National Fuel Gas Co (NFG) 2010 Q3 法說會逐字稿

Good day, ladies and gentlemen and welcome to the third quarter 2010 National Fuel Gas Company earnings conference call. My name is Stephanie, and I'll be your Operator for today. At this time, all participants are in a listen-only mode. Later we will be facilitating a question-and-answer session.

(Operator Instructions)

I would now like to turn the conference over to your host for today, Mr. Timothy Silverstein, Director of Investor Relations. You may proceed.

Thank you, Stephanie, 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 list of certain specific risk factors. With that, we will begin with Dave Smith.

Thank you, Tim, and good morning to everyone.

The third quarter was another very good quarter for National Fuel, not only with respect to our financial results, but as importantly with respect to our continued progress on our plans for growth. Overall, earnings for the quarter at $0.51 per share were solid and in line with our expectations. Our Utility business, as advertised, continues to provide a stable and predictable earnings base. Our Energy Marketing business continues to provide a significant contribution, frankly, often beyond our expectations, despite little capital investment and the influx of more marketers, and thus more competition.

Our Pipeline and Storage segment continues to make terrific progress on a number of transformational projects that ultimately will move Marcellus gas to growing markets on the East Coast and into Canada. And while the strong basis prices at Niagara and Chippewa are currently putting pressure on our pipeline earnings, which as most of you know historically have been largely generated by north to south transportation, that short-term challenge should prove to be a long-term opportunity; as we transform our system so that gas, especially Marcellus gas, can be delivered into Canada.

Our E&P segment continues to ramp up its Marcellus activity, and we're very pleased with the results we've seen to date. As you can see in last night's release, Appalachian production for the quarter was more than double that of the prior year.

Given the running room provided by our vast acreage position, particularly in the Marcellus, and given our financial strength and capacity, we expect this rapid growth at Seneca to continue well into the future. We're currently operating three horizontal rigs in the Marcellus, and expect to double that to six rigs by the end of fiscal 2011. Matt will provide more color on Seneca's results, and on our plans to continue to accelerate development of the Marcellus.

Shifting for just a moment to our smaller operations, as I've said on prior calls, we're actively pursuing the sale of our smaller non-core businesses. To that end, in July we entered into an agreement to sell our Marienville saw mill operations, and some associated timber acreage, on which we will retain the mineral rights. Cash proceeds from the sale will be approximately $15 million, and we don't expect either a gain or loss on the transaction. We intend to maintain a scaled-down forestry operation, but after this transaction we will no longer be in what I call the retail or processing side of the timber business. We expect the transaction will close by the end of this fiscal year.

We also continue to pursue the sale of our landfill gas related operations, and are making some progress on that front. As I said in the past, we won't sell it at a fire sale price, but ultimately it is likely to be sold. We'll keep you up-to-date as things develop.

Before closing, I want to briefly mention the four major promotions we announced in June. Ron Tanski, as most of you know, was elevated to President and Chief Operating Officer. Over the course of his 31-year career with National Fuel, Ron, who holds an MBA, but he's also a lawyer, has held senior management positions in each of our major segments; at one time or another he was President of the Utility, also President of the Supply Corporation. Most of you know Ron, as I said, and also know that he is unquestionably the right person for that role. In his previous position, Ron wore two hats, serving as both President of Supply and the Principal Financial Officer of the Parent Company.

Succeeding Ron as President of Supply Corporation is John Pustulka. John, who has Engineering and MBA degrees, has spent his entire 35-year career in our interstate pipeline business. He knows our system inside and out. He knows our Pipeline and Storage customers, and he's a recognized leader in the industry. I have every confidence in his ability to get the job done.

Dave Bauer, who you'll hear from later on the call, assumed Ron's CFO responsibilities. Dave is a CPA, who has a long history with National Fuel. Prior to joining us in 2001, Dave was a senior manager in PriceWaterhouseCoopers energy practice, and served on National Fuel's account for ten years. In the nine years he's been with us, Dave has worked closely with Ron, and at one time or another has overseen most every aspect of our accounting and finance functions. Like Ron, Dave is a conservative, straight-shooting kind of guy, and I fully expect his transition into the CFO role will be seamless.

We're also pleased to elevate Matt Cabell to Senior Vice President of the Parent Company and, of course, Matt will remain as President of Seneca. And, Matt, as you might expect, is a Geologist. He also holds an MBA degree. In addition to recognizing Matt's accomplishments and improving Seneca's performance and Seneca's prospects, this appointment reflects the growing importance of E&P to the overall Company.

Right now National Fuel is in a very good place. We have great assets, a great business model, great employees, and a strong management team ready, willing and able to execute on our plans for growth, our aggressive plans. I'm excited about our future, and I'm confident we will continue to deliver exceptional value to our shareholders. With that, I'll turn the call over to Ron.

Thanks, Dave, and good morning, everyone.

From an operating point of view, things are going well across the entire system. We're on target with our maintenance capital expenditures for the year, and field operations are going well in each of our Utility, Pipeline and Storage, and Exploration and Production segments.

Regarding Exploration and Production, there are numerous articles each week in the trade press and newspapers about concerns surrounding the BP well in the Gulf of Mexico, or hydraulic fracturing in the shale formations. We believe that our welling -- our well drilling and completion activities are safe, and we've had no major issues with any of our operated properties. We're fully aware of the backlash that can result from any environmental accident, and we're committed to being responsible stewards of our natural resources and the environment.

Even before the Marcellus well completion procedure regulations were enacted in Pennsylvania, our completion procedures had met those standards. We're proud of our environmental record in the Exploration and Production segment, and also in the Utility, and Pipeline and Storage segments, and expect to maintain that performance.

As we pointed out in the earnings release, transportation revenues are down a bit year-over-year in the Pipeline and Storage segment for the quarter and nine-month periods. We've received a number of notices from shippers that have turned back firm transportation capacity on our system. Historically, those customers used that capacity to receive gas from Canada at the Niagara River, and flow it through our system to other delivery points. For those shippers, the gas that is now available from Canada at the Niagara River is simply more expensive than supplies available at other market points. So they gave us notice that they would not renew their contracts at the end of their terms.

For fiscal year 2011, we expect that the full impact of those reductions will result in a net decrease of about $4.5 million in transportation revenues for the segment. We already have notice of additional turn backs in capacity that would further reduce revenue by another $6 million in fiscal 2012. However, that total $10.5 million decrease in revenues from all of that turned back capacity will be more than offset in fiscal 2012 by a pick-up in volumes and revenues from our Line N Expansion Project, and the beginning of flows of our Northern Access Project and the Tioga Extension Project. Because of necessary FERC filings and construction schedules, we won't see the offsetting impact of these expansion projects until 2012, so there will be a minor decrease in Pipeline and Storage earnings next year. But for the longer term, we're really, really bullish on this segment.

By 2013, we expect that the increase in revenue from our expansion projects, and the transportation of gas into Canada from our system, will far outweigh the loss in revenues from the turned back capacity. We submitted our FERC filing for the Line N Expansion Project in June, and our FERC filing for the Tioga Extension will be submitted later this month. Both projects are expected to begin flowing gas in early fiscal 2012.

One project that has slowed a bit is our West to East Project. Producers are taking a wait and see attitude with respect to commodity prices and alternative pipeline routes, before committing to ten-year contracts for capacity on this project. As a result, we're pushing back the proposed in-service date from 2012 to 2013. However, as more and more Marcellus wells get drilled in the vicinity of our pipeline footprint, we're convinced that this pipeline will have to be built in order to provide an outlet for the new Marcellus production. We are continuing with our preliminary engineering and survey work for the project, while our marketing folks keep busy meeting with potential shippers.

And now Matt has the Seneca update.

Thanks, Ron. Good morning, everyone. I'll start with production, and then discuss our Marcellus activity, and finish up with our expectations for fiscal 2011.

Overall production for the quarter was 13.3 Bcfe, up 15% versus last year's third quarter. West Division production was essentially flat versus last year at 4.9 Bcfe. Gulf was down 19% at 3.6 Bcfe, while East was up 115% versus last year at 4.8 Bcfe. Absent a significant hurricane shut-in or other unanticipated event, we expect to finish the year with annual production of approximately 50 Bcfe, which would amount to a production increase of 17% versus last year.

Moving on to our Marcellus activity, for the past few months we've been operating two horizontal rigs in Tioga County. We have drilled 19 wells and completed seven. Five wells are currently producing approximately 25 million cubic feet per day, while the other two completed wells are shut-in for offsetting frac jobs. Over the next two months, we will be fracking 12 wells on two pads, and bringing those wells online. I expect to have the first two of -- the first of those two pads, a seven-well group, completed and online in September, allowing us to meet or exceed our goal of 40 million to 70 million cubic feet per day from the Marcellus by the fiscal year end.

The productivity of our Tioga County wells continues to exceed our estimates. Our last five wells averaged over eight million cubic feet per day for their first 30 days of production, and our best well has now produced over 1.3 Bcf in only six months. Also of note, six of our seven Tioga County wells have shown production declines that are flatter than the type curves. In other words, not only are these wells coming on at high rates, they're maintaining these rates longer than expected.

Over the past several months, we have come a long way in de-risking our western Pennsylvania acreage. We have now tested four wells west of the EOG Joint Venture. One in McKean County, one in Forest and two in Elk. IP rates for these wells averaged from 1.4 million a day to 3.9 million a day, with the weakest well being the shortest lateral. We are also seeing a difference in production rate, depending on the depth at which we land the lateral. Ultimately, based on the data gathered to date, we believe that we can achieve average IP rates of over three million cubic feet per day in most of these new areas by using longer laterals and better seismic data to land our laterals in the ideal zone.

With these new well results, we have de-risked our acreage enough to justify a significant revision to our estimated resource potential. We now estimate net risked potential of eight to 15 Tcf across our entire Marcellus position. To arrive at this estimate, we use a variety of risk factors and EUR estimates for different portions of our acreage. At the midpoint of this resource range, or 11.5 Tcf, our assumptions would be an average EUR of 3 Bcf and a 52% risk factor. As we drill in new areas, optimize our drilling and completion techniques, and accumulate more production history, we will continue to evaluate and possibly revise this resource estimate.

We expect to have our fourth horizontal rig on location in September. We will then have three horizontal rigs active in Tioga, Potter, Lycoming area, and one drilling on our western acreage. We plan to add a fifth rig in May, and a sixth horizontal rig in September of 2011. In addition, we will top hole some locations with a smaller rig. For fiscal 2011, we are planning 60 to 80 Seneca-operated horizontal wells and about 40 EOG-operated wells.

Regarding our expectations for fiscal 2011, we anticipate annual production of 60 to 70 Bcfe, or 20% to 40% over our expected fiscal 2010 production. The growth will come entirely from the Marcellus, with annual Marcellus production estimated at 25 to 30 Bcf, or about four times our annual Marcellus production for fiscal 2010.

Looking beyond 2011, we will be converting our eight to 15 Tcf of resource potential into proven reserves with an aggressive but disciplined development plan. Production will continue to grow rapidly as we develop our extraordinary Marcellus Shale opportunity.

And with that, I'll turn it over to Dave Bauer.

Thank you, Matt, and good morning, everyone.

Overall, the third quarter was a good one for National Fuel. As Dave said, our consolidated earnings of $0.51 per share were in line with our expectations, and right on top of consensus estimates. All of the major earnings drivers for the quarter are covered in yesterday's release, so I won't repeat them again here. Instead, I'll focus on our expectations for the fourth quarter and fiscal 2011.

Fourth quarter earnings are expected to be in the range of $0.33 to $0.43 per diluted share. When you add the $2.27 of earnings for the first nine months of the year, our earnings for all of fiscal 2010 are expected to be in the range of $2.60 and $2.70 per share. This guidance includes fourth quarter production volumes of approximately 13 Bcfe, and incorporates about nine days of contingencies for possible hurricane-related shut-ins of our Gulf of Mexico production.

Looking forward to fiscal 2011, our preliminary estimate for consolidated earnings is in the range of $2.60 and $2.90 per diluted share. Now, these are preliminary numbers that may change as we refine our assumptions across the segments. As we said in last night's release, that guidance assumes Seneca's production will be in the range of 60 to 70 Bcfe. It also assumes flat NYMEX commodity pricing of $5 per MMBtu for gas, and $80 per barrel for oil on our unhedged production.

Our flat pricing assumptions were set based on NYMEX strip prices in place at the time we were putting together the forecast. Our gas assumption appears in line with yesterday's strip, but our oil assumption is a bit more conservative than today's market. As we all know, 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 2011 forecast. The other major assumptions that are built into Seneca's forecast are detailed on page 24 of last night's release, and they are all pretty straightforward.

On the regulated side of our business, there are a few factors you should take into account when evaluating our fiscal 2011 earnings guidance. The first is project development costs associated with our Pipeline and Storage expansion efforts. We take a conservative approach to these costs, and generally expense them as incurred, until it's highly probable that the project will be built.

In fiscal 2011, we expect to expense approximately $7 million or roughly $0.05 per share of development costs related to the West to East and Northern Access projects. Our results for the nine months ended June 30th include a little less than $0.01 per share of development costs. So, therefore, we expect fiscal 2011 Pipeline and Storage earnings will decrease by a little more than $0.04 per share because of these costs. Again, this is a conservative approach to our forecast. When the development work leads to successful projects, and we fully expect they will, we will reverse the entire amount of any development costs that have been expensed.

One further point on project development costs. Through the quarter ended March 31, 2010, we have been expensing development costs related to Empire's Tioga Extension and Supply's Line N Projects. During this past quarter, we determined it was highly probable that both projects would be built, so we reversed the expenses we had previously recorded, and will now capitalize ongoing costs associated with the two projects. Because most of the costs that were reversed in the third quarter had been incurred during the first six months of the fiscal year, project development costs had very little net impact on our nine-month results. As I said, just under $0.01 per share.

As Ron mentioned earlier, decontracting at Niagara will continue to weigh on the Pipeline and Storage segment's earnings. Based on contract termination notices received to date, we're expecting a net decrease in Pipeline and Storage revenues that will impact fiscal 2011 earnings by about $0.03 per share. To reiterate Ron's earlier points, we see this as a temporary phenomenon; as our expansion projects begin to come online in the latter part of 2011, we expect this trend to reverse.

Lastly, we're forecasting about a 2% to 3% increase in operation and maintenance expense in our regulated segments. Higher pension expense and pipeline integrity management costs are the principal drivers. In spite of these increases, the returns on our regulated businesses are high enough that we don't see ourselves filing a rate case in fiscal 2011 in any of our jurisdictions.

In terms of our capital spending for 2011, we're still reviewing the proposed capital budgets of our regulated segments and, therefore, except for the updated E&P capital forecast included in last night's release, we won't be updating projected capital spending by segment on this call. However, other than a $100 million reduction in Pipeline and Storage CapEx related to the delay in the West to East Project that Ron mentioned earlier, we don't expect a significant change to our previously announced overall level of projected 2011 spending.

From a cash flow perspective, using the middle of our earnings guidance range, and assuming about $665 million of capital spending, we expect to be cash flow negative in fiscal 2011 by a little more than $200 million, which is being driven by our E&P spending and the construction of the Line N and Tioga Extension Projects. Add to that the maturity in November 2010 of $200 million of long-term debt, and we project a total cash need of a little more than $400 million. Most of that will be met with cash from our balance sheet. As of yesterday, we had about $400 million of cash on hand. The remainder, at least initially, will be financed using short-term debt.

We continue to maintain ample sources of liquidity, including $420 million of bilateral lines of credit with our relationship banks, and a $300 million commercial paper program backed by a like-sized committed credit facility. Our existing committed facility expires at the end of September, but earlier this week we had a very successful marketing of a new three-year $300 million facility. We expect to execute the credit agreement next week.

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

Thank you.

(Operator Instructions)

Your first question comes from the line of Jonathan Lefebvre with Wells Fargo. You may proceed.

Thanks. Good morning, guys. Just -- I don't know if you saw this or had a chance to hear, but EOG mentioned on their call this morning that they're considering selling some acreage in their Bradford County. I know you guys have a substantial acreage position, but would this be something that you would consider looking at?

Jonathan, yes, that would certainly be within an area that we would see as highly prospective. So I would certainly say that we would have an interest in it. I think the tough thing would be how competitive would it be, are there players in Bradford County who see this as such a natural fit to their existing efforts that they would be willing to pay a price that's more than we would pay, so a long way of saying, yes, we would be interested, but I wouldn't count on us picking it up.

Okay. Thanks. And then in terms of the Marcellus, obviously very nice numbers this quarter. Just was wondering if the EOG well blowout had any impact on the results? It seemed like it was a little below where we had estimated. But I know there is a lot of timing in there with when you bring wells online?

Yes. I don't think there is any significant impact due to the EOG operational issue for the previous quarter, or really even for the future because it was a pretty minor delay for them. Really the bigger impact to our production timing has more to do with when we bring on the multi-well pads. We're just starting a seven-well frack, and then we have another five-well frack coming up within the next month or two. And so really all of the drilling we've done since about May in Tioga County is -- none of that's online, -- it will all come online within the next two months.

Okay. Great. And then a very nice resource update, very impressive numbers. I know you gave us kind of the average EUR. Can you maybe break out for us what you have in the different areas, or maybe give us a little more granularity around your EURs and spacing, and some of those assumptions, West versus East?

I guess I can give you a little bit, Jonathan. We're assuming 100-acre spacing across all of it. And just keep in mind, in a particular area if you had a longer lateral you would maybe develop more acreage with fewer wells, so you would have a spacing that might be 120-acre or 160-acre. However, each of those wells will recover more per well.

So anyway, the assumption here is 100-acre spacing. The range in our western acreage tends to be in the sort of 2 to 3 Bcf; in the EOG Joint Venture it tends to be 2.5 Bcf to 3.5 Bcf; and in the Eastern acreage it tends to be, say, 4 Bcf to 6 Bcf. That's our current estimate of averages across those areas. Those are all subject to change in the future.

Right. Okay. And then -- I appreciate that. And then just finally on the well costs, still seeing wells in the $3.5 million in the $4 million range? Are you seeing any pressures on the costs?

I would say that the $3.5 million to $4 million range is kind of our expectation in the long-term, as we drill -- as we develop areas with multi-well pads. Our history is higher than that $4 million number, and a lot of that has to do with moving rigs between pad locations.

Right.

We are seeing some pressure on the completion side, in particular. Pressure pumping services are not only getting a little bit more expensive, they're also -- you really need to schedule them well in advance just to get them when you want them. That's probably the biggest point of pressure.

Rig rates are a little higher, but I think we're -- the newer rigs that we're contracting may be a little bit more expensive, but a little bit more capable as well.

Okay. And any type of efficiency gains that you can talk about as you move to more pad drilling? Have you been seeing days to drill, come down?

I don't have specific numbers for you, Jonathan. But, yes, I do expect those efficiency gains.

Great. I appreciate it. I'll hop back in the queue.

Your next question comes from the line of Carl Kirst with National Fuel (sic). You may proceed.

Carl Kirst with BMO, guys.

Hey, Carl, we haven't hired you.

I know. I don't know where to send my resume. Just -- Jonathan hit some of my questions, maybe just to continue drilling along a little bit, and Matt, just from a then and now, if you will, obviously very impressive numbers from the resource standpoint. You mentioned the 52% kind of average risk factor that you're using today. Can you refresh my memory of what -- the risk factor you guys were originally using a year ago? And I just wanted to clarify, of the delta that has now come, is primarily most or all of this coming from the de-risking of the western flank or has some of this also come from Tioga as

Yes. It's all of the above. The risk factor, previously, I think the bracket was 30% or 40%. So the low end was 30%, the high end was 40%. EUR -- average EUR is higher and the EUR change really comes from all of the areas. Tioga County, what did I say a minute ago, sort of the 4 Bcf to 6 Bcf range. I think we were closer to 4 Bcf before. Frankly, even 4 Bcf to 6 Bcf may be conservative over there.

Right.

All of the areas we've probably upped the EURs at least slightly. But I'm not -- I can't say that for sure because I don't have all of the data from the past estimate before. But certainly, several of the areas we've increased the expected EUR.

All of that said, I think the risk factor is the biggest impact on the overall estimate.

Okay. I appreciate the color. And two other quick follow-ups, if I could. Is there -- I know it's smaller -- going to be a much smaller bucket here at this point, but could grow much more meaningfully in the next 12, 24 months. Is there any sense around Tioga and the four wells that we have in the Western flank, what perhaps an actual probable and possible might be at this point?

No. Frankly, Carl, I'm not sure how meaningful probable and possible reserves are in these resource plays. As we go forward with the new SEC guidelines, we're going to have -- in areas where we have a lot of well control and production history, we're going to tend to book several offsets to existing horizontals as PUDs. Where you draw the line between PUDs and probables, possibles and resource potential, it's I think it's somewhat subjective. And I'm sure Netherland Sewell has a specific methodology, but honestly I think it's pretty subjective.

Okay. I appreciate that. And then just last question, obviously we kind of continue to see more parties buying into the Marcellus, and there has always been sort of this intent, I think, to drill, see what we have, before, perhaps engaging in those conversations at least in any material way. How do you kind of feel about that now, with sort of the larger resource potential, or are we sort of closer to perhaps engaging in that kind of conversation, or is it more still let's wait to have the cash need, if you will, before going down that route?

Yes. This is Dave. We're certainly talking about this on a relatively frequent basis, because there is a great interest and people are approaching us on a regular basis. So this is something that we talk about, and certainly we look at different opportunities to accelerate our plans in the Marcellus.

But as I've said before, we're in a pretty good position right now, and we certainly don't have to drill to hold our leases the way many others do. That said, we certainly are willing to consider opportunities. We're certainly talking about them. But they would have to be pretty compelling, because we like the game we're in now and we really don't need a game changer. To the extent that we decide to fully explore a joint venture, we would certainly keep you up-to-date.

All right. Thanks, guys.

Your next question comes from the line of with Faisel Khan with Citigroup. You may proceed.

Good morning. It's Faisel.

Good morning, Faisel.

How are you doing?

Good.

Good.

Okay. A question I think you mentioned in your prepared remarks, Matt, the lateral lengths within the JV, those were kind of a direct -- those were part of the function in terms of how the IP rates were? Is that kind of a linear function in terms of how the wells are coming online versus lateral length, or is it more the depth issue that you were talking about earlier? If you could elaborate on that, that would be great.

Faisel, just to be clear, I was referring to the wells that were outside of the joint venture.

Okay.

Further to the west of the joint venture. But the lateral length versus IP rate is the same issue everywhere that we've drilled, both in the joint venture and outside. And it's pretty close to a linear function between lateral length and IP on wells that -- everything else being equal.

Now, the other thing that has to be equal, though, of course, is did we land the lateral in the same place. So we're still learning how much the landing target impacts the IP rate, and frankly it varies depending on where you are. There's some areas where the shale is maybe a bit more homogeneous in a vertical sense, so that where you land it doesn't make as much difference. And there's other areas where it's more, I don't know, stratified, and landing it in the ideal zone makes a bigger impact. Does that help?

Yes, definitely. So do you have -- have you done seismic already for any of these areas, or is this something you have to go out and acquire?

We have seismic data everywhere that we've drilled a well to date. Very difficult to drill these horizontal wells and land them in the right place without any seismic data. Now, that said, there are areas where we just have kind of a loose grid of 2D, and there are other areas where we have 3D seismic. We have acquired and are continuing to acquire 3D in the areas that we're most actively developing, or in some cases, a tightly-spaced 2D survey.

Okay, got you. And then just on the guidance for next year, the DD&A for E&P seems to be kind of flattish compared to where we are right now. I would have thought that maybe as you guys are producing more and as you book more reserves out of the Marcellus, that that depletion rate would actually come down?

That's a good question, Faisel. I think as we get further along in the development of the Marcellus, we will see that DD&A rate fall. But a lot of it depends on the timing of the capital spending versus the booking of the proved undeveloped reserves. Dave, I don't know if you have any additional comments.

Okay. And just on the hedging strategy going forward, how are you guys looking at layering on any more hedges on the gas side or the oil side of the equation? Is it going to be opportunistic or will it be kind of more systematic?

Faisel, this is Dave Bauer. We take a pretty systematic approach to layering our hedges, and I would expect us to continue to do that. We're -- using the 65 Bcf number for 2011, we're at about 45% area hedged right now. And we would likely -- we like to come into a year in the 50% range, so we may be adding some in the coming quarter.

Okay. Got you. And then just last question, on the turned back capacity on the pipelines, I think in your prepared remarks you talked about some of the projects that you have coming online will offset all that turned back capacity. I think I missed it, which -- is it the Line N expansion and Northern Access that will completely offset those revenues, or was there something else that I was missing?

Basically those, Faisel. But if you wanted a kind of more detailed look, if you looked at the second quarter update presentation that we have on the web, on the website.

Yes.

If you look at those projects on page 67, you've got -- the main ones are the ones already kind of offsetting are the Lamont Compressor Station Project, and then Line N, Tioga Extension and Northern Access. So it's the four of those, let's say.

And that would basically get you kind of either to where you are today in terms of EBIT, or a little bit higher?

Well, we didn't want to start going through EBIT calculations for each of these projects, because that's going to be your next logical question. Let's say -- if you take all those projects and you sum up the capital expenditures that we have estimated there on that page 67, you're looking at $136 million of spending. And once all that -- once they're all flowing, the volumes that we have contracted for or that we have precedent agreements for, you're looking at a pick up of $51 million in revenue, and that will offset, say, the $10.5 million that I talked about in the prepared remarks of turned back over fiscal 2011 and 2012.

Got you. Okay. That's helpful. Thank you very much.

(Operator Instructions)

Your next question comes from the line of Ray Deacon with Pritchard Capital Partners. You may proceed.

Yes. Matt. I was just wondering if you could elaborate a little bit on the size of the drilling inventory you laid out, and where you think the economic break even is for the Western acreage, the EOG JV, and the Eastern acreage?

Ray, just to make sure I'm understanding your question, are you asking how many wells in each of those areas I spelled out in the resource estimate?

Well, or, no, I guess just more generally. I assume -- at a $5 forward curve, most or all of the Eastern acreage is going to have a pretty good rate of return. But how much of the Western and the EOG JV acreage is going to look attractive to develop at a $5 gas price, say?

Actually I guess I kind of like the way you asked that, with the $5 gas price, when I refer to that 52% risk factor, I would think of that as 52% of our acreage will ultimately be developed if we're looking at a $5 gas price. Obviously at a higher gas price, that risk factor would increase and vice versa.

Okay.

Now are you wanting that by area? Is that what you're asking?

No. That's great. That's perfect. And I guess just, Dave, one more question to ask you to elaborate. You didn't feel to need to do anything kind of Company-altering, and I guess I've just been looking over the last couple of months. It seems like the prices for Midstream and Pipeline assets have really escalated significantly, and just was curious if you ever -- what would make that seem like an attractive market to sell assets into or spin off the Pipeline segment, I guess?

Well, you know, I don't think I said we didn't really feel the need to do anything, I think what I'm intending to convey is the notion that we're very much aware of everything that's happening in evaluations with respect to all of the acreage in the Midstream and the Pipeline and Storage segment out there, and we talk about it on a regular basis. Ron, Matt and I, at least once a week we look at those various kinds of opportunities.

So I don't think I want to -- for example, with respect to a joint venture in the Marcellus, I don't think I want to throw what I would regard as a compelling opportunity out there in terms of a number, but certainly the message I intend to convey is a message that we're certainly willing to look at it if in the long run it adds value for our shareholders. And we do have those kinds of opportunities that present themselves.

So we are looking at it. We are thinking about it. We are studying it. And if we have what I'll call a compelling opportunity, without giving you a number, we will certainly pursue it.

Got it. Great. Thanks, Dave.

(Operator Instructions)

At this time, there are no further questions. I would now like to turn the conference over to Mr. Timothy Silverstein with any closing remarks. You may proceed.

Thank you, Stephanie.

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 p.m. eastern time on both our website and by telephone, and will run through the close of business on Friday, August 13th, 2010. 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 passcode 88538993.

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 now disconnect, and have a great day.