidentified Company Representative

Well, no I'm sorry. A little more than a quarter.

Operator

Our next question comes from the line of Mark Barnett with Morningstar. Please proceed.

Mark Barnett – Morningstar Inc.

Hi, good morning.

Unidentified Company Representative

Good morning, Mark.

Mark Barnett – Morningstar Inc.

A couple of just quick questions around those, those Lycoming wells. Obviously, some pretty strong figures. Is there any, you know I know you updated your CapEx? But is there an increase in development of that area within your, your latest CapEx guidance.

Unidentified Company Representative

No, it hasn't really changed. It's been the focus of our, our program in fiscal 2013 for sometime now.

Mark Barnett – Morningstar Inc.

Okay, and maybe a little early to comment on this, but, how do the, kind of early decline rates look on those wells versus your experience in kind of your earlier Marcellus development?

Unidentified Company Representative

And so, far very similar. But, but keep in mind, we've only had those wells on for, oh, two months.

Mark Barnett – Morningstar Inc.

Okay, thanks for the color.

Operator

(Operator Instructions) Up next, we have Becca Followill with U.S. Capital Advisors, please proceed.

Becca Followill – U.S. Capital Advisors LLC

Good morning, guys.

Unidentified Company Representative

Hi, Becca.

Unidentified Company Representative

Hi, Becca

Becca Followill – U.S. Capital Advisors LLC

Can you talked about potentially increasing drilling if gas prices were higher, at what gas price would we start to see an increase in CapEx?

Unidentified Company Representative

Well, we haven’t set a specific, $2 gas price will increase the number of rigs, but, we're looking at a range of gas prices get to, $3.80, 3.94 would be certain looking pretty higher to adding a rig.

Becca Followill – U.S. Capital Advisors LLC

Okay, perfect, thank you. And then following the year two JV then not pursuing anymore, what is your new net acreage position in Marcellus, do you guys have that?

Unidentified Company Representative

Yeah, Beck it may surprise you that it's not a, it's not a huge change in the overall acreage position. I think it’s an improvement in the quality, though. So in the initial joint venture EOG contributed a 140,000 gross acres. We contributed 200,000 gross acres. So, we get back a 100,000 net less what they’ve earned. They’ve earned roughly 17,000 of that, so get back 83,000 and we give up access to 70,000, so it’s a 13,000 net acre increase. However, a lot of the acreage that they have contributed was fairly scattered across the state. Some of which we probably would never have gotten to within the joint venture. So in that sense, I would say perspective net acreage is really gone up, more than 30.

Becca Followill – U.S. Capital Advisors LLC

Okay. And then the write-down of reserves for the quarter because of the EOG and the weaker performance on the recent wells, can you quantify that.

Unidentified Company Representative

You mean the break out between those two.

Becca Followill – U.S. Capital Advisors LLC

Just how much the total life.

Unidentified Company Representative

It was about 75 Bcf out of the joint venture is that right.

Becca Followill – U.S. Capital Advisors LLC

60.

Unidentified Company Representative

60 at the joint venture.

Becca Followill – U.S. Capital Advisors LLC

60. Thanks. And then the last one on California, you talked about a well that was $400,000 well that was producing 50 barrels of oil per day. And just what information, and do you know, how many incremental locations you might have or what kind of returns as well as generate?

Unidentified Company Representative

It’s in the [Michigan], its at North Lost Hills, we have a follow-up, that we’re going to drill in fiscal 2013 and the running room is relatively small. So they’re, they’re note going to be a lot of those wells.

Becca Followill – U.S. Capital Advisors LLC

So it’s not a move on.

Unidentified Company Representative

No.

Becca Followill – U.S. Capital Advisors LLC

Okay, great. Thank you guys.

Unidentified Company Representative

Yep.

Operator

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

Carl Kirst – BMO Capital Markets

All my questions have been hit. Thanks.

Operator

Ladies and gentlemen, since there are no further questions in queue, I’d now like to turn the call over to Mr. Silverstein for closing remarks.

Timothy J. Silverstein

Thank you, Jeff. We’d like to thank everyone for taking the time to be with us today. A replay of this call will be available at approximately 2 p.m. Eastern time on both our website and by telephone, and will run through the close of business on Friday, August 10, 2012. To access the replay online or to find additional information visit our Investor Relations website at investor.nationalfuelgas.com and to access by telephone, call 1-888-286-8010 and enter pass code 85783979. This concludes our conference call for today. Thank you and goodbye.

Operator

Ladies and Gentlemen, that concludes today’s call. Thank you for your participation. You may now disconnect. Have a wonderful day.

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