National Fuel Gas Co (NFG) 2006 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the third quarter 2006 National Fuel Gas Company earnings conference call. My name is Sherell, and I will be your facilitator for today. At this time, all participants are in listen-only mode. We will be facilitating a question-and-answer session towards the end of this conference. [OPERATOR INSTRUCTIONS]. As a reminder, 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.

Thank you, Sherell. Good morning, everyone. Thank you for joining us today for our conference call for a discussion of last evening's earnings release.

On the call today, we have 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, 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 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 National Fuel's most recent Form 10-Q for a listing of certain specific risk factors. With that, we will begin with Ron Tanski.

Thank you, Margaret, and good morning, everyone.

Except for the impairment charge related to our Canadian oil and gas properties, our earnings for the quarter were in line with our expectations. A dip in natural gas pricing at the end of June and the use of that pricing in our ceiling test calculation caused us to write-down the book value of our Canadian Exploration and Production properties at the end of the quarter.

As we cautioned last quarter, we had no cushion in our Canadian ceiling test calculation at the end of March, and the approximate dollar per Mcf decrease in the prompt month pricing from March 31st to June 30th resulted in the $62 million impairment, or an after-tax $39.5 million reduction in earnings. That offset all the earnings in the other segments for the quarter.

Commodity prices have firmed up since the end of June, and the pricing of the NYMEX forward strip would seem to indicate that we shouldn't be facing an impairment any time soon. All the other period-to-period variances are explained in the release, so I won't repeat that discussion now, and there've been no other changes in any of the earnings drivers in the segment we are mentioning.

Now, the back pages of the release include detailed segment information for the 2005 fourth fiscal quarter. We began providing detailed segment information in the first quarter this year, and because the detailed information for the last quarter of fiscal 2005 was not available anywhere else, some analysts had asked us for the information in order to complete their trend analysis. So we included it in this release.

The earnings guidance for the fourth quarter continues along with our previous assumptions regarding production volumes, and incorporates approximately three days of possible shut-ins of our Gulf of Mexico production due to hurricanes. The commodity pricing assumptions for the fourth quarter are an average gas price of $7 per Mcf, and an average oil price of $74.50 per barrel. So with the fourth quarter consolidated earnings expected in the $0.27 to $0.33 per share range, we expect earnings for the entire fiscal year to be in the range of $1.85 to $1.91. Excluding the impairment, the fiscal 2006 earnings are expected to be in the range of $2.31 to $2.37.

Looking forward to fiscal 2007, our preliminary estimate for consolidated earnings is in the range of $2.60 to $2.80 per share. The increase in earnings results primarily from increased oil pricing and the falling-off of hedges in the Exploration and Production segment during 2007. We're still in the process of refining segment earnings in the capital structure assumptions for each of the segments, so we're not yet in a position to further break down projected fiscal 2007 earnings among the various segments.

We do, however, have the preliminary capital budgets by segment for fiscal 2007. Those preliminary budgets include $58 million of capital spending for our Utilities segment, $65 million in our Pipeline and Storage segment, $210 to $214 million in our Exploration and Production segment, and $4 million for the rest of the Company, for an overall total of $337 to $341 million. In the Pipeline and Storage segment, approximately $38 million out of the $65 million total is for the Empire Connector Project.

At the end of June, our balance sheet has an equity component of over 54%, and our preliminary forecast for fiscal 2007 indicates that, before considering our share repurchase program, we will again have free cash flow, even considering a capital expenditure budget in the $340 million range.

Regarding share repurchases, as we indicated in our earnings release, we have not built any further repurchases into our guidance calculations because we can't predict when those repurchases will occur. We do, however, intend to monitor the market and continue repurchasing shares absent other investment opportunities, and we will continue to report on those repurchases at the end of each quarter.

Before I turn the call over to Dave Smith, I want to touch base on a rate -- or I want to touch on a rate increase request in Pennsylvania. On May 31st, we submitted a request to increase rates in Pennsylvania by $25.9 million. The increase request has the following broad parameters. Our projected rate base is approximately $297 million, and our filed capital structure and component cost rates are as follows

We filed for an equity component of 51.5%, and requested a 12.25% return on equity. Our long-term debt component is 40.04%, at a cost rate of 6.64%. The remaining 8.46% of our capitalization is short-term debt, at a projected rate of 6.39%. Multiplying all that out would yield a return on rate base of 9.48%. Now, clearly, the one aspect of the filing that has raised the biggest rate payer reaction is our proposal to institute a rate mechanism to address customer conservation, or a revenue decoupling mechanism.

Proposals like this have been put into place in at least five different utilities in four other states, and proposals are either under consideration or pending in 13 additional states. Vice Chairman Cawley of the Pennsylvania Commission has directed the ALJ and parties in our case to fully address rate design issues that encourage conservation. There's a pretty good summary of the Vice Chairman's comments in the July 31st issue of “Gas Daily”, and we're hopeful that we can implement a rate structure that can allow us to promote conservation by our customers, and at the same time, also allow us to recover the revenues that we need to provide safe and reliable service.

The normal schedule for a rate proceeding in Pennsylvania is approximately nine months. So we may not have any resolution on this issue until February, but we'll keep you advised of any major developments before then.

Now I'll turn the call over to Dave Smith.

Thank you, Ron, and good morning to everyone.

Despite a number of challenges, challenges that were really faced by most in the utility industry, the Company's overall strong performance continued through the third quarter. If you exclude the non-recurring Canadian write-down, earnings are up in each of the major operating segments of the Company, not only for the quarter, but year-to-date as well. As Ron said, that information is contained in our release, so I will not dwell on it here.

There were some developments during the last quarter that are not addressed in our release, and that merits some discussion. A number relate to FERC orders that were issued during the quarter. Given time constraints, I'll only hit the highlights, but will be happy to answer any questions you may have on these matters.

On July the 20th FERC issued an order regarding our compliance with FERC Order 2004 and the standards of conduct that govern the relationships between jurisdictional pipelines and their marketing and energy affiliates. Now, this issue's been around for some time, and in fact, for the past couple of years, the Company's 10-Qs and 10-Ks have indicated that we could predict the impact of that order on the Company.

While there were a number of potential issues, most of which have been resolved, our primary concern was that if our utility distribution was determined to be an energy affiliate of supply, as that term is defined in the order, the companies would have to incur the significant expense of duplicate facilities, such as our gas dispatch facility, for example. Duplicate personnel and inefficient operating practices.

The order we received was really a pretty good order, one that essentially resolves our compliance. In pertinent part, the order concluded that so long as distribution continues to refrain from making certain off-system sales, and we have not made those off-system sales since the beginning of 2004 - Order 2004 - supply will not be required to treat distribution as an energy affiliate. The bottom line here, neither supply nor distribution will have to incur the significant capital or operating costs of duplication, and there will not be a material impact on the Company.

Turning now to another matter, on June 7th, FERC issued an order regarding the complaint that was filed by the New York Public Service Commission, the Pennsylvania Utility Commission, and the Pennsylvania OCA, under Sections 5A, and Section 13 of the Natural Gas Act. As you know, that complaint asks FERC to find that supply corporation's present rates are unjust and unreasonable, and also questions whether supplies pass in ongoing sales of efficiency gas were authorized.

It also moved for summary disposition, asking FERC to immediately reduce supply's fuel retention. Our answer opposed the allegations in the complaint, and the complainants' Motion for Summary Disposition, asserting that supply's current rates are just and reasonable, and documenting our authority to sell retained gas. On June the 7th -- the June 7th order was generally consistent with our expectations. It denied the complainants' Motion for Summary Disposition on the fuel retention level.

It set the complaint for hearing, and initiated an investigation into supply's rates, and it suspended the commencement of the hearing by referring the complaint to a settlement judge with the intention of facilitating negotiations. The parties are presently engaged in ongoing settlement discussions, so we can't really say much here because that process is confidential and privileged. The settlement judge did report, however, that the complainants agreed to make an offer by July 27th, and that we agreed to respond by August the 3rd.

Now, we don't know how long it's going to take to resolve this proceeding. If the parties are able to negotiate a settlement that is ultimately approved by FERC, the effective date of any new rate will be part of that settlement. And I should note that in the guidance that Ron provided, there was no indication of any adjustment to supply corporation's rates that might occur as a result of any settlement.

If the settlement process breaks down and we go to a hearing, we will vigorously oppose the complaint. The June 7th order provides for the judge to issue an initial decision within 12 months after the commencement of the hearing process. The judge's decision would be a recommended decision, and FERC would subsequently issue a final decision, which may or may not be consistent with the recommended decision. We will update you as the process proceeds.

The other significant FERC order that was issued during the quarter that I'll mention relates to our Empire Connector. As you know, the planned in-service date for Millennium pipeline, and therefore the Empire Connector, has been revised from November 1st, 2007 to November 1st, 2008. We have consistently said that whenever Millennium is ready, the Empire Connector will be ready. Fortunately, considering the increasing lead time for materials and contractor services, FERC did not slow the approval process down as a result of the slippage in the in-service date.

On July the 20th, FERC issued a preliminary determination on non-environmental issues, indicating that FERC will authorize Empire to construct and operate the Empire Connector and to operate the existing Empire facilities, subject to environmental review and the issuance of a final order. While this order provided clarity on a number of issues, it was disappointing in at least one respect. FERC rejected Empire's plan to provide service to existing shippers under the current service agreements, instead requiring Empire to renegotiate its existing contracts, using its standard pro forma service agreements.

Now, the order is not entirely clear on what happens if we are unable to renegotiate and sign new agreements with our existing shippers. But we will resist any requirement that would change the economic effect of those existing agreements. These and other issues will probably prompt Empire to file a request for rehearing. We expect to receive FERC's final determination on these issues, together with all the environmental conditions, as part of the final FERC certificate.

At the end of the day, we think we're going to end up with a final order that is acceptable to the Company, which would allow us to go forward with this project.

Now, before I turn it over to Barry, let me comment on the recent management changes in our E&P subsidiary, Seneca Resources. In Canada, we've promoted Jeff Campbell to Executive Vice President and made him responsible for the Canadian office and operations. Jeff has been with us for four years, and has over 24 years of experience in the oil and gas industry.

After 17 years of dedicated service, Jim Beck recently retired from Seneca. We have retained an executive search firm to assist us in our search for Jim's replacement, and we are very encouraged by the quality of the candidates we have interviewed to date. With regard to timing, we have no definitive timetable, but we will endeavor to fill the position in the near future.

One reason why we are comfortable taking whatever time is necessary to make the right decision is the overall leadership that's being provided by Barry McMahan. Barry's been responsible for Seneca's operations for 18 years, and was and is instrumental in Seneca's success, particularly in California.

And on that note, I'll turn the presentation over to Barry for an update of Seneca's activity.

Thank you, Dave, and good morning, everyone.

During the quarter, Seneca continued to be very active, drilling 80 wells. Production for the quarter was just over 12 Bcfe, while revenues totaled $86.6 million, or a 12% increase when compared to 2005. Our capital budget has been increased to $207 million. The increase affects the East, West, and Gulf divisions, with Canada remaining unchanged.

The new totals are as follows. $27 million in the East, with increases for additional drilling; $44 million for drilling, acquisition, and infrastructure for new wells in the West; and $90 million for drilling projects, increased working interest, platforms, and associated facility construction in the Gulf.

In the East, our production increased 5% over the second quarter and 13% over the same period in 2005. During the third quarter, 44 wells were drilled, bringing the total to 97 wells for the year. Favorable weather conditions and an extraordinary effort by our staff are the main reasons for this increase. We expect third quarter momentum to carry through to the fourth quarter.

In our West division, third quarter production was flat to the second quarter, but increased approximately 1% on a year-on-year basis. The 2006 heavy oil drilling program was completed in June. A total of 87 producers and injectors were drilled. All these wells are in various stages of completion.

At South Lost Hills, four wells were drilled for the year, two in the third quarter. Both of these wells were being completed as the quarter ended. Three additional wells in South Lost Hills are planned for the fourth quarter. The waste gas scrubber system has reduced LOE by approximately $1.8 million since it began operating in January of this year. Total cost of the project was $6 million. A new project is underway to secure waste gas to expand the use of the system and to increase potential savings.

In the Gulf, third quarter production totaled 3.3 Bcfe. Gulf production continues to be impacted by Hurricane Rita and natural decline. One significant property remains off production. That's our Vermilion 225. It's currently estimated to return to production by the end of September.

At the end of the quarter, Eugene Island 320 came on production, is now leveled off, making approximately eight million cubic feet per day. Platforms for Viosca Knoll's 77 and 432 have been constructed and installation has begun. Based on current estimates, first production from these platforms will be in late September. Additionally, the Brazos 502 #2 well was drilled and encountered 97 feet of pay. The well is currently mud line suspending and awaiting completion. Plans are to combine this well production with the previously drilled #1well.

In Canada, production totaled 2.56 Bcfe, up 18% over the second quarter, but flat to the previous year. Third quarter production was positively affected by the Sukunka 93-D well. Production began April 10th, and the well is currently producing 33 million cubic feet a day. In mid-July, Talisman spudded the Sukunka 69-C well, which will help delineate the productive trend in the field.

Hedging for the remaining three months of fiscal '06 can be summarized as follows. For oil, we have 450,000 barrels hedged with the swaps at an average price of $35.33. For gas, we have 2.3 Bcf hedged with swaps at an average price of $6.20 an Mcf. We have another 1.1 Bcf hedged with collars. The average floor is $8.28 an Mcf, and the average ceiling is $15.47.

The impact on price changes on earnings for the remaining three months is as follows. For every $1 change in oil prices, earnings will change 1/3 of $0.01 per share. For each $1 in gas prices, earnings will change $0.03 per share. Looking ahead to the fourth quarter, we anticipate production to be between 11 and 13 Bcfe. We are focused on meeting our production goals and preparing to execute our 2007 plans. A summary of our 2007 guidance can be found on page 22 of yesterday's earnings release.

At this point, I'd like to thank you all for listening and return the call to Mr. Phil Ackerman.

Thank you, Barry, and good morning, everyone.

I'm pleased that the market is looking through the Canadian write-down to the underlying performance and value of the Company. As Dave and Ron have pointed out, our divisions are up, we've repurchased over two million shares, our equity ratio is over 54% and higher than last year. Obviously we expect 2007 to be even better with a 10% to 20% increase in earnings per share.

Jim Beck has retired as head of our E&P operation, but we have specifically retained Jim as a consultant to help us with Gulf of Mexico exploration. Beginning in January of 1991, under Jim's guidance, we began an exploration program focused on the shallow waters of the Gulf of Mexico. While most of the ensuing discoveries have been depleted by now, the success of that program was largely responsible for the dramatic growth of our E&P segment.

I expect our arrangement with Jim will enable him to focus his efforts on the area where he has had his greatest successes and made a major contribution to the growth of National Fuel. I'm looking forward to continuing discoveries in the Gulf in the coming years.

We are all pleased with the quarter and the nine months, but they are merely steps along the way. We are continuing to work in all areas to build long-term value, whether it's wells, pipeline, storage, rate innovations, timber, financial strength, or any of our variety of assets. Our team and our Company is knowledgeable, focused, delivering results and working hard for the stockholder every day.

With that, Operator, I'd like to take questions.

[Operator Instruction]. Jay Yannello, Pali Capital.

Good morning. I was just wondering. In the '07 guidance, I realize it's early, but I think there's some lumpy tax benefits in this quarter. And I'm wondering if we should assume there's any lumpy benefits in the '07 guidance? Thank you.

Jay, this is Ron Tanski. I don't want to have to go back to quote Ben Franklin, but, I mean, there will always be certain tax adjustments. We expect to be alive, but there will be tax adjustments. The best we can do is get those in the right quarters when they occur, and point those out to the analysts so you can deal with them how you want to deal with them in your forecast and in your models.

But at this point, having gotten rid of the valuation allowance that was on the balance sheet, we really don't expect all that much to come -- be coming forward next year.

Okay. Thank you. And another question, I realize it's early, but as you look for the new head of Seneca, I'm just wondering how might this person be incentivized? In other words, from a compensation standpoint - again, I realize it's early - but what do you think this person's compensation will be based on? Production, production costs, reserve additions, stock price? I'm just curious how you might incentivize this new person.

Somehow we need to incentivize the person in a way that relates to shareholder value. Merely production, merely reserve growth, don't do it appropriately. You have to consider cost, you have to consider return on investment. Somehow we need to find a formula that relates to growth in net income that considers how much it costs to achieve that growth in net income. We don't specifically have a formula in place. We do have in mind the parameters of what needs to be done.

Okay. I would agree with you on that, and I would look forward to knowing that when this person is brought on board. Thank you very much.

[Schneer Gushiney], UBS Securities.

Hi. Good morning, guys. Just had a couple of quick questions. I was sort of doing a comparison of the guidance with respect to production for this year relative to last year's guidance pre-Hurricane Katrina It is down relative to that. And that said, it sounds like most of the volumes will be back from the hurricanes and so forth. And so there's a decline really in the Gulf as well as in Canada and so forth. I was wondering if you could speak to why production's down specifically in the Gulf? Is it decline, is it other issues, and so forth?

I think it's natural production declines, something that we've been aware of for a long time. You have those high decline rates in the Gulf of Mexico. Also there's more delay in the Gulf of Mexico of realizing the impact in terms of production from any discoveries that you have, any new wells. It's going to take us a while to turn the Gulf of Mexico around, or to stem that decline. We can just get wells on line a lot faster in Appalachia, for instance, than we can in the Gulf of Mexico.

Would it be fair to say that you expect to stem this decline by the end of '07, or is this something that'll continue further on?

That's going to depend on the success rate of our exploration program. We're not saying anything about that yet. As we've said before, we try to tell you which wells we're going to drill, what the impact wells are going to be, and where -- when we achieve success with those wells, when we expect them to come online. We don't know yet. We've told you what we expect production to be in 2007, and that's as far as our crystal ball goes.

Okay. Just two other quick questions here. I noticed that the language in the press release changed with respect to share repurchases. Last time, it sort of threw out a hypothetical that if you continued at the same pace, you'd be done by January of '07. Now it's kind of -- the language reads more to the length of purchasing shares from time to time and so forth. I mean, is the goal still to ultimately complete the program? Is it more that the stock prices run up and you don't want to continue purchasing at this level and so forth? Maybe if you can provide just a little bit of color on that.

Yes, we -- Schneer, we do have certain price targets built into the -- or pricing points built into the plan that we've discussed with the financing committee of the Board of Directors, and as we've said before, we're not -- I mean, we're not going to disclose all those various parameters of the plan given the market, given the trading volumes, and the short interest in our stock that we've seen lately. And nor do we want to artificially spur the pricing by our buying pattern. So we do have the goal of reacquiring the full eight million shares, and we intend to proceed along with our plan. I guess that's all we're willing to say at this point.

Fair enough, Ron. If it gets to a point where you're above your target points, I mean, does the Board reconsider and possibly raise the dividend or something to that effect?

Sure. I mean, we're always reviewing the appropriate payout ratio. But as we've said before, we want dividend increases that are sustainable, that we won't have to revisit somewhere else down the line.

Great. Thanks a lot, Ron. I really appreciate that answer.

Ralph Anderson, Merrill Corporation.

Yes, good morning. Ron, the CapEx needs you have mentioned, how are you planning to finance those, external or internal or both?

The CapEx that we have on in line for 2007, we indicated that we do have sufficient cash flow to fund that internally. If the share buyback is completed during the next year, we've also indicated that we would have to enter back into our commercial paper program to finance our working capital, which basically has still been funded with cash that we have on our balance sheet.

So I'm -- again, absent the -- anything else major, it's free cash flow.

Thank you.

Michael Collins, Neuberger Berman.

Good morning, gentlemen. Can you give us an update on the million acre as far as range resources Chesapeake and Talisman have been developing in the area? And we're excited about the acreage, but can you give us your view and an update of where we are with this, and what you're thinking?

I'm not sure what the question is about. Range resources?

No, no, no. I said in the area, there's people who are developing in the Appalachia, you have a million acres, and we wanted an update of how you're proceeding with your -- potentially a joint venture to develop the acreage?

We have been talking with a number of people, and I think we've said this from time to time, about trying to explore the possibilities of the shale in our area. We did have a joint venture with Talisman three or four years ago --

I know that, but --

-- Black River. I'm still kind of befuddled about what your question is here. We've talked about our --

Yes. Just an update.

-- drilling there.

I know you're drilling in the shallow, but at 3 to 5,000 feet, wondering where are we at with that, and now that there's no head of Seneca, that that puts that project on hold for now until you get a head of -- somebody who runs Seneca.

Well, first off, whether or not there's a replacement for Jim Beck doesn't put that project on hold.

Okay.

Drilling in the East is a different sort of drilling than drilling in the Gulf of Mexico, or Canada, or whatever. It's -- I guess I would say far more mechanical. And we're continuing to do that with no slowing of the pace. As a matter of fact, we're drilling at a faster rate than we were.

Michael, I have -- that was one of the increase -- or the reasons for the increase in the CapEx budget for the Appalachian division because we -- because of the good weather, we have been able to drill more wells than projected so far this year. And we expect that rate to continue, if not increase, a little bit more based on rig availability in Appalachia, because we have seen the -- with the pricing that we do have locations that are available. But as we've talked about before, the problem in Appalachia is the take-away capacity with the gathering systems, that the new wells with the flush production sometimes cut back the production from the older wells. So we only want to do it where it makes sense.

Yes, Mike, I'm not sure of the specific project that you're referring to --

I'm just on your -- yes.

-- but generally speaking, our emphasis really in Seneca, we really are emphasizing resources in Appalachia, and we're ahead of our -- we're ahead of our targets and our supply company is looking at ways of opening up Appalachia, not only for Seneca, but for all of local production. I believe they've recently had an open season with respect to that. So that's an area of emphasis for the Company as a whole.

All right. Thank you.

Faisel Khan, Citigroup.

Good morning. Just a question on the utilities side. Would you be able to pull the file in New York this year or next year, for a rate -- for rate release?

Based on the last settlement, Faisel, we can file as early as September, and we've been reviewing that possibility for a while. We've obviously focused on Pennsylvania to get that filing in, and we're in the process of answering interrogatories there. So that's kept us a little busy.

I expect that we may not meet absolutely the earliest filing date in New York, but something that's constantly under consideration.

Okay. And then on the -- on the E&P side, you were discussing earlier about how you've increased your budget there for '06, and a lot of that has to do with the fact that you're drilling more wells than you anticipated in Appalachia and the West Coast. In the Gulf of Mexico, are you -- are you drilling more wells than you initially thought you would for this coming quarter? Is that what you're saying?

Well, I think most of that -- well, for the overall budget, there was some carryover of the 2005 budget that actually got spent this year, so there's, I believe, one new prospect that we're drilling, Barry, and then a lot of -- a lot more infrastructure, and --

Yes. If you look at our success in '05, that carry forward to '06, and we actually set facilities for wells we drilled in '05, at the end of '05, and we didn't anticipate the cost for the structures at that time.

Oh, I see. Okay. So you're carrying CapEx over from '05 to '06?

Yes.

Okay. And then this -- the Brazos 502 well, when was that completed ?

It's not completed. It's mud line suspended. We finished drilling, I believe, in early June, and we suspended the well. Now we're in the process of designing facilities and preparing installed flow lines, and we're going to combine it with the #1 well, which was drilled in '05.

Okay. So the #1 well that was drilled in '05, you'll combine that with this, and that'll flow -- that'll flow back to sales at some point in time?

Yes.

Okay. And then -- how would that compare? How does that -- the net pay you encounter compare to the Eugene Island 320?

It's a totally different environment, but we wouldn't go forward if we didn't think it was a profitable venture, so the 320 is a totally different animal.

Okay. And then, I guess, looking at your guidance for the rest of this year, the 11 to 13 range. What would -- what's determining whether you get to 11 or to 13?

I think the biggest thing would be weather. I think we'd have to see how the hurricanes treat us.

Okay. So you are building some cushion in there for hurricanes?

Yes.

Okay. And then you talked about that Talisman was drilling out in Sukunka on the outer periphery of that formation. I thought they drilled another well. I think it was called Bullmoose 93P. Is that -- is that part of the Sukunka acreage? Is that a well that you did -- elected not to participate in?

That's not part of our joint venture. That's something outside of our joint venture.

Okay. Fair enough. And then in terms of next year, in the Gulf of Mexico for your guidance, your CapEx guidance, you said, I think, it's eight to 12 wells, is that right, for next year?

Yes.

Okay. And are -- would all those be exploratory prospects?

Yes, I don't think there's any development in that. That's all exploratory prospects.

Okay. What kind of -- what kind of success rate do you think we ought to kind of factor into our numbers when we look at these things? What's your -- I guess what has been the historical success rate in your exploratory?

Well, there's a couple of things. One, it's unlikely that any of those wells will affect our 2007 production because of the length of time it takes to get those things on. And historically, going back to the program that Jim Beck started, when you've got things that are delineated by 3-D seismic, and you've got bright spots in AVO and all that good stuff, we were running around 80% success.

Okay. So the production guidance you have for '07 is predicated on the inventory of wells that you have right now in your budget, is that right?

That's correct.

Okay. Fair enough. Thank you for your time.

[OPERATOR INSTRUCTIONS]. Becca Followill, Howard Weil.

Good morning. I apologize if these questions have already been asked, because I got on a little bit late on the call. First one is on the buyback. You'd talked about in the previous release about maybe having this done by January. With the increase of CapEx spending, is that still the plan?

Well, as we answered before, Becca, we have certain price points built into the share buyback plan that's been considered and reviewed by the Financing Committee of the Board of Directors. And depending on what the market is for the -- for our stock in share price, we don't want to be in a position where we're artificially affecting the price of the shares in the market, so we'll be kind of reviewing that on an ongoing basis.

But with respect to the overall cash position of the Company, we've indicated that we will be cash flow positive, even with our $340 million or so CapEx budget. The extra spending for a share buyback would just get us in the position where we would be back into our commercial paper program for our normal working capital financing, which to date -- or for the last year and a half or so -- has been funded with available cash.

So the change in language is more a function of the timing of price points versus CapEx?

That's right.

Perfect. Thank you. And then the next question is, on the shares outstanding, just looking at the cash flow and balance sheet, I see there's been some issuance of common stock along with the share repurchases, so we didn't see much movement in the share count. How much on a net basis are you looking to really move the share count when you net the issuances against the purchases?

Well, the issuances are essentially just the exercise of stock options, and -- boy. On a net basis, that's hard to say. That just depends on the timing of the option exercises, and I believe there's -- some of those options go out for ten years, so it really depends on --

Too tough to tell then.

Yes, the exercise pattern.

Okay. Thanks. And lastly on the production for 2007, can you remind me again how much the hurricanes negatively impacted you in '06?

I don't have the number in front of me, but we lost basically a quarter's production in the -- in the Gulf in '06. And we still have our Vermilion 225 off, which represented about 7 to 8% of our total, so I don't have a Bcfe number for you.

Okay. Thank you very much.

Jim Harmon, Lehman Brothers.

Good morning. I was hoping that maybe we could go through the production regions and talk a little bit about the nature of the prospects yet to be drilled. I assume the Gulf is opportunistic, while Canada is tied to Talisman, but maybe we can go through what's left to be drilled in Canada, and maybe what can you do in Appalachia, if all cylinders fire correctly.

Before we get launched into the answer, are you talking about for the balance of '06, or what we project for '07?

Well, I'm trying to get line of sight more what you can drill before you'd have to go out and buy additional properties. And I guess that would take place either in Canada and Appalachia, where it seems that you do have inventory to drill, that you alone are drilling.

Well, in Appalachia, obviously we have our acreage, and we're in pretty good shape there, and both Canada and the Gulf of Mexico, the acquisition of acreage has been an ongoing activity. We've been participating in the lease sales offshore in the Gulf right along, and we've been acquiring acreage in Canada right along.

We just had a purchase in Canada of acreage both in the Sukunka area and in the east central part of Alberta. You can't have an effective exploration program without continually adding to your acreage position.

When was that done?

Just this last quarter, actually.

Okay. Is it contiguous to existing acreage, or is it -- ?

It is an area that we are familiar with, and want to focus on.

Okay. Thank you very much.

[OPERATOR INSTRUCTIONS]. As there are no further questions at this time, I would now like to turn the call over to your host, Margaret Suto, for any closing remarks.

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