National Fuel Gas Co (NFG) 2011 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the fourth quarter 2011 National Fuel Gas Company earnings conference call. My name is Larry, and I will be your operator for today. At this time all participants are in a listen-only mode. Later we will conduct a question-and-answer session. (Operator Instructions) I would now like to turn the conference over to your host for today, Mr. Tim Silverstein, Director of Investor Relations. Please proceed.

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

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

Thank you, Tim, and good morning, everyone. The fourth quarter has been an outstanding year for National Fuel. Recurring earnings for the quarter were up $0.06 per share, or 15% over the prior year's fourth quarter. Seneca had another strong quarter hosting a 3.8 Bcfe, or 29% quarter-over-quarter increase in production, which in turn drove a $0.04 per share increase in E&P results. Earnings in the regulated segments were up $0.02 per share for the quarter, thanks in large part to a great job by our employees in controlling costs and in driving operational efficiencies across our regulated business units.

In the field, we had a good quarter as we continued to execute on our plans for growth in Appalachia and western Pennsylvania. Seneca continues to build momentum, particularly in the Marcellus. During the quarter, Seneca had 5 rigs operating, which combined to spud another 23 horizontal wells while EOG initiated an additional 13 horizontal wells. Our daily production rate from the Marcellus at the end of fiscal 2011 was nearly triple last year's rate. In addition, even after the sale of our offshore Gulf of Mexico properties, Seneca's proved reserves at September 30 increased by 34% to 935 Bcfe. Simply put, overall, we're very pleased with the results we've achieved in the Marcellus to date.

Turning to the regulated businesses, the Pipeline and Storage segment saw a reduction of its transportation revenues due primarily to the persistently strong pricing basis at Niagara which made selling import capacity from Canada difficult. As you know, this was not a surprise. It was consistent with our expectations and consistent with our forecast. Fortunately, but also consistent with our expectations, net revenue erosion stabilized and moving forward, pipeline and storage revenues will increase significantly.

Last month Supply Corporation placed its Line N Expansion Project in service, and I expect that Empire's Tioga County's Extension Project, which takes advantage of the relatively strong market north of the border, will be in service this quarter. Combined, those 2 projects will add $23.7 million in revenues in fiscal 2012. After the contracts underlying those projects have been ramped up to their full volumes, which will take about 18 months or so, annual Pipeline and Storage revenues will be impacted by about $36 million.

Our Utility turned in a very strong performance, despite the continued weak economy. Thanks to a number of revenue protecting mechanisms, things like revenue decoupling, weather normalization, 90/10 symmetrical sharing, our Utility earnings are much less sensitive to macroeconomic cycles. This stability not only benefits our retail customers, but our shareholders as well. Like our Pipeline and Storage earnings, Utility earnings are not particularly sensitive to commodity price volatility, which serves as a nice hedge to E&P earnings. As we have said in the past, the stable, predictable earnings of the regulated companies serve as the foundation for our long standing dividend, to which we remain committed.

Looking ahead we're expecting an even better year in fiscal 2012. In the E&P segment, we're adding a sixth Seneca-operated rig in early 2012 and plan to drill on the order of 50% more net wells in 2012 than we did in 2011. As a result, we anticipate production growth of nearly 40% and look to maintain a similar growth rate in the following years. A top priority, really the top priority in the E&P segment, will be the further delineation of our western acreage. We made good progress on this front in 2011, delineating our extensive Owl's Nest area. As a result, beginning in January, 2012 we plan to operate 1 or 2 rigs in this 90,000-acre block, which is largely owned in fee and thus, royalty free. As Matt will discuss later in the call, we will continue to explore and delineate additional Marcellus acreage with the goal of identifying large continuous blocks that can be developed in an efficient and systemic manner.

In addition to our Marcellus development, we are very excited about our opportunities in the Utica shale in which we hold an extensive position. We are in the initial phases of testing and plan to drill additional vertical and horizontal wells during the course of the year to assess the economics of our acreage position in the play. While it's admittedly early, it's fair to say that we like what we've seen thus far. Given the extensive opportunities present in the Marcellus and given the potential in the Utica and Geneseo shales, we remain excited about our future in Appalachia.

In California, we look to this asset for consistently strong cash flows and it continues to deliver. In spite of a small dip in production, which was expected, these assets continue to generate significant free cash flow which we redeploy to our Marcellus program. Given the strength of our team in California and the balance offered by oil assets, we'd love to acquire additional bolt-on acquisitions like, for example, our Ivanhoe acquisition previously, and we will continue to work towards that end. In the Pipeline and Storage segment, we'll continue to capitalize on the strategic location of our system and the value it brings to Marcellus producers in the area.

Our near term focus will be on building the Northern Access Project which is designed to move 320 decatherms per day of Statoil's Marcellus production in a northerly direction from northwestern Pennsylvania to Supply Corporation's interconnection with TransCanada at Niagara. This project, which should cost about $62 million, will add $13.4 million in annual revenues once it's in service, likely in early fiscal 2013. Longer term, we continue to pursue expansions of our Line N and Tioga County Extension Projects as well as the development of the larger West to East Project. Needless to say, given the location of our Pipeline and Storage assets in the middle of the Marcellus, Utica and Geneseo shales and growing markets, we remain bullish on this segment.

In closing, fiscal 2011 was a very good year for National Fuel financially and operationally. Our regulated businesses performed as expected, and our Pipeline and Storage and E&P segments continue to capitalize on our compelling growth opportunities in Appalachia and western Pennsylvania. And as I said earlier, we expect more of the same and that fiscal 2012 will be an even better year. With that, I'll turn the call over to Ron.

Thanks, Dave, and good morning, everyone. As Dave said, in addition to our good financial performance for fiscal 2011, it was a good year from an operations point of view, and we've started off fiscal 2012 in great shape. In the Utility, we were on track with all our major capital maintenance projects, and our $58 million in spending in our Utility pipelines was pretty much right on budget.

Going into the winter heating season, Utility has 97% of its gas storage capacity filled, which is just where we planned to be. Assuming a normal winter, we're projecting that our average customer's winter heating bills for the entire winter will be about $719 in our New York jurisdiction and $663 in our Pennsylvania jurisdiction. The estimate for New York is slightly less than last year, and the Pennsylvania estimate is about 1.5% lower than last year because it was about 2% colder than normal in our Pennsylvania jurisdiction last year.

In the Pipeline and Storage segment, all our pipeline integrity and maintenance work that we had planned for the year was also substantially completed, but some storage field work was moved into fiscal 2012. All the work that was done came in pretty well on budget, and on page 20 of last night's release where we show $129.2 million of spending in the Pipeline and Storage segment, $33.6 million of that total was for maintenance CapEx and the rest was for expansion projects including our Bowen Compressor Station, Line N and Buffalo Compressor Station Expansion, the Tioga County Extension, Northern Access and some work on West to East. With respect to those projects, the Bowen Compressor Station has been running since July, and Dave already covered the Line N and Tioga Extension Projects and next year's pipeline projects.

In addition to our Utility having 97% of its gas and storage for the upcoming winter, all of Supply Corporation's other customers have their contract in storage space filled up to about the 93% level. So, we're in good shape to meet all our customers' winter supply requirements.

In our Midstream business, we're busy installing the Trout Run Gathering System in Lycoming County for Seneca's production from the Lycoming County DCNR Tract 100. As you know, Seneca drilled a successful test well on the tract last year, and we're looking to get a backbone line installed to be ready to accept production as soon as Seneca begins to complete entire well pads beginning in January or February.

I'll let Matt cover most of the operational highlights for the exploration and production segment and move on to the Marketing segment, which continues to perform well. Although overall sales volumes were down, the volume decrease was from NFR's lower margin wholesale customers who our earnings in the segment were consistent year over year.

Looking ahead, National Fuel Gas Supply Corporation filed a rate case at FERC to increase its interstate transportation and storage rates. The case was filed at end of October, approximately 17 years since we filed our last rate case. The filing requests a cost of service of approximately $199.3 million, or approximately $38 million in higher revenues over our current supply corporation rates. That's about a 24% increase in its annual rates. We expect that FERC will follow its normal process and suspend these new filed rates at least through May, 2012 while the parties to the case review the file testimony. Our earnings guidance does not include any increased revenues attributable to this case for fiscal 2012 because we can't really be sure of the timing of a FERC order in the case. I'll give you an update on the case probably after our June quarter. With that, I'll turn it over to Matt for a Seneca update.

Thanks, Ron. Good morning, everyone. For the fourth quarter, Seneca produced 16.8 Bcfe, a 29% increase over last year's fourth quarter. For the year, production was 67.6 Bcfe, an increase of 18 Bcfe, or 36%, despite the fact that we sold our Gulf of Mexico assets.

In California, we produced a total of 3.2 million barrels equivalent in fiscal 2011. We drilled 32 wells at our South Midway-Sunset field and added 740,000 barrels of reserves. Production is now up to 810 barrels of oil per day at South Midway, and we expect production to continue to increase as we see the impact of the increased steam injection.

Last week we saw first production from a new non-operated Monterey shale well in California. The well came on at about 90 barrels of oil per day and has leveled off at about 60 barrels. While Seneca only has a 12.5% interest, there could be hundreds of follow-up wells. We're excited about this initial well test and anxious to see how it holds up.

Moving on to the east division, fourth quarter Marcellus production was a bit lower than anticipated due to some delays in bringing on new wells, some temporary shut-ins and disappointing initial production from our second to last Covington area well pad. Fourth quarter production from the EOG joint venture was down 0.3 of a Bcf due to natural decline with no new wells brought online. EOG is actively fracking now, and we expect the joint venture production to jump up soon.

The final Covington well pad came on at good rates such that average Marcellus production in October was approximately 142 million cubic feet per day, or 126 million net after royalty. I expect Marcellus production to stay at about that rate for the first quarter, or about 15 million to 20 million a day higher than the quarter that just ended. We expect a big production bump in the second quarter as we bring on new wells at Tract 595 and initiate production at Tract 100 in Lycoming County.

I want to stress that our fiscal 2012 production guidance has not changed. As I've said in the past, the nature of our pad drilling and completion strategy will naturally lead to a stair-stepped production profile. While there's uncertainty of the precise timing of our production adds, we're quite confident that our rapid growth will continue.

Our 3 new wells at Mount Jewett have been tested at peak rates between 2.3 million and 3.1 million cubic feet per day on a 40/60 forced choke. While these rates are a bit lower than we've anticipated, we should achieve higher rates several months from now when the gathering system is installed and the wells have cleaned up completely. In fact, most wells on our western acreage have not reached their peak rates during early testing. While it's too early to estimate EURs from this limited test data, with our 100% revenue interest we can achieve acceptable returns with 3 Bcf average EURs in current NYMEX pricing. One of our goals for this 3-well pad was to determine the ideal landing depth for this area, and while the IP rates for all 3 wells were similar, 1 well had a steadily increasing production profile for the first 48 hours and a relatively flat profile thereafter, markedly different from the other 2. This well was landed in the lowest member of the Marcellus and confirms our previous experience at Owl's Nest where the deepest well was also the most prolific.

Mount Jewett is a particularly interesting area for us in that we have potential in the Marcellus, the Geneseo and the Utica. Our Utica vertical well that we drilled a few months ago found 400 feet of Utica and Point Pleasant pay. We plan to frac and flow test this well soon and will drill a horizontal Utica test here in the second quarter. We will follow the Utica horizontal with a Geneseo horizontal. Our next Marcellus delineation test is at Boone Mountain where we are currently fracking in southern Elk County. We expect to have that 3 well pad completed in a few weeks. Beginning next week, we will be drilling in the Rich Valley area in Cameron County with a frac of that pad planned for the second quarter.

Moving on to the Utica, we are finishing up the drilling of a vertical well in western Venango County. This location appears to be near the wet gas/dry gas boundary, so we're anxious to get it tested. That completion will follow the Mount Jewett vertical, so a month or 2 from now. This well is about 25 miles north of the Rex Energy Utica well that was announced earlier this week with an IP rate of 9.2 million a day.

In the Geneseo shale, our Potter County well went to sales a few weeks ago and reached a peak 24 hour rate of 4.5 million cubic feet per day, better than what we saw in the initial 3-day test. We are now planning some additional Geneseo wells in this area and at Mount Jewett. Seneca's year-end reserves for fiscal 2011 are 935 Bcfe. We replaced 448% of production at a cost of approximately $1.95 for Mcfe. Looking forward for fiscal 2012, we anticipate annual production of 87 to 101 Bcfe, or 38% growth at the midpoint of the range. So far, we have derisked 125,000 net acres in the Marcellus with 4 Tcfe of reserves and resource potential in the derisked areas. Overall, Marcellus' risk potential remains the same at 8 to 15 Tcfe.

In addition, we have first production from the Geneseo shale, first production at a new location in California's Monterey shale, and perhaps most significantly, a very promising opportunity in the Utica shale. We will be aggressively evaluating each of these new plays in 2012 as we continue to develop and delineate our Marcellus acreage. With that, I'll turn it over to Dave Bauer.

Thank you, Matt, and good morning, everyone. From an earnings standpoint, the fourth quarter was a good one for National Fuel. Our consolidated earnings of $0.45 per share for the quarter and $3.09 for the fiscal year were toward the high end of our range of expectations. Yesterday's release does a good job explaining the major variances in earnings, but I wanted to add some color to a few items. First is operating expenses in the E&P segment. As you saw in last night's release, Seneca's G&A expense for the quarter was $14.2 million, up sequentially from the $11.3 million for the third quarter of fiscal '11. This uptick was mostly attributable to 1-time relocation and other expenses associated with the opening of Seneca's new Pittsburgh office.

Going forward, we're still comfortable with our $54 million to $56 million range for fiscal 2012 G&A expense at Seneca. Seneca's per unit LOE expense for the quarter of $1.16 was a bit higher than our annual rate of $1.08 per Mcfe. The increase for the quarter was attributable to several factors, including an increase in LOE on our nonoperated EOG joint venture wells and higher steaming costs at our California oil properties. In addition, an out of period adjustment to LOE expense added a few cents to the rate for the quarter. Looking forward, as we continue to add low cost Marcellus production, we expect our LOE rate will decline into the $0.85 to $1 range that's baked into our fiscal 2012 earnings assumptions.

Turning to the regulated segments, the fourth quarter is usually a fairly quiet quarter, and this year was no exception. A bright spot, though, was the utility's bad debt expense. As in prior years, we take a pretty conservative approach to our bad debt accruals for the first 9 months of the fiscal year and then take a hard look at the reserve at fiscal year-end. A continued low natural gas price environment, combined with the refunding of an over collection of gas costs from the winter of 2010, had led us to expect a modestly lower level of bad debt expense in 2011 as compared to 2010. When we reached year-end, our accounts receivable aging was better than we had expected. In fact, our final billed accounts are pretty much as low as they've been since the early 2000s. As a result, we were able to reverse about $3.9 million of bad debt expense that we had recorded earlier in the year, and it's that adjustment that drove the $2.3 million decrease in the Utility's O&M expense for the quarter.

Turning to our forecast for 2012, we're reaffirming our earnings guidance range of $2.85 to $3.15 per share. That guidance assumes NYMEX pricing of $4.50 for natural gas and $95 for crude oil, and the current natural gas strip is somewhat lower than $4.50, but it's still pretty early in the year, and we'll likely revisit that assumption in the coming quarters should prices stay at current levels. As always, we've included a sensitivity table in yesterday's release to give an idea of the impact of changing commodity prices on earnings. Our consolidated capital budget and financing plans for fiscal '12 are unchanged from what we reviewed at our analyst day in September.

To recap, our consolidated fiscal '12 capital spending will be in the range of $980 million to $1.13 billion. Assuming the midpoint of our earnings guidance, we project cash from operations of approximately $725 million. Layering in our dividend and debt maturity, we project a total financing need in the $550 million area. Our $150 million maturity is due later this month, and we plan to go to market with a long term debt issuance very shortly after we filed our 10-K. As I said at our analyst day, I expect that issuance will also prefund a large portion of our fiscal '12 capital needs. With that, I'll close and ask the operator to open the line for questions.

(Operator Instructions)And our first question comes from the line of Andrea Sharkey of Gabelli & Company. Please proceed.

Hi, good morning.

Hi, Andrea.

So, I guess first question, I was wondering if you could maybe go through the western acreage delineation stuff again, Matt. It kind of went by fast, and I think I maybe missed some stuff. And I don't know if you gave maybe IP rates or anything related to some of those. I guess you gave Mount Jewett, but --

Mount Jewett is the only one -- only new area that we tested in the past quarter.

Okay.

That's the only one with rates, and if you want to kind of think about how we classified the acreage, I would define Mount Jewett as still in the delineation phase. We need to get those wells online and get a little bit of production history. We'll be at Boone Mountain. We're at Boone Mountain now, fracking it. We should have results from that in a month or so. And then we've got a rig moving to Rich Valley in about a week, and then we'll drill a three-well pad at Rich Valley and we'll test those wells.

Okay. And then it looks like your F&D costs for the year maybe went up a little bit from last year, and I was wondering if you maybe you could just address what's going on there. Is it more just like timing? I know you spent a lot more CapEx than you did last year and maybe timing before that sort of pays off.

Yes. I think one big factor in the way the timing of the reserve bookings worked, this year a lot of our capital went to developing Covington and basically, that was drilling up PUD reserves. So, those wells tended not to add reserves, but rather just converted PUDs to PDP. That's certainly a factor in what the F&D looks like. It didn't really go up a lot. It did go up a bit, though.

Okay. That's helpful. And then I guess maybe just looking at different possibilities to fund a lot of the development in the western acreage, I saw Chesapeake last night did a Utica JV and then also created a different Utica company. It seems like it's almost like a royalty interest. Have you guys considered or would you think about, would it make sense to do some sort of maybe royalty interest on the eastern acreage where soon you'll have kind of more developed? In Covington, it's pretty much finished being developed, and then you've got Tract 595 starting, and once that stuff is sort of up and running, maybe would that make sense to try to bring in some extra capital to put towards the western acreage?

Andrea, we've certainly talked about the concept of a royalty trust. In our Marcellus drilling, I'm not sure that we're at a level of maturity on the western acreage for that to necessarily make sense. But we consider options such as a royalty trust or even a conceivably a royalty trust on our California properties as a way to provide additional funding beyond what we could get from the debt market.

At this point, Andrea, we're pretty comfortable with our plan to lever up, use debt to be able to handle those drilling needs. And in our forecast, we forecast Utica development as well, so.

Okay, great. I'll turn it back. Thanks.

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

Good morning, gentlemen. Matt, would you mind giving us some additional information on the, I guess the pad at Covington? It didn't perform up to expectations. And maybe some variability of what expectations were and how much we're off.

Sure. It was an 8-well pad, and those wells came on more in the 2 million a day rate rather than the 5 million a day rate that we've had at most of the well pads at Covington. So, it is impactful to our production numbers, but it's 1 pad. The next pad that came on at 5 million a day rates again. It was on the kind of the edge, the eastern edge of our acreage. I think when you're looking at overall production expectations, we're going to occasionally have a pad that's a little weak, and we'll probably have other pads that are stronger than expected and will completely counteract that.

Got you. Can you give us -- I know you touched on your opening remarks, when are we expecting to see I guess next well results from Owl's Nest?

It will be a little while. We're acquiring 3-D seismic as we speak. We'll have a rig there in January, and then we'll have to drill pads and frac them and get them online. So, it's probably not until third quarter.

Okay. And then lastly, before you have start of the calendar year the Lycoming stuff coming on. Do you have 1 more well or 1 more pad in Covington, or what's the new well production going to look like over the next three months?

Covington is fully developed, so no new wells to bring on at Covington. We've got 3 rigs now on Tract 595. So, we'll have new well pads coming on, on 595 in January. Tract 100 will initiate production probably, maybe more like early February for Tract 100. We'll have a lot of new things coming on in the second quarter.

Got you. Okay. That answers all my questions. Thank you.

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

Hi. Couple questions. First following up on Andrea's question, royalty trusts kind of require certainty of service costs for whatever drilling commitment might be made. Can you quickly speak to your certainty of that in the Marcellus area out a couple years?

You're asking about a Marcellus royalty trust that we haven't put together, so I'm not really sure.

I think, Craig, to the extent we look at a royalty trust, it's far more likely we're going to look at that in California than it would be in the Utica or the Marcellus because of that kind of consideration, because of the maturity and predictability associated with California. To the extent that we utilize that as a vehicle to raise capital, it would very likely be -- we would very likely look to California before we'd look elsewhere. Let's put it that way.

Fair enough. And realizing that we're still early on in the Owl's Nest and kind of west of that, but as you look towards the more liquids rich part of Marcellus and even into the Utica and Geneseo, can you comment about the ability to handle wet gas processing and NGL off-take from your properties?

Well, Craig, as we develop these properties that are in the wet gas window, we'll build the processing facilities that we need to handle it. Those processing facilities aren't in existence today.

Right. Would you be planning to do that internally or kind of partner or? How do you see that kind of rolling out?

More likely it would be with some third parity.

And do you think enough infrastructure will be there, say, in the next 24 months where if we continue to delineate, that if it made economic sense, you wouldn't be limited by the infrastructure?

I think there's potentially a need for the ethane solution to be in place, but that's really the -- that's probably the only true limiting factor that can't be solved by building the facilities that are needed.

Okay, great. Thank you.

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

Hey, good morning, everyone.

Hey, Mark.

Couple of just quick questions. You discussed at the Analyst Day a couple of areas that didn't hear much about today, and I was wondering, you were expecting completions September, October-ish in the Boone Mountain and the Rich Valley areas. I was wondering maybe if those were the areas where you were a little bit delayed on completions or if you can had any detail to add on those areas?

No. Those are pretty much on schedule.

Okay. So, that's just going to be something we'll hear about more maybe in first quarter of '12?

Yes. Boone Mountain will be -- we're fracking it as we speak, so not sure what we said at Analyst Day. We might have said November completion, so --

Okay, okay.

We're just at the point of starting to drill those wells.

Okay. And if I look at your total well costs from the Analyst Day presentations, basically, is this mostly attributed to moving a little bit further west? I know that well costs and, for instance, in southwestern Pennsylvania are much higher than in the east, but is that kind of what's driving this movement?

Which movement are you talking about?

I just -- over the course of 2011 and off of 2010, well costs have grown pretty substantially on an average basis. And you said that they're coming down in the last couple quarters here. So, I'm just wondering what's --

Oh, sure, yes. Really, the way to look at that is service company costs increased for a period of time, and I guess they've pretty much plateaued. We're going to drive the costs down through efficiencies, through drilling efficiencies, drilling and completion efficiencies, and we -- while our well costs in the sort of second half of 2011 was a little over $6 million per well, we expect that in the next 18 to 24 months we're going to drive that down below $5 million. Especially on the development wells

So, there's nothing more fundamental to your more western acreage that might be driving that number up, then?

No, no. If anything, the western acreage is probably a little cheaper than the eastern acreage.

Okay. Appreciate the detail. Thanks, guys.

Our next question comes from the line of John Abbott of Pritchard Capital. Please proceed. Mr. Abbott, your line is open for questioning at this time.

Hey, good morning.

Morning.

Yes, just quickly here, looking at your -- looking at the quarter, it looks like your oil price realization came in $101.45 on the West Coast. What are you seeing for differentials out there right now?

We're basically at a premium to WTI, and oil is trading more at a discount of Brent than it is on any kind of index to WTI now.

And has that been factored into your earnings per share guidance?

This is Dave. We've taken a more conservative approach to the basis numbers that we used for 2012 and are basically at a NYMEX flat-type assumption. The thing to keep in mind when you're modeling our oil revenues after hedging is that we're pretty fairly well hedged on the oil side for 2012.

I appreciate it. And then just my final question, could you remind me -- have you said what the cost of that horizontal Utica well is going to be at approximately?

We have not, and I guess I'm hesitant to just throw out a number without some detail.

I understand.

It's going to be more than a Marcellus well.

It's an exploration well, I understand.

Exploration well, and it's deeper.

Yes. All right, I appreciate it. Thanks.

Yes.

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

Hey, guys, my questions have been answered. Thank you.

Good talking to you, Timm.

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

There we go. I could just say ditto, because my questions were answered, too. Maybe just one quick, just looking at the fiscal fourth quarter in the Marcellus. You guys had mentioned, sort of three things, a bit of a delay, the temporary shut-ins, the second to last well pad at Covington. Was one of those -- given that the Covington pad was coming in at 2 rather than 5, was that primarily or was it kind of a third, a third and a third, or just as we kind of dot our I's and cross our T's?

Oh, let's see. I think you can probably characterize it as maybe 50% that pad and 50% the other two factors.

The other two. Great. Thanks, guys.

Yes.

Our next question comes from the line of Becca Followill of US Capital Advisors. Please proceed.

Good morning, guys.

Good morning.

Two questions for you. Hey, on the Monterey shale, is that -- does that change your perspective on what you think California production is going to do? Does it allow you to grow, or does it just stabilize it a little bit further out?

We're just not there yet, Becca.

Okay.

It's just one well. And keep in mind, we only have a one-eighth interest in this. So, even if we drilled a couple hundred wells out here, we'd have a one-eighth interest in wells making 60 barrels a day. It's meaningful to us, but it's not a substantial change in our production forecast.

Okay, great. Thank you. And then the other question is on, Dave, you said your goal this year was to delineate acreage. So, if I look at page 30 from your presentation at your Analyst meeting, it sounds like in the areas, the western development areas, that you -- we have a time on that Mount Jewett, Boone Mountain, Rich Valley and then -- so we know that acreage, but what additional acreage do you plan on delineating in 2012?

I'm flipping to this page you're asking about. As you look at this list, we're going to delineate -- if you look kind of at the top of it, we'll delineate 007 and 001 with some additional drilling. We've got wells producing on 001 now. We'll further delineate Jewett, we'll likely delineate James City, Boone Mountain, Rich Valley and very possibly some of the other areas in the western development areas. And then in addition, there will be some additional delineation drilling done on the EOG joint venture acreage as well.

What about the Utica?

I thought she was asking specifically about Marcellus. We'll be drilling wells in the Utica at Mount Jewett, one in -- probably in Tionesta, which is kind of eastern Venango county, and we'll very likely drill a well at Owl's Nest at well in the Utica.

Great. Thank you.

Yes.

And our last question comes from the line of Josh Silverstein of EnereCap Partners. Please proceed.

Good morning, guys.

Hey, Josh.

You talked previously about looking for some potential oil acquisitions, whether they be in California or elsewhere. Just given the outspend you guys have over the next few years, how aggressive could you be there?

Well, I like the kind of bolt-on Ivanhoe acquisition that we did in California, and we have a person that really is focused on looking for those kinds of acquisitions. To the extent we're looking at some big acquisition in another play, that -- it would have to be something that was -- what I would regard as a bargain or pretty compelling to do it. We have a lot on our plate right now in the Utica, the Marcellus, California. So, I don't think we're looking at a Company changing event. Let's put it that way.

Got you, okay. Then the delay that you talked about in the fourth quarter, was that more related to getting infrastructure in place or from getting a frac crew to complete your wells?

You mean the delays in bringing wells online?

Right.

There's a couple factors. It was more related, really though, to getting the frac crew set up and the wells fracked and brought online. But I guess really the other factors in the joint venture with EOG, they just made a conscious decision to delay some of their fracking, and they're now getting after it. It'll all catch up.

Got you. And then lastly for me, you talked about a jump in the second quarter regarding the production there. Where would you think you would go from -- you talked about getting another $15 million per day jump over this past quarter. So, would that would take you from 140 to 150 up to 200, or is that too much of a jump to expect?

For an average for the second quarter that's too much. And I guess I'm -- I don't think we really disclosed an estimated rate at the end of the quarter, but I expect at the end of the second quarter we'll be substantially higher than where we are today.

That's it for me.

Thanks, Josh.

With no further questions, I would like to turn the conference back over to Mr. Tim Silverstein.

Thank you, Larry. 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 close of business on Friday, November 11, 2011. To access the replay online, visit our Investor Relations website at investor.nationalfuelgas.com, and to access by telephone call 1-888-286-8010 and enter pass code 92486219. This concludes our conference call for today. Thank you, and good-bye.

Ladies and gentlemen, that concludes today's conference. Thank you for your participation. You may disconnect at this time. Have a great day.