National Fuel Gas Co (NFG) 2006 Q4 法說會逐字稿

Welcome to the fourth quarter 2006 National Fuel Gas Company earnings conference call. [OPERATOR INSTRUCTIONS] I would now like to turn the call over to Margaret Suto, Director of Investor Relations. Please proceed.

Good morning, everyone. Thank you for joining us on today's conference call for a discussion of last evening's earnings release. With us is 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 Barry McMahan, Senior Vice 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 will contain forward-looking statements, as defined by the Private Securities Litigation Reform Act of 1995. While National Fuel's expectations, beliefs and expectations 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 the call with Phil Ackerman.

Thank you, Margaret and good morning, everybody. While our 2006 recorded earnings may have been disappointing because of the writedowns associated with the Canadian properties, I remind you that those writedowns were, of course, noncash items and you should look at our cash flow for the year, which was substantially positive. We also had a number of significant positive operational developments during the year, and we made some very good progress in that regard.

First, I'm pleased with our restoration of production from the hurricane damage that we suffered a little over a year ago. At this point, only about 7% of our pre-hurricane production is not back online, and that requires the restoration of some third-party facilities. So, everything that was within our control is now back on line.

And we also substantially increased the number of wells that we were able to drill at our Appalachian properties. Having succeeded in drilling something over 150 wells in fiscal 2006, we were successful in getting agreement among the parties on rate settlements, which still require Commission approval, however, in both Pennsylvania and the FERC jurisdictions. Which will enable us to go forward there, as well.

And finally, we have the positive environmental reports with respect to our Empire connector, which will be a significant improvement and enhancement of our interstate pipeline business. For more details about our financial results, at this point, I'd like to turn the call over to Ron.

Thanks, Phil, and good morning, everyone. Our earnings release issued yesterday contains 27 pages of information. Our intent is to get out as much detailed information and explanation of results so that you can digest it before the call and so that we can spend more time with you in the question-and-answer portion of the call. Now, you'll notice that we changed the format on pages 10 to 13 of the release to highlight individual items that you should consider when comparing performance of the segments period to period. We've arranged those items into two categories.

In the first category, are things that we call "items that affect comparability." Since there could be any number of items cropping up during a quarter, we've determined not to call them one-time, special, or nonrecurring items. But they are items that really don't affect how we look at the day-to-day operation of our segment. The second category is a list of the various drivers that had an impact on what we consider the operating results.

In terms of the layout of the tables, the first row of data starts out with GAAP earnings from the prior period. The next set of rows will be the items impacting comparability that we think you should either add or subtract from GAAP earnings, to get to what the Company looks at for its own analysis of results. And we've called that line "operating results." The middle part of the table then identifies all the major drivers that cause the change in the operating results from the prior period to the current period. The bottom of our table, we show operating results for the current period, and then add or subtract current period items affecting comparability to reconcile back to the current period GAAP numbers.

Looking at the fourth quarter operating results that are summarized on the table on page 11 of the release, the $0.36 per share was $0.03 higher than the top of our guidance range. There were a number of small variances across all segments that came together to help us achieve that increase. But there was nothing that would signify any major changes in the underlying business of any of the segments.

For the fiscal year, the table on page 13 of the release shows the summary of operating results at $2.25 per share. Two items shown at the bottom of that page, the $0.03 of earning related to our symmetrical sharing adjustment and $0.13 of income adjustments are excluded from the $2.25 per share of operating results. Those items were, however, included in the $2.31 to $2.37 guidance range that we gave last quarter.

Now, our current presentation is formatted differently than the guidance table in our third quarter release, so you need to be careful what you're comparing. I wanted to make this point to be sure that you wouldn't jump to a quick conclusion that we missed our guidance. I'll turn it over to Dave and Barry to provide more details about the fiscal year operating results in the various segments. And then I'll come back to talk about our 2007 earnings guidance.

Thank you, Ron. Good morning to everyone. As Phil said, despite the volatility in natural gas commodity prices and the consequent breakdowns in our Canadian E&P operation, 2006 was a very good year for National Fuel Gas. Indeed, excluding items impacting comparability, fiscal 2006 earnings were up in each National Fuel segment, utility, high point and storage, E&P, and gas marketing. Our fundamentals are strong, and we have taken a number of steps that will help us continue the momentum into 2007 and beyond.

In the Pennsylvania division of our utility, we reached a settlement in our rate case that was filed with the Public Utility Commission on October 12. The settlement increases rates in amounts designed to produce $14.3 million in increased revenues based on sales and transportation volumes for the 12 months ended January 31, 2007. Although tariffs were filed to become effective on March 2, 2007 in connection with the initial rate case filing, the settlement provides for an earlier implementation date of January 1, 2007. On October 31, the administrative law judges assigned to the proceeding issued a decision recommending approval of the settlement without modification. At this point, while we cannot predict whether the Commission will adopt the recommendation, we have no reason to believe that the settlement will not be approved. And in fact, we expect it will be approved at one of the upcoming Chicago sessions.

As you know, distribution also filed in that rate proceeding, a revenue decoupling proposal, which is not contained in the settlement. That proposal will, however, be considered on a generic basis in a separate proceeding that has been instituted by the Pennsylvania Public Utility Commission, largely as a result of our filing. Without the emotion involved in a rate case increase proceeding, we are hopeful that the Commission will, as so many jurisdictions decisions have, support revenue decoupling and our proposed enhanced energy efficiency rider.

In New York, our current rate plan, which was approved by the Commission on July 22, 2005, will expire on July 31, 2007. Many features of the rate plan will continue past the expiration date, including the basic tariff rates and the earnings sharing mechanism, which is now at 11.5% ROE. Pension and [OPEB] deferral treatment being authorized on a generic basis in New York will also continue.

Competition programs, however, will expire on that date or on successive dates, depending on when they commenced. We have informally notified the New York DSE staff and the Consumer Protection Board that due in large part to a reduction in usage per account, we anticipate filing a rate case on the basis of data for the year ending September 30, 2006. Under the Commission's rules, this would mean that a rate case must be filed no later than February 29, 2007. We expect, however, to file sometime in January, which would produce new rates in late December, 2007, or early January, 2008.

Turning now to the pipeline and storage business. Even with the recent softening of gas commodity prices, which impact supplies efficiency gas, the segment continued its strong performance in 2006. As many of you know, that strong performance resulted in allegations by some state agencies that our supply Company rates are unjust and unreasonable. FERC initiated a proceeding to consider that and other issues.

Our last two 10-Q's contain a more complete description of exactly what our opponents alleged in the history of the case, which was on a procedural schedule leading to a hearing to start February 27, 2007. On September 25, we announced that we'd reached a settlement in principle with the state agencies that complained to FERC. The New York public Service Commission, the Pennsylvania Public Utility Commission, and the Pennsylvania Office of Consumer Advocate.

The parties and all of the parties are presently circulating drafts of a proposed stipulation and agreement and implementing tariff sheets. After the agreement is finalized, it will be publicly filed at FERC, who would approve the settlement only after a final notice to the parties and another comment period. We expect to make that public filing next week, and we hope and expect that FERC will approve the settlement at its December 21 meeting.

When we make our public filing, we will issue a press release summarizing the terms of that settlement. Until that public filing, however, deferred settlement rules forbid us from disclosing any of the term of the settlement. The Company's earnings guidance for fiscal 2007, which Ron will address in a few moments, assumes that our current drafts of the settlement documents will be approved and become effective according to their terms. While we can't disclose the terms, we can say that we're happy to have the matter behind us, so we can move forward and focus on our business.

There have also been some favorable developments in connection with our Empire connector project. As you may recall, we were concerned about a requirement in FERC's July 20 order that we renegotiate existing contracts with existing Empire shippers using standard pro forma service agreements. While we're not sure what FERC meant by that, a renegotiation requirement could have negatively impacted our project assumptions. Fortunately, we were able to reach agreements with our largest shippers, thereby, making moot the requirement and removing, at least from our perspective, the most significant obstacle to the project. That's very good news.

Operationally, thing are progressing nicely. The supplemental environmental impact statement issued by FERC, which related to the four Millennium related projects identified our proposed route as the preferred alternative and found no significant environmental issues. We have already received our New York state DEC permit for the Oakfield compressor station. And we're working to complete and obtain the remaining permits by the end of February, 2007. We have awarded and executed a contract for the compressor station engineering design. We have also bid the pipeline design engineering services contract and expect to execute that within the next few weeks. In short, things are going well, and we expect to start construction in August, 2007, for an in-service date of November 1, 2008, to coincide with the anticipated in-service day of Millennium.

In the gas marketing segment, NFR posted another strong performance, once again increasing net income for the year. NFR accomplished these results by continuing to focus on its core markets while seeking to expand in other areas. Overall, NFR achieved a record volume of over 45 Bcf in 2006, an 11% increase over 2005. With most of the increase coming in the wholesale market, the Pennsylvania retail market, and on contiguous utility systems. The New York State Public Service Commission's efforts to continue to encourage unbundling of utility systems in New York, including our system distribution, bodes well for NFR, the largest gas marketer on distribution's system.

Now in the NP segment which Barry will address in more detail in a few minutes, there are just a few items that I would like to briefly address. First, we're very excited about our joint venture with EOG Resources. That venture, which is now being finalized is designed to test a portion of our up to 700,000 acres of shale resources in Appalachia. Given its potential and given the developing nature of the technology, we've taken our time in considering the partner that could best help us exploit this resource. In the end, we selected EOG because of their experience in Appalachia, in fact they're devoting 130,000 acres to the project. And their demonstrated expertise in this technically challenging play.

We are also able to negotiate what we believe to be a mutually beneficial agreement, one which gives each party sufficient incentive and running room to provide a solid basis upon which to build. We look forward to working with EOG. I should also note that this venture is unrelated to our current drilling program of shallow Devonian wells in Appalachia. As you know, that is an area we have emphasized in the last few years, and we will continue to emphasize. Last year alone, as Phil said, over 150 successful wells were drilled in Appalachia. And Barry will discuss even more aggressive plans for 2007 and beyond.

Finally, let me briefly update you on one other matter. We have concluded our search for a new President of Seneca. Unfortunately, due to a number of factors, we are unable to disclose the successful candidate at this time. What we can say, is that we're confident that he brings the right mix of experience and leadership to Seneca and to the National Fuel family. We expect to make this announcement within the next two or three weeks.

With that, I'll turn the call over to Barry, who will remain in charge of operations, his first love. His leadership and his steady hand provided us with the luxury of time to make the right decision. We will continue to rely on Barry and his talents. Thank you. Barry?

Thank you, Dave. And good morning, everybody. Today, I plan to focus my comments on Seneca's operations. I'll start with our east division. In 2006, as Dave and Phil said, we drilled over 150 successful Devonian wells. This is an 85% increase over 2005. Total capital expenditure was $27 million, with production increasing 13.5% to 5.5 Bcfe. In 2007, we budgeted a moderate increase in drilling, but are making plans to increase the number of wells significantly.

At this time, we do not see any operational issues that will impede our planned increase. As we've discussed in our November 1 release, we are looking forward to testing the economic viability of our shale position. As Dave mentioned, Seneca's finalizing our agreements with EOG Resources to jointly explore and develop Devonium shale. Negotiations are close to being completed and we expect the agreements to be executed by the end of November.

This effort began over a year ago, when an internal study was prepared to evaluate Seneca's shale potential in our acreage. We concluded that a large portion of our acreage, over 700,000 acres, is situated in an area prospective for shale production. We also concluded a strategic joint expiration venture would reduce our risk and significantly increase our chance of success. During the past 12 months, Seneca met with over a dozen companies to evaluate and identify the best partner and the best potential business arrangement. The joint exploration venture with EOG was the result of this process.

Like Dave noted, EOG is an existing Appalachian operator, holds approximately 130,000 acres that will be available to the partnership, and they are familiar with the challenges of this region. Seneca and the EOG will explore and development shale and other deep horizons as 50/50 partners. EOG will act as operator. Starting immediately, seismic data from both Seneca and EOG will be evaluated and any new seismic data needed will be acquired.

The effectiveness of both horizontal and vertical wells in this formation will be assessed. Exploratory drilling operations are expected to begin during fiscal 2007. Seneca does not share in the cost of the initial exploratory activities, including new seismic, plus Seneca's current guidance for CapEx as well as operating costs and revenues does not include the shale program.

Moving on to our west division, we drilled a total of 95 wells with a total capital expenditure of $36 million. Which included the acquisition of the adjacent property at [South Seals] from from Ivanhoe Energy. With the installation of the scrubber earlier this year, we have realized nearly $2.7 million in operating savings by burning waste gas to generate steam.

As part of 2007's capital investment, we will include equipment to supply additional steam to our Midway Sunset enhanced oil recovery project. Steam injection is a primary source for increased productivity. We also plan to continue our development drilling program in 2007, but we're adding new focus on areas where reserves can be added.

In the Gulf division, Hurricane Rita reduced our 2006 production by approximately 4 Bcfe. Rita's impact will continue until the host system for [Vermilia] 225 is repaired, which we now expect to take an additional three to six months. Production being deferred by the Vermilia 225 is approximately 5 million cubic feet per day. In addition to our hurricane recovery efforts, we installed four new platforms, laid approximately 95,000 feet of underwater pipeline, and completed five new wells. The total capital expenditures in the Gulf in fiscal '06 was approximately $103 million.

With regard to our recently announced discovery at Highland 24-L, we have an update for you. Earlier this week, the well tested at 47.5 million cubic feet of gas per day. We expect sales to commence in the next six months. Seneca has a 35% working interest in this project. We currently have two rigs running in the Gulf. One at Vermillia253, the other is moving in at Galveston 310. As we take advantage of lower rig rates, we plan to spud at least two additional wells this quarter. A followup well to the Highland 24-L discovery is being planned for the early part of calendar 2007.

I'll conclude with some comments on our Canadian division. We drilled 25 wells, of which 21 were complete. We are currently drilling our seventh [Secunca] well in the Secunca 69-C. We expect to be bottom some time in the second quarter of fiscal '07. Total capital spend in our Canadian operations in 2006 was approximately $42 million, with nearly $17 million being spent in the Secunca region.

In 2007, we will be concentrating our internal efforts on gas plays in west central Alberta. Additionally, we are reviewing every aspect of the Canadian operation with a simple goal of improved results. Nothing is being left off the table. At this time, I'd like to thank you for listening and I'll turn it back to Ron.

Thanks, Barry. Our 2007 earnings guidance is a range of $2.10 to $2.30 per share. At this point, that would be both expected GAAP results and expected operating results. We've included in the release the broad assumptions that are factored into that range. The point to takeaway from this guidance is that we're not projecting any drastic changes in the underlying operation of any of the segments that would indicate a major change from our 2006 operating results.

There is some upside potential in our E&P segment, where we're reviewing a rampup in the number of wells to be drilled. We will revise guidance if we make any material changes to our current budgets or as a result of any modification to our drilling program. You will notice that we've got a smaller percentage of our projected production hedged going into fiscal 2007. The 13 Bcfe of hedged production, as laid out on page 23 of the release, amounts to approximately 26% of the midpoint of our production guidance.

There's two primary reasons for this lower amount of hedged production. The first, we've talked about before, and that's the issue of not being able to effectively hedge the basis for our California production. Over the past year, we've also seen this same basis issue with the Canadian pricing, when the Canadian AECO prices can diverge substantially from the NYMEX.

The second issue is the hedging of Gulf of Mexico production that may be shut in due to hurricanes. Our forecast anticipates up to four days of possible shut-ins. If you recall, at the end of last year, we had to take a fourth quarter charge related to hedged production that was going to be shut in for an extended period as a result of the hurricanes. And the forecast of a more active hurricane season had caused us to hold off putting on hedges during this past summer.

Since the main purpose of our hedging program is to limit volatility in our earning rather than cause additional volatility, we've held off on hedging additional large volumes until we can get those two issues solved in an acceptable manner. Because of our unhedged position, you need to be more mindful of the pricing strip and sensitivity table on page 26 of the release. Using yesterday's closing NYMEX strip, our earnings range could be increased by $0.125 per share. But we needed to choose a starting point for our forecast, and we chose the September 21 NYMEX strip. We think the best thing that we can do for the folks that follow out the assumptions in our forecast and provide a sensitivity table, so that you can make your own projections based on whatever pricing deck that you care to use.

Finally, with respect to our own forecast models, the forecast -- with respect to your forecast models, the forecast DD&A rate that was included in the third quarter release should be updated and lowered to a range of $2 to $2.10 per Mcfe. That adjustment is necessary to factor in the impairment charges that we took this year. We'll be in New York next Tuesday to review our operations during the luncheon presentation with analysts. And we look forward to seeing many of you there. That presentation will also be Webcast and you can check our Website for relevant details. At this point, operator, we'll open it for questions.

Thank you, sir. [OPERATOR INSTRUCTIONS] And your first question will come from the line of Jim Harmon of Lehman Brothers. Please proceed.

A quick question on the A&P division. Could you maybe go through regionally, in California specifically and in Appalachia specifically, what type of an inventory do you have left to drill? And maybe if you could explain a little bit more -- when you talk about significant drilling opportunities in Appalachia, theoretically, what could you take up the well count to? And are there gathering restrictions as to how much drilling you can do?

Well, in all of Appalachia, there's gathering restrictions, and that's something we have to focus on. But the upside, it depends on the environmental side of it, how many locations we can build, how many -- I don't think there's -- I don't think we see to date a restriction in equipment or anything like that. So it's a matter of how many we can get laid out and get permitted and get ready to drill.

Yes. Jim, this is Dave. A couple things. One is we have just about 1,000 acres there -- 1 million, I'm sorry. 1 million acres. That gives you some kind of number. But really it has been gathering system issues. And we're looking real hard, we have a team looking at how to open up Appalachia. Not only for Seneca but for all Appalachian production. So there are some opportunities with respect to gathering that we're focused on because we recognize that that's an issue in Appalachia.

Okay. And with respects to Canada, what type of an inventory do you have to process? We talking months, years?

I would say -- I would answer that and say months. In the east central Alberta area we have 70,000 gross acres that we're working with.

Okay. And what about California?

Well, California, we're converting PUD to PDP. And I would imagine we have about a five year inventory at the pace we have in the laugh few years.

Okay. We can talk about Canada. You mentioned that all options are on the table. Without asking the obvious question, maybe you could tell us a little about what took place up there this past quarter because production did appear to come in a little bit weaker than we would have expected?

Yes. Some of the wells that we put on were weaker than we expected, and some were delayed.

Okay, thank you.

And your next question will come from the line of Carl Kirst of Credit Suisse. Please proceed.

Good morning, everyone. Just keying off of Jim's question for a second. In Appalachia, Barry, I think you mentioned there was going to be a significant increase in the well count for the same budget. I'm sorry, did you actually say what the number was? I may have missed that.

No. I think, Carl, what we said there were 150 successful wells. We're looking to increase that by some number. What I was looking for was 175 to 200. That's the range I've talked to Barry about. And I think that's achievable.

That's helpful. Thank you. And again, I understand that this is not definitive, so there may not be details you can share with us here. But with respect to the EOG joint effort, I'm sorry, you said that EOG was going to give you a carried interest, presumably up to a certain dollar amount? Are these thing that can be discussed in more detail? And also, is EOG going to be buying in at all? Will there be any cash changing hands in this?

Well, we've given all the information we can give until we get the agreement signed. We would hope that by the end of November, the agreement is signed and we can release some more information that will help you out with those details.

Fair enough. Maybe one detail you might be able to release, just the 700,000 acres, for instance, I'm assuming that's a gross basis. Do you have that number on a net basis?

Those are Seneca acres, and ours is mostly fee.

Okay. I'm sorry, those are Seneca net acres then?

Both gross and net, Carl. They're fee mineral owners. Fee mineral rights that we have. So the only thing you'd maybe to to deduct from that on a net revenue basis is some of the royalties for some of the nonfee production.

That's correct.

Or nonfee acreage.

Right. And I appreciate the clarification. And then just lastly, on the proved reserves side, obviously we ended the quarter of September with a fairly low gas price number. Barry, are any of the revisions, specifically the negative revisions price related? If so, can you give us sorts of a sense of what kind out because of low gas price?s Perhaps if we had ended using second-quarter numbers, just giving us ballpark?

Yed, I can give you that in the east division, we had a -7 Bcf revision due to pricing. And I believe it was -10 Bcf revision in Canada.

Okay. So that 17 was all due to pricing?

Yes.

And then last question off of the proved reserves or more the SEC PB10 then, do you have development costs that are associated with your PB10's?

Well, obviously, we have those but not right at our fingertips. That's something that we'll be able to bring with us next week Tuesday in New York. That's obviously something that's in the -- our normal oil and gas disclosure about that.

No, absolutely, we'll wait for that, for the K. Appreciate the detail and good luck.

And your next question will come from the line of Shneur Gershuni from UBS.

Hi, guys. Just a quick followup questions. With respect to the guidance number today, I just wanted to just clarify the change from the previous quarter. It sounded like it was just related specifically to changes in the strip and so forth. Was there anything else with respect to either the Pennsylvania rate case, as well as anything on the cost structure side in E&P, or was it just literally the strip as well as your understanding of the FERC settlement?

It was all pricing, Shneur. The one slight caution with respect to the pricing. Included in that sensitivity, you also have to take into could certain basis differential assumptions that changes along with the changing pricing. But if we were to use the pricing strip that was in effect in our third quarter release, and that was a July strip, if you plug though prices back in, you'd get right back up to the $2.60 to $2.80 per share earnings guidance using that strip.

Okay. Just another question with respect to the EOG. I just don't want to beat a dead horse here because I know you're limited in your details. But that's -- my understanding is you're testing the Devonium shale and so forth in this partnership. What happens with the shallow gas? Is that all NFG's gas, is that shared as well too? I just wanted to understand where this JV was headed.

No, Shneur, that's unrelated to this joint venture.

Okay. So basically the JV is literally just below 5,000 feet or some certain point essentially?

It's focused on the shale resource.

Yes. And we've retained all the shallow rights.

Okay. Is there a possibility that you'd be doing any horizontal drilling on the shallow area -- on the shallow region, as well, as opposed to just the Devonium shale?

Our position isn't optimal for horizontal drilling in the shallow intervals.

Okay. And just one last question. Dave, you had mentioned before that you're finalizing some details with the new head of E&P and you can't make an announcement at this point right now. Can we assume it's an outsider?

Yes.

Okay. Perfect. Thank you. That answered all of my questions. I appreciate it.

And your next question comes from the line of [Kyle Henderson] of [Presidous] Asset Management. Please proceed.

Your E&P CapEx from '06 was about $208 million. Much of the large increase from '05 was targeted for the Gulf Coast operations, about I think it was around $90 million, is what you forecasted you would spend in the Gulf. You're forecasting a similar amount for 2007. A lot of that Gulf CapEx was targeted toward explorative drilling and facilities. As we think of 2007 and 2008 and beyond, should we think of this kind of $90 million level necessary to keep the production and reserve adds kind of flat in the Gulf Coast? Or we should see improvement in that or perhaps more CapEx or what can we think of?

Well, I think for '07 you certainly will be higher than that range actually. Just a little over $100 million. Going forward, we'll just have to see. I think our five year plan had it tailing off.

Okay. And is that just the result of increasing cost and lower what?

Well, it was more a move -- and this is kind of a discussion we started a long time ago, an effort to actually move away from the Gulf just because of the high cost of the wells and the short life nature of trying to get into basins that have more life to the wells.

Great.

That's the primary reason. It's still ultimately an expectation that we'll try to move away from the Gulf.

Okay. So we should think of the increasing costs that we're putting into the Gulf as what exactly?

As opportunistic at this point because what we're doing now is drilling up prospects that we had identified a number of years ago but did not drill because they were uneconomic at the pricing decks that were around at that point.

Okay. Very good. Thank you very much.

And your next question will come from the line of [Sue Lynn Ping] of Citigroup. Please proceed.

Good morning, my question is related to the CapEx spending in Appalachia. Back in August, you had indicated about $35 million CapEx there. Now with the EOG partnership, I was wondering if you are planning on increasing that CapEx?

Yes, well, we're looking at that at this point. The current guidance and the current forecast is based on that old budgeted number. But as I mentioned in my prepared remarks, we're currently examining increasing and ramping up that effort. So that's something that we're going to -- as we get those details together, we'll update the guidance.

Okay. That's fine. And second question is related to your share repurchase program. I know you are authorized to buy back up to 8 million shares, and you had bought back 2.5 already. Is there a specific timing or are you just looking to continue on an ad hoc basis or -- can you talk more about it?

You're breaking up a little bit. But we do expect, at some point, to continue on buying shares. And as I've mentioned in previous calls we're weren't going to get into a discussion of what the actual repurchase strategy was, only indicate that the Board has authorized various pricing points and volume limitations that we're following. And we're going to report on what those acquisitions are at the end of every quarter. If you just look at the number of shares we repurchased and look at the cash flow statement for the $85 million that we've spent on those repurchases, you can see we spent an average of $33.71 per share so far on that repurchase program. We have not halted it. We expect to continue to be out there in the market according to the Board-authorized plan.

Okay.

And your next question comes from the line of David Groomhaus of Copia Capital. Plea proceed.

Good morning, just two clarifying questions. In term of the earnings, you talked a little bits about the sharing and the income tax item. I think you said $0.03 and $0.13. Did that really affect the prior nine months, as opposed to affecting this quarter? And is that why it looked like coming into the quarter you were at about $2.04, $0.36 this quarter. Obviously your year was only $2.25, though. Am I thinking about that correctly?

Yes. Those were in the first nine months of the year.

Okay. So we should think about the nine month number then being $0.16 lower than what it was coming in from the 2.04, is that right?

Well, again, I'm not --.

You did shift.

I'm not exactly sure what you were looking at. But the table that was in the third quarter guidance did not exclude those two items.

Right. Okay.

However, we did exclude that in this current presentation. So you've just got to be careful what you're adding in or out.

Okay. That's helpful. And then there have been -- the EOG JV, I know you've assumed in the guidance no production. Is that being conservative or will it likely take a year to look at the seismic and do the exploratory before we potentially see any production on that?

Well, we think it will be 2008. There's a lot of work to be done. There's a lot of risks associated with these tests.

Okay. And just to clarify, you said the initial drilling and exploratory is on their dollar, not on yours?

That's correct.

Okay. And I suppose any detail beyond that we're going to have to wait for the agreement?

That's also correct.

Okay. Thank for the time.

And the next question will come from the line of [Vic Kumar] of [Soundpost] Partners. Please proceed.

Any comments on the [Reg FD] that was filed a couple of weeks where a couple of shareholders believed that your shallow assets are not fully analyzed and that there are additional exploratory opportunities in the deeper formations? And also, would you guys hire or get advice from their consultant to help realize the value of those assets?

Well, okay, with respect to the filing itself, as it was stated, I think it's a pretty fair statement in the filing itself that the principals of New Mountain Capital had talked to us because of Reg FD concerns that we've been living with for a long time now. We're very careful about disclosing to them any other information that we don't concurrently disclose to our other shareholders. So they did inform us of their position, but we have not had a discussion back with them with respect to those items. In term of the further development of our Appalachian resources, we've already indicated that we hope to ramp that up.

Right.

And that combined with the EOG venture should give you an indication that we're looking at getting more more earnings out of our Appalachian assets.

And the second question about using that consultant or --?

Yes. At this point, I think we have with EOG in the shale play and on our own in the shallow Appalachian production, we do have a lot of expertise there. And typically the issues get to be gathering issues. And we have a lot of expertise in that area. We're presently working on it. But that's not to say we would foreclose bringing somebody in. There is clearly unlocked potential there. And so, I -- the answer is not yes, the answer is not no. It's something that we certainly would consider.

Great. Those were my questions. Thank you.

And your next question will come from the line of Joanne Fairechio of Janney Montgomery. Please proceed.

Good morning. Switching to the utility for a minute, and I know it may be a bit premature to say at this point. Are there any proposals such as decoupling or trackers that you might incorporate into your New York filing? And also, has the New York commission backed off a bit on encouraging migration to third party suppliers? Thanks.

Well, let me take the second one first. No, they haven't backed off, and as a matter of fact, as a result of our previous settlement, we're actively in a program right now to let's say support growth in the migration to third party marketers. We've got an advertising program going on right now announcing that customers can save up to 7% of the commodity portion of their bill by switching over to a third party marketer. So no, the Commission hasn't backed off on that. With respect to any other revenue decoupling mechanisms or rate mechanisms, let's call them in New York. Yes, New York has been kind of on the -- I won't say the cutting edge, but they are always willing to listen and look at new rate mechanisms in any filings. And we're kind of looking at all of that right now as we put together the filing based on September end data.

Joanne, just -- can I just add that, we have a new Governor, as you know.

Right.

And typically, Commissions evolve, the staff is there, the staff is going to continue to focus on customer service and those -- things of that nature.

Sure.

But perhaps you'll see a little bit of a change in direction. And certainly if you look at the Attorney General's office and what they were involved in, it wouldn't surprise me if the new Commission ultimately moved in the direction of less competition, less unbundling. It also wouldn't surprise me given the Attorney General's positions if they weren't more representative to revenue decoupling mechanisms. So you have to look at it over a period of time. And I think into the future, both -- you may see a change in competition and in those issues. And you may see a change in revenue decoupling just based on the new Governor and new direction.

Right. Would you be the first Company in New York to also file for decoupling? I hadn't seen any others filed similar to what you did in Pennsylvania.

I don't believe there are any in New York. So we probably would be the first Company to file.

Okay. Thank you.

But Joanne, again, just one more followup point on that. The filing would probably be in line -- if you go back to the generic proceedings that are going on regarding decoupling, the comments from the Attorney General, our soon-to-be Governor, actually support those kind of rate mechanisms. So I -- we do hope to include those in the filing.

Okay. Thank you.

And your next question will come from the line of Jim Harmon of Lehman Brothers. Please proceed.

Thank you. Just a followup question on the Appalachian question. I thought it greedy since you're in a chatty mood. But if you're drilling 200 wells per year, what type of inventory is that over -- how many wells can you drill or how many wells have you identified to drill?

Well, I'm not sure we have an inventory that we can tell you there's 1,000 wells to drill or 2,000 wells to drill. But based on spacing, we have room to drill for several years.

Okay. Good. Second question would be related to lower DD&A costs. Can you give us a little more color as to what's driving that or maybe I missed it?

Well, with respect to the -- all I'm saying is we needed to update the guidance that had been provided in the third quarter release. Because during the first -- the fourth quarter, we had the impairment in Canada with the lower depletable base in Canada, the results from that impairment. Just the math works to lower the DD&A rate. So that's going to be more in the range of what we saw in 2006. Or as the range I gave is $2.00 to $2.10 per Mcfe.

Okay. Is that going to be inclusive of both writedowns?

Yes.

Okay. Great. Thank you very much.

[OPERATOR INSTRUCTIONS] And you have a followup coming from the line of Shneur Gershuni. Please proceed.

Just one last followup question. You had mentioned in your prepared remarks about rig rates in the Gulf of Mexico coming down and so forth. Would you be able to give us an idea what you believe they're down by? Is it 5%, 10%? Is it -- also if you can give color on whether it's getting a lot easier to secure rigs and so forth?

You cut out on the second part of that question.

Whether it's been easier to secure rigs or not.

Okay. Thank you. We've seen rig rates drop in the last two months by about 40%. And we don't know if that's long term or short term but we're imagining it's going -- the market is going to tighten up this winter. As it relates to availability, we're having no problem attracting the rigs we need to do our work.

Are you signing any of these rigs up to longer term contracts?

No, we are not.

Okay. Thank you.

And your next question will come from the line of [Stephen Strassburg] of Longbow Capital. Please proceed.

Yes, I just have a question on the share count. When I look at page 15 of the release, which is the balance sheet, it shows shares outstanding at the end of '06 being 83.4 million versus 84.4 million at the end of last year. And then on page seven, you said that you bought back 2.5 million shares. So then again it looks like you've issued 1.5 million shares for something. Could you talk about what program that was, how that worked, and what sort of run -- works, and what sort of run rate you expect for that going forward?

The issuances of the shares, Stephen, are just issuances under the outstanding options program. So that's people exercising options. There's also -- there would be a slight uptick there from shares issued for payment to the Directors for Directors' fees. With respect to the run rate, boy, that just depends on mark conditions. When people elect -- on market conditions. When people elect to exercise the options, which are normally outstanding for a 10-year period. So I just can't give you any estimate on that.

Is there any disclosure anywhere as far as the schedule of though, or what's outstanding or anything of that nature that we can then use to gauge for ourselves?

Sure. That -- there's a table in the 10-K with respect to what the outstanding options are.

Okay. Thank you.

[OPERATOR INSTRUCTIONS] And there are no other questions, so I will turn it back to Margaret Suto.

Thank you, Cindy. We'll conclude our call then for today. We would like to thank everyone for taking the time to be with us. And the replay this call will be available in about one hour on both our Website and by telephone. And both will run through the end of business on Friday, November 17. Our Website address is www.nationalfuelgas.com. The telephone replay number is 1-888-286-8010, using passcode 91885312. This concludes our conference for the day. Thank you. And goodbye.

Thank you for your participation in today's conference. This does conclude the presentation. And you may now disconnect your lines. Everybody have a great day.