National Fuel Gas Co (NFG) 2012 Q3 法說會逐字稿

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'll 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.

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 my 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. Last night National Fuel reported third quarter 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% in 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 helped 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 in keeping an eye on spending, which helped to limit the overall impact of a 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 the East 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, a 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 in 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's 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 scaled down development plan at Tracts 100 and 595, and on Utica and 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 a significant slowdown in activity. Though disappointing, EOG's decision was not unexpected given the decline in natural gas prices and given their publicly stated intention to de-emphasize 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 in 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're ramped up to their fully contracted volumes. At NFG Midstream, the Trout Run gathering system was placed in service at the end of May. Though not a big factor in our third quarter results, as Seneca brings on additional wells in Lycoming County and as 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 producers have expressed serious interest in a further expansion of our Line N system. We'll keep you updated as that project develops. We also continue to pursue projects in the dry gas area of the Marcellus, such as Empire's Central Tioga Extension project and 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 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.

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 at North Midway. At Sespe we drilled six wells, including two more five-acre infill wells and two Coldwater tests. We plan to frac these wells sometime this fall. We also drilled a horizontal Etchegoin 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, an 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 costs may be a bit higher here, we're 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 of 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 that they're unlikely to meet their minimum drilling requirements for calendar year '12. 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 in 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 '12 will be greater than what we originally forecast. Consequently for the year, we expect to be very close to the top end of our guidance range at $690 million.

We now 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 is 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 have seen on the TGP 300 line. And another 3 to 4 Bcf related to completion delays, also in response to the low spot price. Absent the low spot price and the associated curtailments and completion delays, our production forecast would have been 85 to 90 Bcfe. For fiscal 2013, we are projecting production of 92 to 105 Bcfe, or about a 10% to 25% increase over fiscal '12. Meanwhile, we'll 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. Fortunately, 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.

Thank you, Matt. 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 on 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've 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 rate.

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 will average about $2.7 million per quarter. However, changes in gas prices and the timing of when we spud 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 to $2.48 per share. The increase reflects our third quarter results, our updated production guidance of 81 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 7 of last night's release. The earnings guidance section refers to a $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 to $2.75 per share. Midpoint-to-midpoint, a $0.17 per share increase over 2012.

Let's review 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 to 105 Bcfe. It also assumes flat NYMEX commodity pricing for our unhedged production of $3.25 per 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. Today's strip is a bit higher than our pricing assumptions, but we've included a sensitivity table in yesterday's release that can used to estimate the impact of different commodity pricing assumptions on our forecast.

From an 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 costs 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 midpoint of our guidance, per unit G&A in fiscal '13 should 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 editions, particularly at the end of the fiscal year.

Turning to the regulated businesses, you can expect a significant increase in Pipeline and Storage earnings in fiscal '13, mostly as a result of our recent expansion projects. The Northern Access and Line N 2012 projects, which will go in service in the first quarter of fiscal '13, will add about $20 million of revenues. On top of that, contacted volumes on the Line N 2011 and Tioga County Extension 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 turnbacks of capacity on the Supply 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 '12 and '13. Starting with '12, 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 $110 million in All Other, which is largely from Midstream's Trout Run gathering project.

For fiscal '13, our preliminary, 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. The break out of the consolidated total 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 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 principal financing activity next year. Our balance sheet is in great shape, our equity to cap ratio was a little higher than 57% at June 30th and should stay in that vicinity through the end of fiscal '13.

Lastly, with regard to our hedging program, for the remainder of fiscal '12 our gas production is about 65% hedged, in oil about 55%. For fiscal '13 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 1st. As I mentioned on the last earnings call, we intend to establish a fairly substantial long-term hedge position, to 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.

Thank you.

(Operator Instructions)

Andrea Sharkey, Gabelli and Company.

Hi, good morning.

Good morning.

Good morning, Andrea.

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 that has been a big impact for you guys, but I just wanted to get your thoughts on that.

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 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.

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 the next five years or whatever the rule is on that?

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 proved 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.

Okay. That's helpful. And then 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 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? Meaning, it won't be fully ramped up 2013 or just help with the timing on that may be.

Andrea, this is Ron Tanski. Line N 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 the 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.

I think by 2014, it's ramped up.

Okay. Thanks, guys. That's really helpful.

Kevin Smith, Raymond James.

Hi, good morning, gentlemen. Nice quarter.

Thanks.

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

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

And what's the outlook for that?

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 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.

Okay. So we're just waiting for -- is there any potential for you to increase firm sales or is it just more of you're maxed out on that side of it so you're just waiting for pricing?

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

Got you.

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

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

A good way to look at it is assume that an RCS well, a reduced cost per spacing well, has twice as many stages, and each of those stages cost 60% of what an ordinary well would. So if you had -- let's say you had a 20 stage frac job, you turned it into a 40 stage frac job, you'd be adding about $1 million to the cost.

Okay. Great. And then lastly any updates on the three wet gas Marcellus soils you're drill in western Elk County? I think you're supposed to start fracking them sometime right about now?

Actually, Kevin we haven't drilled them yet.

Okay.

As part of our slow down, we're not going to start drilling those wells till, really probably the beginning of the next fiscal year roughly.

Got you. Okay. That's all I had. Thanks.

Mark Rogers, Soroban Capital.

Good morning, guys.

Good morning, Mark.

Good morning, Mark.

So Dave, I wanted to touch on the MLP question briefly. I know you are often asked the question, I think you typically say you're open to it but you kind of stop there. But with your close peer EQT recently forming an MLP, trading well and quite frankly the under performance of NFG versus the peer group over last 18 months or so, I think EQT is up 20% over that period, and NFG is down about 25% over the same period. I wanted to see if you could possibly put some tighter goal posts around potential timing of the formulation for MLP, particularly with Midstream as the top stated growth priority for the Company now?

Yes, I think what we've 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 add -- 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 regard an MLP, and I think the Equitable experience verifies that, that it's a good financing vehicle. So to the extent you're looking for timing, we're looking at a couple of years, but there are other -- there are moving parts. We can use our balance sheet, so there are a number of other options as well. But, we do look to an MLP as a potential financing vehicle next year or so.

Got it. And then --

Depending upon as the projects develop.

Okay. Makes sense. Just one follow-up on that. I realize one school of thought obviously is you wait until you've identify growth projects and it's a funding mechanism before forming an MLP, but is there also an argument that maybe the lack of an MLP might really be an impediment to you winning more business and deploying more capital in the Marcellus and Utica, both from a cost of capital and management focus perspective? You guys seem to be really in a pole position with your current assets and quite frankly, it's a little surprising you haven't been able to deploy more, more quickly, given the advantage that you have with the pipe in the ground. I'm just thinking out loud, but I'm just wondering if an MLP could potentially accelerate, both from a focus and cost of capital perspective.

There's an argument for that. But, at the end of the day, we've talked all that through and we will be driven by a need for capital.

Okay. Thanks.

Timm Schneider, Citigroup.

Hi, guys, hope 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 that?

What proportion of the -- okay. I think I understand your question. As we bring on the Trout Run system, our gathering costs are higher there, so Covington is in the $0.32 range and Trout Run will be pushing $0.50.

Yes.

So it is higher.

But it is all intercompany.

It is all intercompany, we pay it to ourselves. In terms of proportion of our total LOE, it's a quarter of it, roughly.

Got it. That was it.

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

Mark Barnett, MorningStar.

Hi, good morning.

Good morning, Mark.

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

No, it hasn't really changed. It's been the focus of our program in fiscal '13 for some time now.

Okay. And it might be a little early to comment on this, but how do the early decline rates look on those wells versus your experience in your earlier Marcellus development?

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

Okay. Thanks for the color.

Yes.

(Operator Instructions)

Becca Followill, US Capital Advisors.

Morning guys.

Hi, Becca.

Hi, Becca.

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

We haven't set a specific -- $4 gas price will increase the number of rigs, but we're looking at a range, if gas prices get to $3.80, $3.90, $4 we'll be looking pretty hard at adding a rig.

Okay. Perfect. Thank you. And then following the EOG JV, the not pursuing anymore, what is your new net acreage position in Marcellus, do you guys have that?

Yes. Becca, it may surprise you that 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 140,000 gross acre, we contributed 200,000 gross acres. So we get back 100,000 net less what they've earned, they've earned roughly 17,000 of that. So we 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 had contributed was fairly scattered across the state. Some of which we probably would have never gotten to within the joint venture. So in that sense, I would say prospective net acreage has really gone up more than 13,000.

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?

You mean the break out between those two?

No, just how much the total was?

It was about 75 Bcf out of the joint venture. Is that right, Dave?

About 60.

60 out of the joint venture.

60. Okay. The last one on California, you talked about a well that was a $400,000 well that was producing 50 barrels of oil per day. I missed what formation and do you know how many incremental locations you might have and what kind of returns those wells generate?

It's in the Etchegoin. It's at North Lost Hills, we have a follow-up that we're going to drill in fiscal '13, and the running room is relatively small. So there are not going to be a lot of those wells.

So it's not a huge needle mover?

No.

Okay. Great. Thank you, guys.

Yes.

Carl Kirst, BMO Capital Markets.

All my questions have been hit. Thanks.

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.

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 PM 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 on-line 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 passcode 85783979. This concludes our conference call for today. Thank you, and good-bye.

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