National Fuel Gas Co (NFG) 2007 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Q1 2007 National Fuel Gas Company earnings conference call. My name is Mike and I will be your operator today. At this time, all participants are in a listen-only mode. We will facilitate a question-and-answer session at the end of the presentation. (OPERATOR INSTRUCTIONS)

As a reminder, ladies and gentlemen, this conference is being recorded for replay purposes. I would now like to turn the presentation over to your host for today's call, Margaret Suto, Director of Investor Relations. Ma'am, over to you.

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

Also, since this call is being publicly broadcast, we remind you that today's teleconference discussion will contain forward-looking statements as defined by the Private Securities Litigation Reform Act of 1995. 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 Phil Ackerman.

Good morning, and welcome to the first quarter of our fiscal 2007. I doubt that many people were surprised by our earnings for the quarter. Obviously, warm, wet weather impacted the weather-sensitive segments of our business, while increasing production and the expiration of some low-priced hedges helped our Exploration and Production results. But generally, we were in line with our guidance.

What is more noteworthy is that recent days, weeks and months have seen significantly rising prices for National Fuel Gas stock on increasing volumes. Our recent price of $41 per share has exceeded the expectation of many of the utility-oriented analysts who have traditionally followed our stock.

While we are proud of the strength of the balance sheet and enthused about our prospects for growth in Pipeline and Storage, I think it is clear that this recent market activity is driven by a spreading recognition of the size of our Appalachian acreage position and how tremendously valuable it may ultimately prove to be.

National Fuel has operated gas wells in northwestern Pennsylvania for more than 100 years, and during that time, various combinations of discoveries, new technologies and rising prices have spawned a series of booms which have created large fortunes, starting of course with John D. Rockefeller. We may very possibly be at the early stages of another of those eras. Clearly we have high prices, and advances in tracking techniques have enabled the production of large volumes of gas from shale formations in other parts of the country.

Appalachia presents us a complex series of opportunities and challenges, both for production from various sands and shales and for gathering and processing. We've been increasing our focus on and activities in Appalachia for a number of years, but it has become clear that this area is worthy of an even greater effort. What we have here is an extremely valuable asset, and we will be developing a comprehensive game plan to maximize its value for our shareholders in the days, weeks, months and years to come.

Both Dave and Matt, our new head of Exploration and Production, will have more to say about this. But first, Ron has a few words of explanation about a couple of items. Ron?

Thanks, Phil, and good morning, everyone. Last evening's earnings release is pretty straightforward, and I don't think there's any need to repeat anything that we already pointed out there. But as Phil said, I do want to give a little more explanation of two items that we talked about in the release.

The first has to do with the $1.9 million gain we recorded in the Pipeline and Storage segment. Back in 2003, when we acquired the Empire State Pipeline, there was some floating rate project debt that came along with the Pipeline as part of the purchase. The credit agreement covering that debt, signed by the original owners, required Empire to put an interest rate collar in place. That collar had a ceiling of 9 3/8% and a floor of 5.15%.

When we acquired the Pipeline in 2003, three-month LIBOR rates were in the range of 2%, or 315 basis points below the 5.15% floor of the collar, and the collar had a value of approximately $5 million to the counterparty. As a result, we were required to book approximately $5 million as a liability on our opening balance sheet. That liability was being amortized over the remaining life of the loan that had repayments scheduled to be completed in February of 2009.

But as interest rates rose, our liability on the collar decreased and gains were recorded in other comprehensive income. When we paid off that debt in December, hedge accounting rules required us to mark that collar to market and immediately recognize the gain that had accumulated in other comprehensive income on the balance sheet. The accounting entry to do that resulted in the gain during the quarter, which we used as an offset to long-term interest expense. And that is why you see a large decrease in the year-over-year long-term interest expense line. We consider this a special item that did not arise from our operating activities.

And the second item I want to talk about has to do with the depreciation, depletion and amortization in our Exploration and Production segment. Our preliminary forecast and the guidance that we had given to analysts regarding the DD&A rate had that rate at approximately $2 per Mcf equivalent. After going through a complete analysis of the dollars includable in the depletable base and refining certain of the assumptions regarding the future development costs for our unproved properties, the actual number came in lower. You can see on page 17 of the release that the actual DD&A expense for the first quarter was approximately $1.83 per Mcfe. For the remainder of the year, we are using an approximate rate of $1.90 per Mcfe in our earnings guidance.

With that DD&A rate change as the primary factor and some additional operating and maintenance expense savings that we're working on, we've increased our earnings guidance for the year to a range of $2.15 to $2.35 per share. Remember, however, that the range is still subject to the sensitivity set out on page 20 of the release regarding our unhedged production.

Matt will go over the details of our hedge positions in a few minutes, but I will point out that we've been increasing our hedge positions as commodity prices have risen and we have been able to find a creditworthy counterparty to hedge our California oil production. That solves the basis risk issue that we've talked about previously and we will be moving in the direction of getting 2/3 to 3/4 of our future production hedged.

Before I turn it over to Dave, I'll just note that we filed a request for a rate increase in our New York utility jurisdiction last week. We put out a separate release on January 29th with more details on the case. You can refer to the News and Headlines section of our website for that release. Since New York rate proceedings usually take 11 months to process, there would be no earnings impact from that case until fiscal 2008.

Now I will turn it over to Dave Smith.

Thank you, Ron, and good morning to everyone. Given the weather-related challenges that Phil mentioned, the first quarter was a good one for National Fuel and I'm pleased with our results. Though earnings were down slightly from the prior year's quarter, mostly due to lower efficiency gas revenues and warmer weather, overall our results were in line with our expectations.

As Ron indicated, last evening's release provided significant detail on our financial results, but I won't dwell on that here. Instead, I will focus on operational developments at our subsidiaries. The past year has been a busy one for the rate departments within the regulated companies of National Fuel. On November 30, 2006, the Pennsylvania PUC approved the settlement agreement our utility reached last fall with the parties to our rate case. Under that settlement, new rates designed to increase revenues by $14.3 million were placed into affect on January 1, 2007.

With the Pennsylvania case behind us, we are now focusing our attention on the New York division, where, as Ron indicated, we recently filed a request to increase our rates by $52 million. One element of the case I'd like to touch on for a moment is the conservation incentive program that was included in the filing. Under that program, the Company will commit $12 million to promote conservation among our customers. The decoupling component provides that the delivery rate charged by the utility would be adjusted, based on throughput, in order for the Company to recover its operating margins. Customers benefit by the savings on the commodity itself, which, as you know, is the largest component of the customer's bill. And the Company benefits by avoiding future rate increases associated with declining usage per account. The win-win nature of this kind of program has been recognized by many commissions throughout the country and we are optimistic that the New York Public Service Commission will agree.

Turning to the supply corporation, last quarter we announced we had reached a settlement in the complaint proceeding brought by the New York PSC, the Pennsylvania PUC and the Pennsylvania OCA. That settlement, which was supported by all the parties who brought the complaint and by other active parties as well, was certified by a FERC ALJ in late December and is currently awaiting a final approval from the commission. Since the settlement was uncontested and no negative comments were filed, we have every reason to believe that FERC will approve the settlement in the very near future.

It leaves our base rates unchanged, and yet still preserves an opportunity to operate efficiently enough to generate efficiency gas and realize a good portion of that revenue, revenue that has allowed us to maintain, as opposed to increase, base rates for the last 11 years.

The five-year stay-out provision of the settlement preserves our potential to benefit from enhanced Transportation and Storage opportunities, which we have prioritized and are presently pursuing. Just as importantly, the settlement provides for the full recovery of the existing OPEB regulatory asset over the next five years, adjusts our ongoing OPEB expense to a more current level, and provides the security of continued OPEB deferral accounting treatment into the future.

Given the risks inherent in any litigation, we are satisfied with the terms of the settlement. And by the way, the settlement will be effective on December 1 of 2006 and that has been taken into account in guidance.

The Empire connector remains on schedule for a November 2008 in-service day. We reached a significant milestone on December 21st when FERC issued a certificate to construct the project, which we are happy to accept. And it's my understanding that Millennium Partners likewise accepted their certificates. From a regulatory approval standpoint, all that remains are two environmental permits, both of which we expect to receive within the next couple of months.

While we are not at this time changing our estimate of the total capital costs of the project, which we put at $152 million, we are aware that contractor labor costs appear to be increasing. Thus, it is possible that the ultimate cost of completing this project could be as much as 10% to 20% higher than our estimate. As a result, we've redoubled our efforts to control construction costs and are considering a combination of competitive bidding and partnering arrangements with contractors. We are also applying for sales tax exemptions and property tax abatements. Other pipeline companies, including Millennium, have recently received similar tax accommodations, and we believe we will have similar success.

Operationally, things are going well with the project. Over the next few months, we will be busy negotiating pipe and construction contracts and acquiring rights of way. By April, we hope to have all necessary permits and favorable decisions on our sales and property tax proposals. We will then execute our firm service agreement with KeySpan, which will commit us to build these facilities. As I said, we expect construction to begin in August of 2007 for an in-service day of November 1, 2008.

In the timber segment, the weather during the first quarter created poor harvesting conditions. When it's wet and muddy like it was during the quarter, it's very difficult, if not impossible, to get logging equipment into the forest. As a result, our harvesting activity for the quarter fell short of our expectations and a low inventory of saw logs resulted in our mills being shut down for a period of two weeks. We are hopeful the recent cold weather will enable us to resume normal log sales while increasing inventory.

Switching gears now to the E&P segment, Matt Cabell, our new President of Seneca, has been on board for close to two months and has been busy getting his arms around our E&P operations. He will provide an update of Seneca's activities in all of the areas we presently operate.

Before I turn it over to Matt, let me comment on what I see as one of the most significant and promising assets in our system, the almost 1 million acres we control in Appalachia. It is no secret that we have been emphasizing our drilling operations in western Pennsylvania. Drilling in the shallow sandstones has increased from approximately 40 wells three years ago to over 150 wells last year, to hopefully over 200 wells this year. Additionally, as you know, we have started to explore our shale potential -- a portion, up to 200,000 acres of almost 800,000 shale acres, of which is dedicated to our agreement with EOG.

To move our efforts to the next level, we have decided to retain a consultant to help us assess our Appalachian reserves. Basically, the consultant will provide an estimate of the potential that this extraordinary resource provides. Matt will provide you with more details on these efforts.

On a final note, given this increased activity in the Appalachian Basin, not only by Seneca but by other producers as well, we are also exploring the potential to develop a midstream, likely unregulated company that would focus on transporting and processing what we believe will be an ever-increasing volume of production out of Appalachia.

With that, I'll turn the presentation over to Matt for an update of Seneca's activities.

Thanks, Dave. To continue on a theme started by Phil and Dave, I will start with our East division. We believe we have an excellent leasehold position in Appalachia, and this will be an area of increasing focus for us now and in the future. As Dave mentioned, we're going to initiate a comprehensive regional study of our Appalachian potential, which will include an outside estimate of both proven and unproven reserves. We have several proposals for this outside work and expect to kick off the study later this month.

Following the study, I expect that we will be prepared to provide shareholders with an indication of our unproven reserves, but due to competitive issues, we may limit what we release. However, please understand that this consulting work will only be a starting point for what we need to do in Appalachia.

While we have some talented and knowledgeable people working in the area, we will need to dedicate additional resources and make regional work a high priority. Ultimately, we expect to have a long-term exploration and development plan that includes an estimate of resource potential and a multi-year drilling and production forecast under various pricing scenarios. This plan will be regularly modified based on our drilling results.

For now, though, the East is the smallest of our four divisions in terms of daily production. We produced 1.6 Bcfe in the first quarter, which is 18.5% more than the same period last year, primarily due to the success of last year's drilling program.

As Phil mentioned, our 2007 program is a bit behind schedule due to soggy ground conditions resulting from warm, wet weather. It shouldn't be a problem anymore. However, we still expect to meet our fiscal 2007 goal of 200 wells in Appalachia.

Regarding our joint venture with EOG to explore the Devonian Shale, the agreements have been signed and the work has begun. We expect the first well to be drilled in March and four to six wells to be drilled in fiscal 2007. Under the agreement, EOG will drill 10 wells in 2007 and 2008. Two of them will be horizontal. Ultimately, they can earn 50% working interest in up to 200,000 acres of our total 900,000, and this will be restricted to the shale interval.

In the Gulf of Mexico, production for the quarter was 3.9 Bcfe versus 2.3 Bcfe for the same period last year. This increase is primarily due to the effects of Hurricane Rita on last year's production. One field remains shut in, Vermillion 225, with plans to complete repair work on a third-party platform sometime this spring and bring that production back on.

We are currently drilling a wildcat well at Ship Shoal 79, which we operate with a 55% working interest, and we expect to spud an offset to last year's Highland 24L discovery, operated by Walters. That will be later this month.

In the West, we produced 750,000 Boe, or the equivalent of 4.5 Bcf, which is about as expected for the quarter. We've drilled 20 development wells in the Midway-Sunset field, and in South Lost Hills we'd added three producing wells on the Citrus lease, which we acquired last April, thus adding about 300 barrels of oil per day.

In Canada, we produced 2.1 Bcfe as compared to 2.4 a year ago. This production drop was both due to natural decline and to some operational delays. Additionally, we had some reduced flow at our Sukunka 93D well due to a downhole problem that has subsequently been fixed.

Moving on to hedging, for the remainder of fiscal 2007, we can summarize it as follows. We have 540,000 barrels hedged with swaps at an average price of $37.86. We also have 135,000 barrels of oil collars at a floor of $70 and a ceiling of $77. All together, that is 25% of our remaining 2007 oil production.

For gas, we have 4.5 Bcf hedged with swaps at 7.32 per Mcf and 4.1 Bcf of collars, with a $7.93 floor and a $17.22 ceiling, such that 41% of our remaining 2007 gas is hedged. For 2008, we've hedged 225,000 barrels of oil at $51.80 and 5.1 Bcf gas at $8.31, plus another 1.4 Bcf of collars, with a floor of $8.83 and a ceiling of $16.45.

So to summarize our E&P, our production for the fiscal first quarter was 12.0 Bcfe, 8% higher than production for the same quarter a year ago. This is primarily due to the downtime last year from hurricanes. We expect similar production for the second quarter and still anticipate a full-year volume of 47 to 52 Bcfe. We've hedged approximately 35% of our remaining production for fiscal '07 and have been increasing our hedge position for fiscal '08.

Lastly and perhaps most importantly, our East division will become an increasing area of focus. We will engage an outside firm to estimate our unproven resource potential, and we will develop a long-term development plan. We're very excited about this opportunity to grow in Appalachia over the next several years, both in the shallow Devonian and in the underlying Devonian Shale.

Operator, I guess we are ready for questions now.

(OPERATOR INSTRUCTIONS) Mike Heim with AG Edwards.

I think just about all my questions were answered, but I didn't hear any comments on strategic review of the Canadian E&P. Is there any progress on that? And if not, is there any kind of guideline you can give us on when that might be complete?

It's still something we're giving some consideration to. Again, I've been here a little less than two months. I need a little bit more time to get my arms around those assets, and I will be working with Dave and Phil and Ron to determine our path forward.

I don't mean to press you, but do you see this as a 2007 type of event?

Yes.

Thank you. That is the only questions I had left.

(OPERATOR INSTRUCTIONS) Jim Harmon with Lehman Brothers.

Good morning. With the physical hedge issue solved on the West Coast, how far out are you able to hedge volumes? Is it year by year or is it multiple years?

In terms of the liquidity going out past 2008, Jim, it obviously gets a little bit thinner. But I don't have the actual quotes or the volumes that the counterparty is willing to go at my fingertips. But like we always do every quarter, we will give you an update as to where we stand.

Okay. No -- and that is appreciated. And as far as resolving your ability to hedge Canadian production, I guess there are two thoughts that come to my mind. One, would you seek to find a counterparty if you are actually conducting some sort of strategic review?

That is exactly the point. As part of our review of what we're doing up there, we can't go too much farther out and get prices locked in. But it is something that -- again, hedging is of a concern to everybody in terms of certainty, and we are looking at everything, trying to get back up to our overall 2/3 to 3/4 of future production hedged. Obviously, that would need to include a portion of Canada.

Okay. Move to the Gulf. The disclosures in the annual report intimated that you were looking at contracting additional rigs given the price declines. And I was curious whether or not that would either impact the current program with either lower costs or imply that you may be in the Gulf a little bit longer than we had anticipated, and it would be a little bit more than an opportunistic program, since you are generating fairly good results out of that region today.

I think perhaps the answer is neither, Jim. We intend to stay in the Gulf as long as we're able to find economic prospects. With rig rates coming down, perhaps we will be able to find more economic prospects than we would have been able to find with higher rig rates. But I don't really know how long you were anticipating that we were going to be in the Gulf. I still see it as an opportunistic situation.

Phil, do you have a price deck that you'd ascribe to that opportunistic endeavor?

Well, it varies from time to time, yes. But we review each prospects on its own, in light of the prices, both for rigs and for the gas or oil, at the time of the review.

Okay. And I guess the last question on Appalachia. Did we assume that we will see a two-piece/three-piece scenario at some future date? Or will that be one of the items that may not be disclosed?

Well, we recognize that in general we have an obligation to keep the shareholders informed as to what we are doing, and in particular with respect to Appalachia, as we spend more time and resources in this area that may be unfamiliar to some of them. But at the same time, we don't think it is in shareholders' best interest to reveal proprietary data that may give us a competitive advantage at the time, whatever the time is. So we're going to look at that on a situational basis.

Certainly a lot of our peers are giving out 3P data; we recognize that that is the common industry practice. We don't know for sure yet what our study is going to show, and if we think there is some advantage to be gained by -- an advantage to the shareholder by keeping that tight for a while, we will do that. It's a common industry practice not to reveal the results of particular wells for some period of time, until you can lease up acreage or own discoveries. It may turn out that there is some tactical or strategic reason to keep that 3P data tight for a while.

Okay, and I guess the two last questions would be on the hedge for West Coast. Is that private equity or is it just a general corporation? And then -- I guess I only had one question.

I mean, we do not want to give out commercials regarding all our counterparties, but it is a substantial, creditworthy counterparty, Jim.

Okay. Thank you very much.

Shneur Gershuni with UBS Securities.

Good morning, guys. Most of my questions also were answered, but I did have three quick questions. With the expectation of exploiting the Appalachian asset and testing it and so forth, could we not expect that you might be interested in expanding the midstream infrastructure for the Appalachian assets? Given that flow rates will be much different from a deeper shale play and so forth, could we see, I guess, some sort of pipeline infrastructure put in place over the next couple of years or so?

Absolutely. Perhaps it got glossed over in both my remarks and Dave's, but both Dave and I mentioned that, that we are also looking at the midstream opportunities in Appalachia.

Speaking of the midstream opportunities and so forth, do you believe that there are any storage opportunities as well too that you could be exploring, assuming Rockies Express terminates within your region and so forth?

Absolutely. That too. One of the things that we need to do -- and we've talked about over the years -- we need to get Millennium built in order to give us an outlet to the markets. Having a bunch of gas come from the Rockies, whether it is on Rockies Express or some other project, doesn't do much good unless there is some ability to get the gas from eastern Ohio or Western Pennsylvania into a larger market area.

So we need to get Millennium built first to give us an outlet for additional volumes. Whether those volumes come from the Rockies Express or from an expansion of Cove Point, wherever. But as Dave said, we are optimistic that Millennium is going to afford and we certainly are looking at incremental storage opportunities.

Yes, we're looking both on our system, enhancing our existing storages, but also there are three or four opportunities that we're actively pursuing for storage in the Central New York area, let's say that. So, yes, we are very aware of it. We've prioritized it. It's part of what we are really looking to grow in the relatively short-term, and we are very actively pursuing it now.

I guess that sort of rolls into my next question. Given the amount of CapEx that will be involved on a pipeline midstream and storage expansion, would that interfere at all with your ability to increase the dividend above the general percentage increase that we've seen over the past couple of years? You have reduced your share counts on a year-over-year basis and so forth, providing I guess more distributable cash flow to shareholders. Is it possible that we could see a larger dividend increase or would some of the CapEx interfere with that opportunity?

We think we have plenty of capital resources. We haven't really given any kind of an indication about a possible change in dividend policy. But we don't see anything happening yet that is going to cause us to be particularly capital constrained or cash constrained.

Okay. That actually answers the balance of my questions. Thank you very much.

Robert Gendelman with ClearBridge Advisors.

Good morning, everybody. I guess first with a question -- somewhat of a follow-up of the last question, and then with a very brief comment. Have you -- or do have any plans to change your capital budget for the year given this very significant, by your own words, opportunity set in Appalachia?

And then as sort of a follow-on commentary to that, we have been kind of less than thrilled with the return profile of the capital that has been spent by this Company over the last five years. We can talk about the Canadian assets, the Empire purchase. We understand that sometimes weather doesn't cooperate and other things that are beyond the Company's control.

But we're really very concerned that this asset will be given the capital that is required to make it return the appropriate profile to shareholders. And we are just wondering why you continue to pursue opportunities, particularly in Canada and even in the Gulf, as the question earlier was raised, when we all believe and competitors of years who are immediately adjacent to your properties believe that the opportunity set in the Appalachians is so great.

So the question really is capital, how it is determined that capital gets spent, and what we should expect, as shareholders of the Company, to be a reasonable return profile for the capital that is being spent? Thank you so much.

You certainly said a mouthful there. To start with, the first item that I wrote down here, I don't think we will have the opportunity to spend significantly more money in Appalachia in fiscal 2007 than what we budgeted. We are already somewhat behind in that regard because of the constraints imposed by all the mud and miserable conditions out there in the first quarter. So we are going to be encouraging our people very strongly to catch up for the amount that we fell behind in the first quarter.

To accelerate beyond the pace that we will need in order to catch up is probably impossible, so I don't think we will be able to spend significantly more money in Appalachia in fiscal 2007 than the amount we had budgeted.

With respect to pursuing activities in other areas, as we've indicated, Canada is under review. And what I want to be particularly careful with there is not throwing the baby out with the bathwater, to use an old expression. And I do think the results we've had up in the Monkman area with those Sukunka wells indicate that that is a baby, even if some of the other parts of our Canadian experience may be viewed as bathwater.

In the Gulf of Mexico, we have had a very successful program in the shallow waters of the Gulf of Mexico. And I want to emphasize again the shallow waters of the Gulf. The pricing structure is completely different there in terms of costs as compared to the deeper waters. And by utilizing 3-D seismic, bright spots, AVO and so on, we've had historically better than an 80% success ratio in that area. And I think our returns have been quite satisfactory.

I kind of lost track of what the other parts of your question were there.

Phil, I appreciate those comments. But the fact is that there has been 600 million odd dollars spent in E&P over the last five years, and with very little return after write-offs to show for it. The earning stream of the Company is essentially unchanged over that same period. And so it raises the question of is the capital being spent appropriately.

There is no doubt that what some of the money that we spent and some of the E&P efforts, and particularly in Canada, would better have not been spent. There is no way to get around that. We see that; we realize that. I think all we can do is tell you what we plan to do going forward. And what we plan to do going forward first is have this comprehensive review of Appalachia, and we see that as a potential shining star. And we are going to look at all aspects of that, as we followed on with the earlier questions from Shneur about looking at midstream, looking at storage, looking at all aspects of Appalachia, in addition to exploration and production.

And we're going to focus our other CapEx in the E&P area on those activities that historically have been successful for us, and not spend money in those areas that have not been successful. The best we can promise you is to learn from our mistakes. I can't deny that mistakes were made.

Bob, one thing you mentioned that I don't think was a mistake. We recognized we were paying a dear price for the Empire line when we bought it. But it was certainly a strategic acquisition for us, right through the middle of our service territory. And at the time, we anticipated the potential to expand Empire,. and I think now that is coming to pass.

Well, at the time when we bought it certainly -- we acquired it in the tax-free exchange so we had -- or tax-deferred exchange, as all the accounts look at me. We had an advantage in that regard. But also for us, that was a long-range acquisition. We recognized it at the time and it's now going to fit it nicely with our whole, overall Pipeline and Storage development. So we recognized the return wasn't terrific in the first three or four or five years, but I think now we are looking at seeing the upside of that.

Should I get back in the queue guys, or is it appropriate to ask another question?

Ask another question.

Speaking of the Pipeline and Storage division, companies talked about, and I think thoughtfully, about the appropriate capital structure for that entity, if indeed it should be in a separate entity. Can you basically update us on your current thinking on that line of thought?

You thinking of an MLP or --?

An MLP -- or -- yes, exactly.

You know, we've looked at the structure in the past and we certainly are not prepared to say we are looking at moving to that structure at this time.

Can you maybe just help us to understand why that might be -- ostensibly it seems like a pretty good idea, but I don't claim to be anywhere near an expert on that.

For one thing, I believe there are still significant rate issues associated with the MLPs. At least the last time I looked at it, there were. But --

And with the settlement of the case brought by the PUC and the PSC, we've got a five-year settlement with respect to those rates. So it is really -- our historical past looks at this issue, Robert, had to do with coming up with a new tariff schedule once the properties got moved to an MLP type entity, to take into account the tax savings or the tax changes brought about by that reorganization. So the earliest we could even possibly see that would be five years from now.

Okay. And I guess lastly, can you help us to understand if the details of the EOG joint venture will be made public? There are a lot of open issues in regards to that.

What other details are you looking for?

Well, for example, I mean we know broadly speaking that they have sort of a call option on 50% or 100,000 acres. Do they have the choice of any of the acreage? In general, we would just love to see in an 8-K the details of that. And according to them, they are not opposed to putting that out publicly either at this point. So I'm just curious as to why that hasn't occurred. Maybe I'm missing something.

Well, it's a drill-to-earn deal. They have to drill to earn the acreage, and they can earn up to 100,000 acres, which is 50% of 200,000 over time, as they drill those wells -- and it is strictly in the shale interval. I'm not sure if I would characterize it as simply a call option on all of our acreage.

The hundred thousand can be on -- of the 200,000 or of any of the acreage in the shale?

The 100,000 is a net acreage position that represents 50% of 200,000 acres. Those are acres that they would have to earn by drilling -- up their drilling obligation.

So, again --

They have the choice of where to drill, which we viewed as being advantageous because we want to utilize their expertise in selecting locations.

Right. So can we expect to see some filing that details all these issues?

I'm not sure what we gain by making the filing. We've made the --

I'm still not sure what detail you are missing.

Bob, you have different information than we have. Certainly, we've had an indication that with regard to any specific geographic information, EOG is very concerned about the release of that kind of detailed information. So I think generally, to outline the general parameters of the deal is appropriate. To get into the details of where they're going to earn acreage and where they are drilling, certainly we do not foresee a filing of that nature.

Okay. Are you willing to say who the consultant was that was hired to explore the East Coast opportunity?

We've -- as I said in my comments, we've accepted proposals from several firms and we have not engaged a specific firm yet.

And then once engaged, you will tell us who that is?

Yes.

Great. Thanks a lot, guys.

Rebecca Followill with Howard Weil.

Good morning. A bunch of questions for you. On this review of the Appalachian area, why now, given that you've had the acreage for a long time -- can you tell us more about what you hope to get out of it? What is the timing to develop a plan? What kind of capital you would put into it? And I can just spout all these off and we can go through and back review them.

Are you willing to -- the percentage of E&P of the Company has been gradually increasing. Are you willing to take that significantly higher? And if you do so, what happens to your debt levels, what happens to payout ratios, what happens to your dividend policy, etc.? That is just a start.

Well, almost -- kind of start in the middle of your question, Becca. Where we wind up going with this kind of depends on where the opportunities lead us. Some other people have been making some pretty heroic projections about what Appalachia can amount to. And that is one of the principal reasons why we are undertaking a total review of the opportunity at this point in time. And that total review includes not only the exploration and production activity, but also the midstream potential for that area -- gathering, processing, storage, you name it.

So it is hard to say at this point where that study will lead to. If it turns out that there are significant incremental profits to be made in the exploration and production activity in that area, yes, we will pursue them. If that means that our mix of business changes significantly for some period of time, so be it. Does that mean we change our payout ratios or change our debt equity ratios? We will take that as it comes.

I think one of the things that many people see is that a lot of the Appalachian exploration and production opportunities perhaps are less risky than some people think of other exploration and production activities, and therefore they may not be as concerned about leverage or things like that in connection with an Appalachian program.

It's going to be overly simplistic, but we are just here to make money. If it turns out there is money to be made in Appalachia, we want to make it. And we will take it one step at a time.

If I can just add to debt. Your question why now? It is something that needs to be done. Yes, maybe we could have done more sooner, but I think maybe one thing that is not completely clear here is we have done some substantial regional work in Appalachia already. There is a lot more we can do.

This third-party study will give us a starting point for some specific unproven reserve numbers. But whether we could have done more before or not really isn't relevant; it is still an important thing for us to do now.

In this study, in the scope of it, are you also looking to get (indiscernible) unproven numbers, the economics behind it, a proposed schedule for drilling -- or is it just more of a reserve analysis? What is the full scope of the study?

The scope of this study will be to evaluate the unproven reserves, the external study. Internally, we will be developing a long-range plan that includes multi-year drilling and production forecasts. And those, of course, are dependent on pricing. So as prices rise, we may be able to justify a bigger program than if prices fall. And of course, it all depends on the success of that future drilling as well.

So you'd first get the outside study and then develop your plan from there? Or are you kind of moving in tandem?

I think it would be fair to say that we will be doing a lot of this kind of simultaneously. But the results of the study are going to help drive it.

And what is the timing for completion of those parts?

The external study should be completed within fiscal 2007.

And the budgeting part, the long-range plan is also an '07 item?

Yes, but I guess I would say that it's -- this is something that is going to be constantly modified and evaluated as we drill additional wells, particularly in those areas of less dense well control.

Okay. And then on the midstream side of the business -- and I think, Phil, you answered this question, but I just want to make sure -- in developing that business line to complement accelerated drilling in the Appalachian area, any idea of the magnitude of capital spending or would that come out of this study?

It would come out of a combination of the external study and our internal study. The potential for the midstream part of the business is not only the acceleration of our own drilling, but what we would expect to be the acceleration of other people's drilling as well.

We're obviously not the exclusive holder of acreage in Appalachia. We have to consider what the potential is from other people's acreage as we start to contemplate gathering and processing facilities.

I guess I would add there's also a limit to how fast you can spend capital drilling in Appalachia. It is not like --

It's nickels and dimes.

-- kicking off a big development project in the Deepwater Gulf of Mexico.

Right. Just trying to get an idea of magnitude. And then last question for you, Matt, again big picture. And they've been keeping you under wraps so we haven't had a chance to ask you these questions.

This has been -- the E&P business at NFG has been -- production has been declining the last few years, F&D costs have been fairly high. How do you view this business differently at this point? And what are the metrics that you're going to be using to -- that your performance is gauged on? Is it reserves, is it production, is it operating cost, is it return on capital employed? What are you targeting for the Company?

Yes, it is all of those things. Rebecca, I guess what I would say is we certainly recognize that our finding and development costs have been subpar for the last several years. So I would say that a focus of mine is going to be improving those finding and development costs going forward.

But are there any specific metrics that you are tied to?

Yes, pretty much everything you mentioned.

Is there one that is weighted more heavily than others?

Dave?

Actually, I think finding and development costs and reserve replacement are more heavily weighted.

I think they are one and two, Rebecca.

Okay, thank you so much for your time.

Peter Hark with Talon Capital.

Yes. Good morning. Just a quick couple of follow-ups to Bob and Becca's line of questioning, and to make sure I understand the economics of the EOG JV.

First, I thought they were bringing like 130,000 acres to the table in combination with the 770 that Seneca is bringing. So I thought -- first of all, the starting point I thought was 900,000 acres and EOG was bringing 130.

That is correct.

Okay. So the 100,000 that you are using as a base, or in the EOG JV, that allows the drilling of 200,000 acres, right, between the two of you? Is that correct?

Actually, that is -- within the structure of the JV, they can earn a 50% interest in 200,000 of our acres. We can earn a 50% interest in any of their 130,000 acres.

I got you. I got you. Great. And does the JV -- after -- or if you can display some success here, does it extend to the remaining acreage? In other words, do they then have an opportunity or a call, as Bob called it, to then conduct drilling in the remaining acreage at similar economics?

No.

Okay. And then -- I know it is simple math again, but where did the other 100,000 acres come from. I had 130 plus 770 for Seneca. I don't know if that is right.

As we talked about 1 million?

Yes -- you're just rounding.

Okay. There are other holdings of ours that are not considered to be prospective for the shale.

Okay, Phil. I got you.

(multiple speakers) side of the shale JV.

Got you. Thanks. At this point, do you have an opportunity to kind of categorize these shales? I know Range and Equitable are drilling in the Devonian Marcellus Shale in Pennsylvania, which is deeper and heavily pressured. Is that similar in nature to the acreage you guys have or is it more like the shallow, underpressured shales?

We have the Devonian Shales.

It is similar. I don't want to go a whole lot further without divulging something that I might feel is competitive.

Okay, fair enough. And then what are the expectations on F&D costs relative to what you are experiencing now? Are F&D cost multiples of what they are currently to drill these shale plays, or can you kind of go over some of -- just basic, the economics of that?

Wait a minute. I think it is fair to say that at this point we have no idea. We have yet to drill the first of these shale wells with EOG.

Okay, Phil. Great, thanks. And just jumping back on more mundane is on the share repurchase program. I guess you kind of make disclosure here that the guidance you've revised here today does not include any additional share repurchases under the authorization.

And first, just trying to understand your thinking in terms of executing on that. Because it seems here you have a much better economic opportunity in putting dollars into Appalachia than perhaps buying back additional shares at this point. I'm just trying to get an understanding of why you would want to go out and buy another 3.7 million shares of stock under the authorization when you have better opportunities?

We haven't talked about our plans going forward with respect to share repurchase -- ever. I think we said in the beginning that we would tell people how many shares we had repurchased in the periods that have passed, but not talked about our repurchasing strategies going forward.

I will say that the counterargument to your point about having good opportunities to deploy the capital and drilling in Appalachia is that there may be an undervaluation still by the market of the opportunities that we have in Appalachia and that may be a good opportunity to repurchase the shares at this price. I'm not saying which way we are going to go.

Okay, fair enough. And then just lastly on the potential opportunities -- I guess it was touched on. But to the extent that you get through this evaluation process and kind of move forward with some of the drilling, what infrastructure will you guys be looking at to help get this gas to market? I know there will probably be additional pipeline and storage opportunities. Can you kind of lay out then what you might be looking at to kind of continue the growth prospects going forward?

I mean, just generally, you'd be looking at gathering systems, processing and whether or not that interfaces with the pipeline and storage, the regulated component. But for us, I mean it is a great opportunity, not only for all of Appalachia and all the producers. But it's an opportunity for Seneca; it's an opportunity for the gathering company, the midstream gathering and processing company we are talking about. But also to the extent we move this gas on our regulated supply company pipeline and move it off-system, there is an incremental opportunity for us.

So it is a good opportunity all the way around for the system, and it would be -- certainly the gathering and processing would likely be unregulated. And so that is what we would be looking at, though, in its pieces.

Right. I guess also I'm just trying to get a better handle on the timing of all that. Because while you might display significant reserve potential, bringing that gas to market may take a few years of infrastructure development to kind of get it there. So the earlier it can get going on that, the better.

We are presently the plans forward now. And you are right, it's not something that you'd have in the ground tomorrow. It is a year to two-year proposition. And even moving out, it is a longer-term proposition just seeing a very immediate impact from this kind of a gathering system.

Right. One last thing on the third party study, when you do the evaluation. Will it just be on the 200,000 acres or will you extrapolate or extend that to the other acreage and kind of come up with 2P and 3P across all the acreage potential?

It is largely focused on the upper Devonian sands. It is really not a shale study. That 200,000 acres is a portion of our position that EOG can earn in at the shale horizon. This third-party study is our entire Appalachian --.

Got you. Okay, perfect. Thanks.

Sarah (indiscernible) with Millennium Partners.

It's actually Mark Russo. I just wanted to get a follow-up, to make sure I understand correctly. This Eastern review that you guys are doing, when it is all said and done, there is a chance we may not get an update or you may delay when shareholders get an update. Did I hear that correctly?

That is right. We are going to look to see what it is that we have, what they come up with, and make a determination as to whether or not there is a competitive advantage that we can take advantage of by keeping that tight for a while.

I guess the way to think about it is to the extent that there is a disadvantage, we'd be uncomfortable in disclosing that. And I think the specific question, if my recollection that Phil was answering was the disclosure of [E2] and P3. And to the extent that there was a disadvantage in disclosing that, we'd obviously have to consider that.

But at the same time, we recognize shareholders' interest in having as much information as they can get about this area.

So does that mean that there is a chance that we won't get any meaningful update in '07, meaning the company will have an update internally, but shareholders may not hear anything until next year because it could be a competitive advantage?

I wouldn't say any meaningful information -- that is probably too broad a characterization. You will get an update on what we are doing with our study; no question about that. I think the specific question that Phil was answering was the P2 and the P3.

Okay. And then depending on what this review determines, will you look to monetize other regions? Given that there is tremendous reserve potential in the eastern region, would you look to monetize the other regions, since they haven't had great returns on capital?

We might monetize other regions if we have reason to think that we need the capital to fully take advantage of Appalachia. We consider all the time selling various assets and look at the kinds of prices other people seem to be getting for things. We may be driven to sell something or we may not. We will certainly consider it if it seems appropriate.

And as far as permitting goes, do you guys have enough permits in hand to do what you propose to do. And if the review, again, has a lot of potential, when would you start going out for permits?

We are going out for permits (multiple speakers).

You mean permitting well locations?

We are constantly permitting well locations to meet our drilling plans going forward. This study, of course, though, the intent is for it to some degree -- both the external study and what we do internally will guide us in where we go in the future. But it is well ahead of the permitting process.

Got you. And then on the F&D front, I guess what are the things to think about? Is it just technology as far as driving the costs down that is available now versus what was available in prior years?

No, no, no. A couple different things. When we were talking about getting costs down, I think we were talking specifically about rig rates in the Gulf of Mexico were easing up a little bit. In general, in terms of F&D costs, we're looking at not making as many mistakes, would be one way to put it.

And drill wells that find more reserves.

Okay, thank you.

Faisal Khan with Citigroup.

Good morning. On the two horizontal wells, I guess the total of 10 wells you've described in terms of drilling, what are the target depths of the -- I guess the 10 wells or the two horizontal wells and the eight other wells, if I'm reading it right.

That is not something we are ready to disclose yet. But you are right -- it is two horizontal wells and eight vertical.

Okay -- two horizontal and --

That is the requirement of the joint venture.

Okay. And then looking at your current gathering and processing and transportation rates out of the basin, what does it cost you right now to gather, process and transport the gas out of the basin?

A couple of things. One, a lot of the gas doesn't leave the basins. A fair amount of the gas is consumed here by local end users.

Yes, actually, I think the vast majority of that is the case.

Okay. How much would it cost to actually gather and process it?

That is precisely what we're looking at right now. Our existing system -- I mean, there is a number of very old systems out there. I'm not sure we could look at that as forming an appropriate basis for what it will cost us moving forward and developing and gathering.

Okay. When you consider your current vertical well program of call it between 100 to 200 wells a year, do you look at that program as sustainable over along period of time, meaning you have a lot of drilling locations to be able to do that over the next five to ten years?

Yes, dependent on prices and dependent on our additional regional --.

And then in terms of how long would it take -- assuming that you had all the capital you needed, how long would it take for you to get ramped up to kind of a 500 well a year program? Is that a possibility with those vertical wells you currently drill to the -- I think it is the Bradford shale?

It is the Bradford; they're tight sands actually.

Tight sand -- sorry.

I guess maybe that is part of what we are still evaluating, is how quickly can we ramp up. But I hate to throw out numbers of how many wells we will drill per year until we have done all of our work.

That gets to be a lot more complicated then because of the limitations on gathering and processing. There is no point in drilling wells without the infrastructure to take the gas away, which is why we need to look on a comprehensive basis at our acreage position, at the potential for the region in which we operate, and come up with a plan that integrates all of the elements of this thing -- vertical wells, horizontal wells, sands, shales, gathering, processing.

And then at that point, we're also looking at getting out of the basin as well. The local market can only absorb so much. So that is one of the reasons I guess, to get back to Becca's question, of why we're looking at all this now.

And the study that you are doing right now, this basically, you are trying to figure out whether your -- how far your current play extends into your other acreage. Is that fair to say?

Well, I guess I will characterize it this way. We know the play extends across all of our acreage. The question is what are the best places to grow, what reserves per well can we expect, what kind of production rates can we expect, and how should we plan that going forward in terms of more sort of R&D wells versus simple development wells.

So there are a lot of pieces to it. I don't think anyone who knows the basin would deny that there is going to be gas in the tight sands across all of our acreage. It's a question of economics as well.

Okay. The EIA has published some stuff on the density -- how much gas is across all of Appalachia. And they kind of do it in density; they say maybe there seems to be more hydrocarbons farther north, farther south. Are those type of studies still valid, given the type of research you guys are doing right now on your acreage position, or are those completely thrown out the window?

They are valid, but they lack the quantity of data that we have. So what we will do will be have far greater resolution than anything that the EIA has done.

Okay. Thanks for the time, guys.

Shneur Gershuni with UBS.

Just two quick follow-up questions. One is a follow-up to the earlier question about MLPs. In the whole process in your analysis of MLPs and so forth, have you reviewed the opportunity of potentially putting the timber business into an MLP and possibly separating that out in terms of having it as an MLP and using the MLP to potentially grow the timber business?

We continue to consider MLPs wherever they might be appropriate. Specifically with respect to the timber business, at the moment, a lot of the timber activity that we are doing is tax-favored because of some capital loss carryforwards that we are employing, so that it doesn't appear that there is a tax advantage to putting the timber business in an MLP at the present time.

We also think that our timber business is peculiar or particular to a relatively small area in Pennsylvania, where you have this very high-quality cherry veneer being produced. Our timber business cannot be expanded geographically significantly and still retain the same kind of character. We can't go into the softwoods of the South, for instance. Two-by-fours, dimension lumber, pulp, paper are completely different businesses from the high-quality hardwoods that we are harvesting.

Okay.

(multiple speakers) clear that there are a lot of incremental opportunities within our area of forestry and geographic expertise.

Okay. I did have one other question for Matt, I guess. My understanding is the deal with EOG is to explore I guess what some people call the Devonian Shale or in some regions call the Marcellus Shale and so forth. Is there any thought to test a little deeper and go to the Trenton-Black River?

Trenton-Black River is not part of the joint venture.

So if you chose to develop the Trenton-Black River or test it out, that would be something that is completely 100% yours?

That is correct.

Is there any thought to try and test it out?

We have drilled wells in the Trenton-Black River in our acreage (indiscernible) in a joint venture with Fortuna several years ago -- without success. But that does not mean that -- by no means did those wells condemn the rest of our acreage in the TBR. It's another one of those things that as we continue our regional work, we will always have under consideration.

Okay. Thank you for taking my second question.

Jim Harmon with Lehman Brothers.

Thank you. I guess you guys are ready for a vacation after this call. I guess we're trying to come to grips to the future potential of Appalachia, and I was hoping we could get some metrics around current conventional production.

Three basic questions would be, for me would be how many wells are currently producing? What spacing are they on? And on average, maybe you could share a decline curve or how many reserves per well do you typically add?

Barry, are you in on the call there?

Yes, I am.

Can you take a stab at that one?

We haven't previously disclosed reserves per well. So is that is something we want to start talking about?

Well, I think we have disclosed the number of producing wells. But it's kind of a misleading number; we've got close to 2000 producing wells.

Just over -- yes -- 2200.

But some of them go back to the 1800s.

No, that is fair. It was just (indiscernible) point.

And the completion techniques in the 1800s were a lot different from the completion techniques in the 2000s. So I don't think that is going to help you out a whole lot.

You asked about average spacing and typical decline curve. I'm not sure whether we (multiple speakers) disclosing that.

A couple different things there. The average spacing -- I guess I don't know what the average spacing is because the wells that were drilled in the 1800s again had different spacing. And it's just a whole different animal from what we might be dealing with now.

Is your current program based upon 160, 80, 40?

Jim, here is a financial guy taking a stab at this. I think what you are trying to do is consider this acreage as pretty much contiguous and having the same characteristics, such that if you are looking at a Pinedale Field or something you can decrease spacing within a pretty much formation that is consistent throughout. We just don't have that on our acreage. And to try to use those types of numbers or math, as Phil said, I don't know that it is going to get you anywhere.

Jim, I think what it really amounts to is each of us has a sense of what the numbers might be that you are trying to get to. But one of the principal reasons we're hiring this third party to take a look at all this is that we're not really comfortable with the numbers that we have a gut feeling for. And one of the purposes of this is to take a rigorous look at the data that we have. As Matt mentioned earlier, we've got a lot more data than the EIA studies, for instance, so that we're going to be looking at this with a great deal more resolution.

Our acreage is not homogeneous. You need to look at this area by area to come up with reasonable numbers. Some of our wells might be on 40-acre spacing, some of them might be on 80, some of them might be on 160s.

And some areas are barely drilled at all.

Yes.

Okay.

Because it depends, we're undertaking this study or we're going to have somebody else undertake this study for us, based on the information that we have, to get a better resolution to the kinds of numbers that I think you are trying to get to -- what is the potential reserves on this acreage.

Thank you. I really do appreciate all the time you have all spent with us, because I guess from the outside, we're trying to understand your resource potential just as much as are trying to communicate it to us. So, thank you again.

You're welcome.

I'd like to turn it back to management for closing remarks.

All right, Mike, if there are no further questions, we will conclude the call. We want to thank everyone for taking the time today to be with us on the call. A replay is available in about one hour on both our website and by telephone, and both will run through the close of business on Tuesday, February 13th. Our website address is www.nationalfuelgas. com. The telephone replay number is 1-888-286-8010, using pass code 82459115.

With that, we will conclude our call. Thank you and goodbye.