National Fuel Gas Co (NFG) 2011 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the third quarter 2011 National Fuel Gas Company earnings conference call. My name is Crystal, and I will be your operator for today.(Operator Instructions)Later we will conduct a question-and-answer session. As a reminder, today's conference is being recorded. I would now like to turn the conference over to your host for today, Mr. Timothy Silverstein, Director of Investor Relations. Please proceed sir.

Thank you Crystal, 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 David 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 which they are made, and you may refer to last evening's Earnings Release for a listing of certain specific risk factors. With that, we will begin with Dave Smith.

Thank you, Tim, and good morning to everyone. As you read in last night's release, National Fuel's earnings for the third quarter were $0.56 per share, up nearly 10% from the prior year. Largely on the strength of another outstanding quarter from our E&P segment. Seneca's production grew by 27% over last year, which in turn drove a nearly 20% increase in E&P earnings for the quarter. Net growth in production and in earnings is particularly impressive in light of the sale of Seneca's off shore Gulf of Mexico properties, which closed this past April. Utility earnings remain steady and strong, and earnings in the Pipeline and Storage segment, while down during this year of transformational projects, were in line with our expectations. Over all, we're very pleased with our results for the quarter and for the year-to-date. As you know, over the course of the past several quarters, we set forth a compelling growth story for National Fuel. Looking to the future, as we continue to execute on our plans, we have even greater expectations.

In the pipeline and storage segment, construction is presently under way on our two near term projects. Supply Corporation's Line N Expansion and Empire's, Tioga County Extension. Both are on tract for an in-service date this fall. Combined, these two projects will add $24 million in revenue for fiscal 2012, and will ultimately contribute about $35 million annually, when the contracts underlying the projects, fully ramp up over the next two years. Importantly, both the Line N and Tioga Extension projects are readily expandable and together with Supply Corporation's Northern Access and West-to-East projects, provide continuing opportunities for earnings growth well into the future.

Turning to E&P, our Marcellus Program continues to grow at a very rapid pace. We expect capital spending in the Marcellus will be approximately $580 million this year, and as we move to a 6 rig program between $740 million and $820 million in fiscal 2012. As a result, production will continue to grow rapidly. For the full fiscal year 2011, we expect a 40% increase in production, and looking to next year fiscal 2012, using the midpoint of our guidance we anticipate that production will grow by an additional 35%. Matt will provide an update on Seneca's operations later on the call.

We have the capacity to take advantage of these opportunities. Financially, we're in terrific shape. At June 30, our equity capitalization ratio was 64%, so we're not capital constrained. Our balance sheet is strong, and we can readily accommodate any additional borrowings we incur to grow the Company. And that brings me to an update on a potential joint venture. Our future growth prospects and the fact that we're not capital constrained or up against a schedule of lease expirations, sets a pretty high bar. As a result, while we've been relatively close with two different parties over the last 2 or 3 months, we ultimately chose not to consummate either of those particular transactions. While they were good and serious offers, we determined that they just weren't good enough. And while discussions do continue with a few potential partners, as we said in the past, unless a joint venture enhances shareholder value, unless it produces significant advantages, above and beyond our existing robust plans for growth, which as I said is a pretty high bar, we will simply move forward on our own. At this point, that's the likely outcome.

With or without a JV, our prospects are compelling. We have the resources, financial and human, and the assets to deliver exceptional value to our shareholders for years to come. With that, I'll now turn the call over to Ron.

Thanks, Dave, and good morning, everyone. Operations across all of our subsidiaries are going really well. As Dave mentioned, construction on our Supply Corporation Line N Project and our Empire Tioga Extension project are under way. And even though we had some early delays on Line N due to wet weather in the spring, and a FERC certificate that was later than expected on the Tioga Extension project, both projects are expected to be in service this fall. The increased revenues from those projects will help offset the decline in revenue from turn-back of capacity at our Niagara import point. But what is more important is these projects set the stage for additional expansion capacity on our system down the road. We already have a further expansion project on our Line N fully subscribed, and we have received strong interest in a project that extends our Empire Pipeline further into Pennsylvania.

We continue to be bullish on our pipeline growth opportunities. Between June 2009 and June 2011, Marcellus Gas deliveries into our Legacy Supply Corporation pipelines, increased from a daily average of 1.5 million cubic feet a day to 69 million cubic feet a day. Now, that number does not include Seneca's production in the Eastern Development Area that is currently running at about 100 million cubic feet a day and is flowing through our Midstream's Covington Pipeline and into Tennessee's 300 Line. And as Seneca gears up its drilling on Tract 100 in Lycoming County, our Midstream Company expects to have its Trout Run gathering system completed, so that Seneca's production from Tract 100 will be ready to flow in the first calendar quarter of 2012. For our maintenance capital expenditures and our spending on new capital projects, we're three-quarters of the way through our fiscal year, and spending in all of our segments is on tract with our budget. Now I'll turn it over to Matt for a Seneca update.

Thanks, Ron. Good morning, everyone. Seneca had another good quarter with production of 16.9 Bcfe, up 27% versus last year's third quarter. In California, production was down slightly, however, we are expecting California production to increase over the next several months, as our new wells at South Midway Sunset, begin to respond to steam injection. Also in California, our Sespe Drilling Program is on the third of 6 wells planned for this fiscal year. Two of these wells will be five-acre in-field wells, that if successful, could lead to a bigger program which would add significant reserves over the next several years. Our Marcellus production for the quarter was 10.3 BCF or 61% of our total quarterly production.

At our Covington project in Tioga County, we have drilled all 47 of our planned wells. We are just bringing on an 8-well pad, such that by early next week, we should have 39 wells online, and producing at a combined rate of approximately 120 million cubic feet per day. Another three-well pad has been fraced and should come-on within 2 weeks, while the other remaining wells will be fraced and completed by the end of the fiscal year. Our estimated EUR for the Covington wells is 6.7 BCF per well, or a total of 300 BCF for this area. A few miles to the south of Covington, at DCNR Tract 595, we now have 2 rigs drilling. Tract 595 has 55 total well locations. The gathering system is in place, so that production will come on immediately, as new pads are fraced and completed. This area should provide significant production growth in fiscal 2012.

Our fifth Seneca operated rig arrived on location last month and is drilling at Tract 100 in Lycoming County. You may recall that our first well and Tract I00, IP'd at 15.8 million cubic feet per day. The gathering system for this area should be completed this winter with first production anticipated sometime in the second quarter. We are excited about beginning development of the Tract 100 area. Based on the initial well, we believe this could be a serious Marcellus sweet spot, with wells that produce at very high rates and EUR's that rival the best in the play.

In our Western Development Area we fraced 2 wells at Beechwood that IP'd at a combined rate of 3.1 million cubic feet per day. While we believe we can have better results here with some tweaks to the frac design and landing depth, this will not be a focus area for fiscal 2012. Currently we have a rig drilling at our Mount Jewett Area in Southwest McKean County, another at Boone Mountain in Southern Elk County. We're in the final stages of permitting our Owl's Nest 3D survey and anticipate moving a rig there sometime this fall. Owl's Nest will be a development focus area for the next several years with the potential for 300 to 500 horizontal wells. This fall we will be drilling our second Utica Shale vertical well. The well is planned for Western Venango County which is well west of our Marcellus activity. We plan to do a partial frac of this well, intended to provide data and help us plan for the fracing of future horizontal wells.

Looking forward to fiscal 2012, we're forecasting Company-wide production of 87 BCF to 101 BCF, an increase of 35% over fiscal '11 at the midpoint of the range. At the high end of the range, our production will have doubled in two years, despite the fact that we sold our Gulf of Mexico assets. While we are not yet providing guidance for fiscal 2013, I can say that we expect our rapid growth to continue. We have one of the best overall acreage positions in the world's hottest gas play, and have proven our ability to exploit it. The Utica Shale may provide another outstanding opportunity, while California oil production provides steady cash flow to support our growth. With that, I'll turn it over to Dave Bauer.

Thank you, Matt, and good morning, everyone. As Dave said earlier, the third quarter was another great one for National Fuel. Our consolidated earnings of $0.56 per share were right in-line with our expectations and slightly ahead of consensus estimates. There were no unusual items in the quarter, and between Dave's remarks and yesterday's release, I think we covered all earning's drivers for the quarter, so I won't repeat them again here. As you saw in last night's release, we've increased and tightened our fiscal 2011 earnings guidance to a range of $3.00 to $3.10 per share. The increase reflects our strong third quarter results, our updated production guidance of 68 Bcfe to 71 Bcfe and NYMEX commodity prices of $4.00 for gas and $90.00 for oil. If you back out the $0.37 per share gain on the sale of our investment and landfill gas generation assets, our recurring earnings for fiscal '11 are expected to be in the range of $2.63 to $2.73 per share.

Looking beyond the fourth quarter, we're initiating preliminary fiscal 2012 earnings guidance in the range of $2.85 to $3.15 per share, midpoint to midpoint, a $0.32 per share increase over 2011. The continued growth of Seneca's Marcellus program, combined with the Pipeline and Storage expansion projects that go in service later in the year, will be the primary drivers of increased earnings in fiscal '12.

Now, let's walk through the major assumptions that are baked into our forecast. Starting with E&P, as Matt said, our 2012 guidance assumes Seneca's production will be in the range of 87 to 101 Bcfe, which is up slightly from our original forecast. It also assumes flat NYMEX commodity pricing of $4.50 for gas and $95 a barrel for oil for our unhedged production. Our flat pricing assumptions were set based on NYMEX strip prices at the time we were putting together the forecast. As we've seen this week, commodity prices can be volatile, so as usual, we've included a sensitivity table in yesterday's release, that can be used to estimate the impact of different commodity pricing assumptions on our forecast. From an expense standpoint, as our low cost Marcellus production becomes a larger percentage of the consolidated total, we expect our per unit LOE rate will continue to decline from the $1.03 level we experienced this quarter, to the low $0.90 range that's the midpoint of our 2012 guidance.

G&A expense will increase in nominal dollars as Seneca continues to ramp-up its operations, but with the forecasted increase in production, we're expecting a fairly significant drop in G&A expense on a per unit basis. At the midpoint of our guidance, per unit G&A in fiscal '12, should be about $0.60 per Mcfe, as compared to the $0.70 per Mcfe for the most recent 9 months. Per unit depletion expense is expected to rise slightly from our current level, but that could change based on the timing of our reserve additions, particularly at the end of fiscal 2011. All of the major assumptions that are built into Seneca's forecast are summarized on page 24 of last night's release.

Turning to the regulated businesses, you can expect a fairly significant increase in Pipeline and Storage earnings in fiscal '12. As Dave mentioned earlier, the Line N and Tioga Extension projects will add about $24 million of revenues in 2012. On top of that, the second phase of our Lamont Compression project, and some other smaller projects, will add another $3 million in revenues, making the total impact of our recent expansion projects approximately $27 million. However, the expansion revenues will be partially offset by the continued de-contracting at Niagara, which we estimate will have a $4 million negative impact on 2012 Pipeline and Storage revenues, relative to fiscal '11. In addition, Pipeline and Storage earnings will be negatively impacted by an approximately 2% rise in O&M expense from current levels, driven partly by new costs associated with the expansion projects, and partly by increased spending on greenhouse gas emissions monitoring, pipeline integrity, and other safety initiatives.

Under the terms of our 2006 settlement agreement, Supply Corporation is required to file a rate case proposing new rates to be effective December 1, 2011. Assuming FERC's suspends the filing for 5 months, which is its typical practice, Supply would start collecting new rates, subject to refund, effective May 1, 2012. At this point, we don't expect Supply's rate case will have a material impact on fiscal '12 earnings. Utility segment earnings will likely decline slightly in 2012 for two reasons. The first is weather. Our 2012 forecast assumes normal weather, but as you read in last night's release, colder weather in Pennsylvania contributed $0.03 per share per to earnings for the most recent 9 months. Our forecast assumes this benefit won't recur. The second is O&M expense, which we expect will increase in the area of 2% in fiscal '12. But in spite of that increase, we don't see ourselves needing to file a rate case in either jurisdiction.

In terms of capital spending, our preliminary consolidated budget is in a range of $970 million to $1.1 billion. We're still reviewing the proposed capital budgets of our regulated segments, but I don't expect a significant change to our previously announced level of spending in those segments. A break down of the consolidated total is as follows. $55 million to $60 million in the Utility segment, $100 million to $135 million in the Pipeline and Storage segment, $785 million to $875 million in the E&P segment, and $30 million to $40 million in All Other, which is largely for NFG Midstream's Trout Run gathering project in Lycoming County. Assuming the midpoints of our earnings and spending ranges, I expect capital spending will outpace cash flows in 2012, by a little more than $300 million.

Our next long-term debt maturity is for $150 million this November, and at this point, I expect we'll do a long-term debt issuance within the next month or two, to refinance that maturity. Interest rates are attractive, so we'll likely pre-fund a large chunk of our capital spending as well. In total, you can plan on an issuance in the $400 million to $500 million area. Our balance sheet continues to be in great shape and can handle additional leverage. Our equity-to-cap ratio was 64% at June 30, and should be in that vicinity come the end of the fiscal year. Assuming $300 million to $350 million of incremental borrowings over the next 18 months, I expect our equity-to-cap ratio at September 30, 2012, will be in the high 50s. With that, I'll close and ask the operator to open the line for questions.

(Operator Instructions)

Today's first question comes from the line of Holly Stewart with Howard Weil. Please proceed.

Good morning, gentleman. I guess, Dave, can you start off just by -- with the announcement not to pursue the joint venture -- a very long process, obviously, over the last 9-plus months or so. Can you briefly talk about the process in general, and how ultimately you came to that conclusion?

Well, we didn't come to the conclusion that we're not going to do a joint venture. I think, specifically, we said, it's likely we'll move forward on our own. And this is not a -- it's not black and white. It's more -- you're in a situation here where you're dealing with likelihoods. And through the process, we were fairly comfortable -- while I'm not going to get into any of the specifics, we were fairly -- we had some very good, very serious offers. Evaluations were reasonable. The offers we had were very diverse. I mean, from different -- we had some offers from large integrated oil companies to smaller companies.

But at the end of the day, we kept balancing it against our own plans. And when we look at -- we would look at one of these, and as I said in my comments, we came relatively close twice. We decided not to move forward, in large part because our plans for our own growth were so robust. So I really can't get into any of the details. I know you would like to. I know you would like more color on that, but I really can't get into any of the negotiated details for a variety of reasons, particularly because there is still -- there still are some discussions.

Sure. Absolutely. Matt, can you remind us, then, about the rig count ramp here over the coming year, so we can make sure our models are appropriately -- taking into account your own ramp?

Sure. We've just gone to 5 rigs. We plan to go to 6 in January. Actually we'll probably be briefly at 6 in September, but we're adding a rig and dropping 1 at approximately the same time. Then we'll add the sixth rig in January. I don't think we've disclosed anything beyond that in terms of our rig count. I think it's probably safe to say that we will continue to add rigs as we go forward, but a lot of it depends on gas prices and other factors in terms of exactly when we want to add the next rig.

Okay. And then, another on the Marcellus. I mean, you've given the map of the Marcellus fairway as well as your own acreage; but the Utica has obviously become a pretty hot topic here. Anything outside of this Marcellus fairway that's in your Appalachian portfolio?

I'm not certain that I understand what you're asking.

Anything else in Pennsylvania that you haven't pointed out within that 750,000 net acres?

Oh, I think the vast majority of our Pennsylvania acreage falls within the Marcellus Shale fairway. Perhaps where we're drilling this upcoming Utica, which was kind of Western Venango, that might be on the feather edge of the Marcellus fairway.

Okay. Perfect. Thanks, guys.

Our next question comes from the line of Andrea Sharkey with Gabelli & Company. Please proceed.

Hi. Good morning. So, correct me if I'm wrong, because I might -- but did your CapEx guidance go up for 2012 for the E&P business; but your well count, I believe, stayed the same? So I was just curious what was driving that increase?

Our CapEx has gone up. I guess I'm not certain what well count you're looking at from a past disclosure that has --

I think it was the last -- and maybe I'm looking at it. Maybe it's not the same comparison. Because I think it was 115 to140 ;but that included the EOG joint venture wells. And so maybe --

I know what you're looking at. Yes. You know the biggest change, Andrea, is -- while our gross well counts stayed the same, our net well count actually went up.

Okay.

There were more of the wells in the previous disclosure that we're going to be 50/50 with EOG; and now more of those wells are 100%.

Okay. So are you dropping some 50/50 EOG wells, then?

No. Essentially what happened is, we were going to drill some wells with our rig that were going to be part of the EOG joint venture program. And ultimately, we've decided that we're not going to drill there, we're going to drill elsewhere. So essentially, we replaced some 50% wells with 100% wells.

Okay. And then on the -- I think it was the Beechwood area -- you said you're not going to have as a focus area anymore, because of, I guess, the results from the couple of wells you had. Can you remind us where -- what county that was located in?

Yes. That's in the eastern edge of Elk County.

Okay.

And I guess the way I would characterize that is, we do believe we can get much better results there, as we tweak the frac design and focus on exactly where we want that landing depth to be. But the reality is, we have so many places to choose from. It's just more likely to full further down the priority list; and we'll focus on a place like Owl's Nest, where we have already de-risked it more significantly.

Right. That's fair. And one more question, and then I'll turn it back. On the Utica drilling, any updates on where you stand on that? And do you think that the acreage that you have that is perspective for the Utica, is mainly in the dry gas portion; or do you think you have some exposure to the natural gas liquids area, or the oil area?

Yes. We think it's mostly in the dry gas window. The well that we'll be drilling here fairly soon, is about as far west as our acreage -- current acreage position extends. So it may be an opportunity to see if we have a liquids component there; but honestly I think we're more in the dry gas window.

Okay. Thanks so much.

Our next question comes from the line of Steven Maresca with Morgan Stanley. Please proceed.

Hello. Good morning, everybody. Realizing you can't discuss it too much -- but if you come out saying you're likely not to do a JV, but you're saying you're also in discussions, or discussions are still continuing -- help me reconcile that. Are these more high level discussions? And so what makes you come out and say you're not going to do it, but you're still discussing it?

There is some late entrance. I think is (inaudible). Dave, I don't know if you want to say anything.

Yes. Specifically what we said is, it's likely we're going to move forward on our own. There are a few -- a few parties we're still talking with. But, again, it's a matter of degree. And we just think at this point it's more likely we're going to go on our own than we'll do a joint venture. That doesn't foreclose the possibility of a joint venture as we move forward. I mean, that's specifically why we use the word likely.

Okay. And as a follow-up -- and I appreciate if you can't give any color -- but understanding you have a very high bar, do you think that not getting to an agreement with somebody was more value driven, or more on the size of the acreage?

Well, with respect to the size of the acreage, there were diverse proposals. So it was less that; it was more with respect to what we're able to do without a joint venture, relative to what we're able to do with a joint venture. And your question, evaluation, [is right] characterized it.

Okay. And in terms of your CapEx now, the guidance you gave, that was for '12, the outspend of $300 million. Was that right?

Yes.

Okay. And so, you feel comfortable with the debt issuance of $400 million to $500 million plugging that?

Yes.

Yes. And, Steve, just a little bit more on your question. It's fair to say that some circumstances have changed since the start of this process in terms of gas prices, transaction values, things of that nature. But with respect to our plans, they haven't. I mean, with respect to our plans, we continue to have this robust growth strategy. And so, we haven't changed, with respect to the evaluation of our assets. And so I think that's where -- when we get into the relative discussion, that's what we're talking about. We still have this great growth plan that's precisely what it was when we started this process. And that's what, in large part, we're comparing it against.

Okay. And then finally, I was writing this down -- but you said you fraced in the west acreage and -- was it 3.1 million cubic feet a day? And you said that was not going to be a focus? Can you just give me more clarity? I don't know if I wrote down enough when you were talking there.

It was two wells at Beechwood with a combined IP of 3.1 million.

Okay. Okay. Thanks a lot.

It's not our best wells.

Okay.

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

Good morning, gentleman. I'm hoping not to beat a dead horse, Dave, but you keep mentioning -- or I guess you have mentioned it twice now -- you talked about your plans were more robust than maybe what bidders were thinking? Robust -- is that really more capital, maybe, than people were looking to bring? Or is that more of a plan of you have a better expectation for rate of return for wells? Or how should I interpret that statement?

I guess I'd interpret it to -- and we said right from the beginning, that we do this if it enhances shareholder value. We'd do this if we were comfortable at result, in a better outcome than what we do on our own. And so, as we looked at those few proposals I talked about, we just concluded that with the change in circumstances, things like gas prices and transaction values, we were just better off holding on to that acreage -- not, in effect, selling it -- relative to those transactions, and drilling it on our own and following our own plan.

Was operating a sticking point?

There was -- there were differing proposals. And operational issues were involved with respect to one of the discussions.

Okay. And then switching gears here, because I guess that topic has been covered pretty well -- Matt, getting back to Beechwood, is there any sort of geological differences between that and Owl's Nest? Or do you have anything that you can kind of contribute to why you're seeing differences in well results? And maybe why you picked Beechwood in the first place?

Yes. We're still studying it, Kevin. I don't think I have a definitive answer for you. The thing that's interesting here is, a lot of people look at our acreage and have a tendency to say that Eastern is better and Western is weaker, and it's clearly not that simple. Because Beechwood is about as far east as you can go in our western acreage while Owl's Nest is much further west.

So I think that what we have learned as we've drilled up more of our western acreage, is there will be a lot of variability. It's not necessarily that easy to predict ahead of time; and every time we drill a well, we learn something new. So we're very confident we're going to have a whole lot of very attractive acreage in our Western Development Area. But we're kind of learning as we go.

Okay. Fair enough. And if we assume that there is no JV, does this change your capital plans? In, at least, my understanding, one of the reasons for the JV discussion was trying to bring a lot of that PV value forward and recognize that earlier on in their lives. Do you imagine now increasing CapEx and trying to drill projects, or is it just stay as it goes?

We have kept our capital plans consistent with an assumption that we would not do a JV, from the beginning. Every time we evaluated a specific JV proposal, we modified capital plans for that proposal. But all of our borrowing plans, our capital spending plans, were based on no JV.

Okay. Thank you. Pardon me, thank you very much.

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

Good morning. You guys had talked at one point about possibly disclosing a range of outcomes, in the event you did not do a JV. Any willingness to do that at this point?

No, particularly with us still having some discussions back in [soo].

Okay. And you also have a dormant buy-back program that is authorized. With the market correction in your stock down about 9% today, any thoughts on maybe using some of your CapEx for that? Or do you feel like you would rather put it into your E&P and Midstream businesses?

Well, we would be looking first and foremost, for our spending on the Midstream, and pipeline, and E&P. But, you're right -- with the market the way it is, we will be revisiting that with the Board. But I don't see -- right today, I don't see us reacting immediately to that dip in the stock price.

Okay. And then, finally -- obviously, the whole premise behind the JV was 2 part -- 1 to show a market value; and then, second to be able to accelerate drilling. So now that you're not going to do a JV -- or it looks like it's unlikely at this point -- going beyond 2012, do you try to find a way to get additional capital to increase or further accelerate drilling? Do you look at possibly issuing equity, or are you just happy with trying to live within your means at this point?

Yes. We're not looking at issuing equity. And given the -- and I don't think we've disclosed our five-year plan with respect to CapEx. But we're continuing on a fairly aggressive growth pattern, and can pretty much handle any of those requirements in our existing structure -- our existing capacity. So living within our means, I think, is a good way to put it.

Can I add something to that? If we think about when we decided to go forward with this JV, we were in an environment with a pretty frothy gas shale joint venture market. We weren't driven by a need to raise capital in order to execute our program. We recognized that was one of the benefits of a JV, that we could accelerate it a bit. But we weren't driven by this need for capital. So we still have a very robust program that we can handle within our -- from our own balance sheet going forward, whether we have a joint venture partner or not.

Great. Thank you.

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

Hey, guys. How is it going? A quick question on the G&A guidance for next year -- a little above where it is this year. I thought, given the drilling you're doing on the Marcellus, that would go down a little bit. Can you talk --

Hey, Tim, you're breaking up. You're coming and going. I'm having trouble hearing you.

Can you hear me now?

Oh, yes. Much better. (laughter)

All right. Real question -- the uptick in the DD&A for next year, what is driving that?

Uptick in the DD&A?

Yes.

When you think about how the DD&A rate is calculated, it's based largely on capital [deluxe] -- entirely on capital spending and reserve bookings. We are pretty conservative as we book our reserves. This year a lot of our drilling was developing PUDs at Covington and also drilling wells that were fairly remote to our development plans that don't really allow for significant PUD booking. So it's entirely possible that at year-end we'll book enough reserves; that we'll be lower than that anticipated DD&A, right -- but that's our best guess for now. I do expect that in fiscal 2012, we'll probably have significant reserve bookings. You'll probably see that DD&A rate come down a bit again.

And then, real quick -- on the LOE expense -- directionally it's going down, which makes sense, because your Marcellus production is ticking up. Can you give us what your actual LOE in the Marcellus is, versus out in the west? On a per Mcf and per barrel basis if you have it?

Yes. It's on the order of -- I don't know -- $0.35, $0.40 in the Marcellus versus --

It's a little more than that.

More than that.

$0.50.

Okay. $0.50, maybe average across the Marcellus. While in the west it's -- About $10 a barrel.

Got it. All right. That's it. Thank you.

Our next question comes from the line of Josh Silverstein with Enerecap Partners.

Good morning, guys. Just another thought with not doing the joint venture. I was curious if you guys might look at doing some other sort of asset sale, whether it's just a flat out-acreage sale. Maybe a sale of some of your shallower Devonian production? If that's still something that might be on the table?

No.

Okay. That settles that. And then the exit rate that you guys are talking about in the last press release, of getting up to 240 million cubic feet a day by the end of next year -- can you do that with the existing capacity that you guys you have? I know you were adding another line -- I think, the Trout Run line -- for the end of next year, which is about 300 million cubic feet a day. I was curious if that was needed, to come on-line, for you guys to get to that level, or if you can do it based on the existing capacity.

We need Trout Run. Trout Run will be in place this winter.

Got you. So, will that bring you guys up north of 400 million cubic feet per day?

You mean of capacity?

Right. So I was curious if you have more room to ramp up above the 240 level?

Yes. Trout Run has -- a total capacity of Trout Run, Ron? Do you recall off the top of your head?

350-400.

Yes.

Trout run 466.

466 is the total capacity of Trout Run, and we intend to use probably three-quarters of that, ultimately. We won't hit that level until probably some time in fiscal 2013.

Got you. Okay. I was just curious if you guys had more room to grow into that. Got you. Okay. And then -- I know you were talking about the outspend that you guys would have in 2012. I know you talked a little bit preliminary about 2013, growing your production then. It seems like you would still have an outspend in that year. Then would you have an additional outspend close to the same $300 million level based on the capital spending that you have to do in the E&P business; as opposed to adding some additional capital for the West-to-East line, and potentially the central Tioga Line as well?

Well, we haven't given, really, any sort of guidance on '13, so I guess I don't want to really speculate too much. But I think the thing to keep in mind on the Marcellus Wells, is that they pay out relatively quickly. And when you look at the core business, there is a certain financing cost of ramping up when you're adding a rig, but ultimately that catches up relatively quickly.

Got you. Okay. Thank you, guys.

Our next question comes from the line of John Abbott with Pritchard Capital Partners. Please proceed.

Good morning. Just 1 quick question. With regards to your core Marcellus acreage, could you break that out a little bit? How much of that acreage is in Potter, versus Lycoming, versus eastern Tioga, versus western Tioga? And also, in that area where EOG has been doing a lot of drilling in Clearfield? How much acreage do you have in that area particularly?

A lot of parts to that question. Lycoming -- we have about something on the order of a little less than 10,000 acres, in Lycoming. Tioga County -- we probably have another 12,000 to 15,000 acres. I don't know off the top of my head. That is about evenly split -- no, no -- that is not right. Probably more like 15,000 acres, and maybe 10,000 of that is eastern and 5,000 of that is western. Potter is another 15,000, 20,000 acres.

20.

Clearfield County, where we're partnered with EOG -- that's probably -- that 1 block is on the order of 25,000 acres.

Okay. I appreciate it. Thank you.

And we have a follow-up question from the line of Andrea Sharkey with Gabelli & Company. Please proceed.

Hi, just looking at the market in general, and specifically in the energy business, it looks like a lot of companies have been splitting off or spinning off and doing things like that, to be more focused, and to show better market value -- get better valuations for their companies. Would you give any thought to that? And if you did, in the future, what would maybe prompt you to start thinking about that more seriously? Or how do you view what's been going on from that perspective?

We pretty much have the view we've had all along, and that is, that we like the balance between the regulated companies and the unregulated companies, and what they each bring to the table. And as we've said, as we move down the road -- certainly 3, 4 years out -- if you're 75% or 80% E&P, that may call for a different discussion. But at this point, we really like this model we have, and we are building the Pipeline and Storage business at the same time we're building E&P. But there is no question that 4 or 5 years out with the kind of program that we contemplate in E&P -- yes, it's going to call for a reexamination of that model.

Okay. That was helpful. That's all that I have. Thanks.

And our next question is a follow-up from the line of Mark Barnett with Morningstar. Please proceed.

Not really a follow-up -- I got disconnected a little bit earlier.

That wasn't us, Mark. (laughter)

Yes, I know. Quick question on the -- talking about the sweet spot in Lycoming; and, obviously, from the small amount of data you have, it looks great. What would you [you are here] estimating what their -- that you would say, they are up there with the best? I'm just curious, as to what (inaudible).

Well, we've been assuming something on the order of an 8 Bcf EUR there. When we get a few more wells, and a few more well tests, I think it's entirely possible that will go up.

And then as your -- I guess this is kind of a piggyback on an earlier question around CapEx -- but as you're developing that area and Owl's Nest through next year, what are your projections for well cost? And do you think there is going to be shift, either up or down, from where you're operating today?

Yes. Well cost is so heavily dependent on lateral length and number of frac stages. Really on number of frac stages. But frac stages to some degree are dependent on lateral length. So our experience is that we're wanting to do 15-plus stages per well, and that is driving our well cost above $6 million. I don't anticipate that dropping dramatically in the near term. However, we're already seeing significant efficiencies in our drilling and completing of the wells with our multi-well pads.

So, ultimately I do see those costs coming down. A lot of it is also dependent on service company costs. We have contracted a company to do completions for us at a better cost per stage than we had been running, so that is going to help. And we're looking at our entire supply chain to see what else we can do to reduce those costs. It's only a matter of time. I think we, as well as everyone else in the industry, is going to be able to drive these costs down.

And we have no further questions. I would like to hand the call back to Mr. Silverstein for closing remarks.

Thank you, Crystal.

We would like to thank everyone for taking the time to be with us today. A replay of this call will be available at approximately 2.00 PM eastern time, on both our website and by telephone, and will run through the close of business on Friday, August 12, 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 46229014.

This concludes our conference call for today. Thank you, and goodbye.

Ladies and gentlemen, that concludes today's presentation. Thank you so much for your participation. You may now disconnect and have a great day.