Exhibit 99
Conference Call Transcript
NFG — Q4 2007 National Fuel Gas Company Earnings Conference Call
Event Date/Time: November 09, 2007 / 11:00AM ET
National Fuel Gas Company (the “Company”) and its directors and executive officers may be deemed to be participants in the solicitation of proxies from stockholders in connection with the Company’s 2008 Annual Meeting of Stockholders (the “Annual Meeting”). The Company plans to file a proxy statement with the Securities and Exchange Commission (the “SEC”) in connection with this solicitation of proxies for the Annual Meeting (the “2008 Proxy Statement”). Information regarding the names of the Company’s directors and executive officers and their respective interests in the Company by security holdings or otherwise is set forth in the Company’s proxy statement relating to the 2007 annual meeting of stockholders, which may be obtained free of charge at the SEC’s website at http://www.sec.gov and the Company’s website at http://www.nationalfuelgas.com. Additional information regarding the interests of such potential participants will be included in the 2008 Proxy Statement and other relevant documents to be filed with the SEC in connection with the Annual Meeting.
Promptly after filing its definitive 2008 Proxy Statement for the Annual Meeting with the SEC, the Company will mail the definitive 2008 Proxy Statement and a proxy card to each stockholder entitled to vote at the Annual Meeting. WE URGE INVESTORS TO READ THE 2008 PROXY STATEMENT (INCLUDING ANY AMENDMENTS THERETO) AND ANY OTHER RELEVANT DOCUMENTS THAT THE COMPANY WILL FILE WITH THE SEC WHEN THEY BECOME AVAILABLE BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION. Stockholders will be able to obtain, free of charge, copies of the 2008 Proxy Statement and any other documents filed by the Company with the SEC in connection with the Annual Meeting at the SEC’s website (http://www.sec.gov), at the Company’s website (http://www.nationalfuelgas.com) or by contacting Secretary, National Fuel Gas Company, 6363 Main Street, Williamsville, New York 14221, (716) 857-7000.
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Corporate Participants
Jim Welch; National Fuel Gas Company; Director of IR
Phil Ackerman; National Fuel Gas Company; Chairman of the Board & CEO
Dave Smith; National Fuel Gas Company; President & COO
Matt Cabell; National Fuel Gas Company; President, Seneca Resources Corporation
Ron Tanski; National Fuel Gas Company; Treasurer & Principal Financial Officer
Conference Call Participants
Jim Harmon; Lehman Brothers; Analyst
Carl Kirst; Credit Suisse; Analyst
Becca Followill; Pickering Energy Partners; Analyst
Chris Sighinolfi; UBS Securities; Analyst
Presentation
Operator: Good day, ladies and gentlemen, and welcome to the fourth quarter 2007 National Fuel Gas Company earnings conference call. My name is Lacey, and I will be your operator for today’s call. At this time, all participants are in a 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 our host for today’s call, Mr. Jim Welch, Director of Investor Relations. Please proceed.
Jim Welch: Thank you, Lacey, and good morning everyone. Thank you for joining us on today’s conference call for a discussion of last evening’s earnings release. With us on the call from National Fuel Gas Company are Phil Ackerman, Chairman and Chief Executive Officer; Dave Smith, President and Chief Operating Officer; and Ron Tanski, Treasurer and Principal Financial Officer. And from Seneca Resources Corporation, Matt Cabell, President. At the end of the prepared remarks, we will open the discussion to questions.
Also, since this call is being publicly broadcast, we’ll remind you today’s teleconference discussion will contain forward-looking statements as defined by the Private Securities Litigation Reform Act 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 which they are made, and you may refer to last evenings earnings release for a listing of certain specific risk factors. With that, we’ll begin with Phil Ackerman.
Phil Ackerman: Thank you, Jim, and good morning. Our quarter and full year’s numbers are great at $1.84 and $3.96 per share. We are raising our guidance for 2008 and National Fuel has great money in the bank type assets such as California heavy oil, the undeveloped Devonian Sands and pipeline and storage. Standing on the base of the utility, these should enable us to grow earnings and increase dividends for years to come. On top of that, the wild card of the Marcellus Shale may provide us with a huge growth opportunity if it can be successfully developed. In short, we had another great year and we are capable of having many more.
However, these are interesting times we live in. The company has nearly doubled the results of the S&P 500 over the last one, three and five years, periods of time when the S&P achieved returns that most investors would gladly take over the next five years. And yet certain shareholders claim our Board of Directors somehow has not adequately represented shareholder interest nor acted quickly enough. Although time may be money, haste for its own sake is seldom a virtue. Certain shareholders addressed the board at our February 15th, 2007 annual meeting, strongly suggesting that we sell our Gulf of Mexico assets and form an MLP of our California properties. Our history since February reinforces our belief that experienced operation and management of assets is generally preferable to a quick sale or financial engineering. In February, our Gulf of Mexico production was 40 million cubic feet equivalent per day. Today it is 47 million. In February, the price for California heavy oil was $50.61. Today it is over $80. Had we acted in haste, both these significant profit enhancements would have been lost to shareholders.
Most of you are aware that New Mountain Ventures has filed lengthy proxy solicitation materials, and I know that you must have many questions about the content. A complete discussion of the weaknesses of their claims is beyond the scope of this call, since a fair critique will require a lengthy filing of our own. Suffice it to say that every member of senior management has an overwhelming interest in the performance of our stock through both options and direct share ownership. In short, if New Mountain’s claims were consistent with our own knowledge and experience, we would be implementing them. Yesterday our utility, National Fuel Gas Distribution Corporation, filed a petition with the Pennsylvania Public Utility Commission seeking to ensure that New Mountain complies with that state’s laws regarding acquiring control of a utility. Pennsylvania utility law requires that if an entity is pursuing a controlling interest, either directly or indirectly, in a regulated public utility, then it must first secure a certificate of public convenience. The requirement is designed to give the public and the Public Utility Commission an opportunity to determine if an entity is qualified to manage a utility. Our Pennsylvania utility serves more than 200,000 customers in western Pennsylvania and has provided safe and reliable natural gas service to its customers for more than 100 years. The company is requesting that the PUC commence an investigation to assure that no violations of the public utility code have occurred.
As I indicated on our last earnings call, we’ve been working with Morgan Stanley for months on evaluating whether the MLP structure is appropriate for our pipeline and storage assets. We recognize that, at least in theory, there are inherent tax advantages to the MLP structure. However, in our case, the tax leakage caused by the relatively low tax basis of our midstream assets erodes much of the benefit to National Fuel. An additional and significant concern to us and to our state regulators is the needs of our state utility customers because of the integration of our pipeline and our utility. As most of you know, the pipeline and storage operations of Supply Corporation and the utility operations of Distribution Corporation are highly integrated and mutually dependent upon each other. They share common personnel and from a practical perspective are operated as one system. Considering the severely tax impacted benefits of the pipeline and what we perceive as a potentially significant risk on the utility side, we are unconvinced that a pipeline MLP makes sense from a total shareholder perspective. To the best of our knowledge, none of the MLPs created to date contain midstream assets that are as highly integrated with an LDC as ours are. We are discussing these concerns with our MLP counsel as well as our state regulatory attorneys. We will be reviewing the subject again with our board in the near future and anticipate a final decision at that time.
We are also evaluating whether an MLP might work for certain E&P assets, particularly our California oil properties. Our greatest concern in this area is sustainability. Given the natural decline curve of oil and gas properties, new long lived reserves must be constantly added to an upstream MLP in order to merely sustain its cash distributions, much less grow them. Given the significant premiums being paid for long-lived MLP friendly reserves, we are skeptical that upstream MLPs can be fueled solely through acquisitions over the long-term. Should our Appalachian acreage prove to be as prolific as we all hope, the development of that resource might eventually sustain an MLP, but it is premature to count on that.
During my time as Chairman of National Fuel, I’ve focused on board recruiting and bringing a geographically diverse array of obvious gas industry experts to the board including two former Chairs of the American Gas Association, the former Chair of Questar, the former CFO of Key Span and a resident of Southwestern New York who actually made his living as an Appalachian producer before National Fuel bought his company. These people have made the NFG board the best and the strongest in the industry, composed of people whose depth of experience permits them to quickly get to the heart of issues without the need for expensive explanation. These people have served their own shareholders well for a long period of time, and they have served our shareholders in an exemplary fashion as evidenced by our stock performance and record earnings. I’m optimistic about our assets, our people and our future. To paraphrase Joe Namath, I can’t wait until tomorrow, cause we get better looking every day. With that, I’ll turn it over to Dave Smith.
Dave Smith: Thank you, Philip, and good morning to everyone. As Phil said, the three months ended September 2007 was yet another outstanding quarter, and it capped an exceptional fiscal year for the company. For both the quarter and the fiscal year, each of our major segments posted results that met or exceeded our expectations. Excluding non-recurring items, our 2007 earnings were 10% higher than they were in 2006. More importantly, even at the low end of our guidance, we expect 2008 earnings will be at least 10% higher than they were in 2007. The market has recognized and rewarded that strong performance. As Phil said, over the past year, National Fuel shares have produced a total return of 32%, twice that of the S&P 500. While we’re proud of our accomplishments, we’re certainly not content to rest on our laurels. We continue to work diligently to improve upon areas of concern and to take advantage of opportunities to grow the company, with a view toward increasing long-term shareholder value. We expect much of that growth to come in the pipeline and storage segment and also in the E&P segment.
As I’ve said in the past, expansion of pipeline and storage segment is a major priority for National Fuel, and the Empire Connector is the first of what we hope and expect would be a number of pipeline and storage projects. We broke ground on the Empire Connector in early September and expect to complete at least 20 miles by December 2007. The project is on budget and on schedule. To date we’ve spent a little more than $20 million and expect to spend another $30 million by the end of this calendar year. We remain on track for a November 1st, 2008 in-service day. Looking beyond the Empire Project, earlier this year Supply Corporation held an open season to assess market interest in additional west to east capacity. The results of the open season were very encouraging and led us to propose a new pipeline project we’re calling the West to East Project, which would be a 324-mile pipeline from the terminus of the Rockies Express at Clarington, Ohio to the Millennium Pipeline in Corning, New York. The proposed pipeline, approximately 75% of which would be built on existing rights of way, would be designed to move approximately 550 to 750 million dekatherms of Rockies gas per day. It would also be able to accommodate volumes from local production areas. Indeed it would be laid through Seneca’s Appalachian acreage and Cove Point volumes arriving at Leidy. As you know, there are many competing projects in this area, but we anticipate that the development of associated additional Supply storage capacity, both by way of enhancement of existing storage and the addition of new storage, will set our project apart from the rest. If all goes well, we hope to sign precedent agreements with potential anchor shippers early in 2008. After that, we’ll complete our design and engineering analysis and conduct a binding open season. We will keep you up to date as the project progresses.
Turning to the exploration and production segment, we’ve taken a number of steps that have strengthened Seneca and bode well for the future. First and foremost, we’ve added significant talent, including our new President, Matt Cabell, who you’ll hear from this morning, and John McGinnis, our Senior Vice President of Exploration and Development, who we hired from Dominion and who has significant Appalachian experience. In Appalachia we’ve added 17 employees in the last year alone, including four recently hired geologists. We’ll be adding three more this year. In short, we’re confident that we’re assembling the best team to move Seneca forward.
As you know, we’re pleased with the sale of our Canadian properties, not only because they did not perform to our expectations, but because we realized a sizeable gain. Perhaps more importantly, the sale allows Seneca to focus more attention and where appropriate, more resources, on areas of greater potential. Obviously, as is evidenced by the additional hires I noted previously, Appalachia is at the forefront of that potential. As a result, we’ve significantly accelerated our drilling program in the upper Devonian and will continue to accelerate drilling, but to do so in a considered, comprehensive, and sequential manner that recognizes the complex geology of the region, an approach that was clearly validated by the recently completed 3-P reserve study by Netherland and Sewell. In addition, we have initiated activity in our extensive Marcellus Shale opportunity with a partner, EOG, who from a number of perspectives including technical, financial and contributed acreage, brought the most to the table. We are very comfortable with that decision and Matt will update you on the progress that has been made to date and our plans for the next year.
We also continue to refine our efforts in the Gulf of Mexico and we’ve had some recent success. In the past, we employed more of a shotgun approach to our exploration program. We drill a large number of wells in different areas of the Gulf. While we have had overall success over time, in recent years our finding costs have admittedly been high and we only occasionally developed an in depth knowledge of a particular area. Matt, who has a great deal of experience in the Gulf and who was successful there heading up exploration programs at Texaco and Marubeni, prefers more of a rifle shot approach — one that focuses on the areas where we have expertise and where we’ve had past success. We’re confident that with our new management team in place, with this different approach, that we will lower our finding costs and improve our returns in the region. If we do not, as we did in Canada, we’ll re-evaluate our entire position in the Gulf.
Before turning the call over to Matt, I’d like to address the shareholder recommendation that we sell our gas marketing company, National Fuel Resources, because they suggest it is non-core. Simply put, we disagree, and can only assume the recommendation is based on a lack of understanding of that business and of NFR’s activities. While NFR has indeed been expanding its business on contiguous LDC markets to our east, most of NFR’s business is highly integrated into our utility and pipeline system. It is presently one of the largest, if not the largest retail marketer on our utility system, serving our own utility customers and is the third largest customer on our pipeline and storage subsidiary, Supply. In addition, it is a large customer of Empire. Clearly it is core and the financial results of NFR have been strong, consistent and incremental to earnings. Those earnings have been achieved with modest capital investment, and because NFR doesn’t speculate, with very, very little risk. Needless to say, we have no intention of selling NFR. With that, I’ll turn the call over to Matt for a comprehensive update of Seneca’s activities. Thank you.
Matt Cabell: Thanks, Dave. Good morning. Let me start by saying that fiscal 2007 was a good year for Seneca Resources. First of all, we increased our U.S. production to over 39 BCFE. Secondly, we sold our Canadian operations for $232 million or $4.75 per MCFE. And most notably, we continued to accelerate our drilling program in Appalachia, growing our East Division proved reserves by 32%. As we announced in our October 11 press release, in Appalachia we drilled 233 wells and added 33 BCF of proved reserves. That’s five times our annual East Division production. We are extremely pleased with these results and plan continued acceleration of our drilling program with 280 wells planned for fiscal ‘08. While we do have aggressive growth plans, I must stress the importance of balancing the increased drilling pace with detailed geologic mapping and continuous integration of new drilling results. We will continue to accelerate our drilling pace at a rate which will allow us to achieve that balance and therefore maximize the value of our assets.
In addition to our outstanding growth in the upper Devonian, we have now drilled three vertical wells for the Marcellus Shale and have recently drilled our first Marcellus horizontal well with our joint venture partner, EOG. The horizontal has been completed and fracked with testing planned for next week. So far, all indications are positive. For fiscal ‘08, we may drill up to 18 additional Marcellus wells, 10 of them horizontal, and with significant success we could do more. We are also seeing industry activity in the Marcellus heating up. On trend to our acreage, another operator has reported the results of their first three Marcellus horizontal wells with initial production rates ranging from 1 million to 3 million cubic feet per day, per well.
Also in the October 11 press release, we disclosed the results of Netherland Sewell’s analysis of undeveloped proved, probable, and possible reserves on our Appalachia acreage. As we pointed out in the release, Netherland Sewell would only classify acreage as proved, probable, or possible if that acreage was within close proximity to wells with reliable production data. Therefore, the majority of our acreage was outside of the 3-P area. Let me now address some important differences between the report by Netherland Sewell and the projections made by New Mountain. At the suggestion of New Mountain, I met with Schlumberger in Pittsburgh. I was told that Schlumberger had not been released by New Mountain to discuss their study. However, the Schlumberger manager was able to discuss what the report was and what it was not. Although we would still welcome a copy of Schlumberger’s study and the opportunity to discuss it with them, it is apparent that New Mountain’s analysis consisted of some simple calculations based on Schlumberger’s brief overview using very limited data. In the words of Schlumberger’s manager, their study was a 50,000-foot view and was nowhere near a reserves report. While the Schlumberger overview could have driven New Mountain to invest in NFG, under no circumstances should we consider using this limited analysis as a guide for our Appalachian strategy. That said, we believe that there is great potential in Seneca’s Appalachian acreage, and although it is hypothetically possible to drill 600 wells per year, it is not the way to create the most value. I know I have said this before, but it bears repeating. Only through detailed geologic work and continued integration of drilling results can we maximize the value of these assets and thereby maximize value for our shareholders. Our strategy and development plan are based on our proprietary data, our ongoing geologic work, and the extensive knowledge and expertise of our geologists and engineers. So long as we continue to follow our strategic plan, we will have great success in developing our Appalachian properties.
Let me continue by pointing out that Netherland Sewell’s estimated EUR per well is completely consistent with our drilling results. In fact, their EUR estimates are simply an average of the EURs for Seneca’s economic wells in each area. By definition, subeconomic wells are left out, because only economic wells can be classified as PUD, probable, and possible. Any operator will always have a tail of subeconomic wells that are produced, and these bring down the average of the program. In most areas, Seneca’s EURs per well are equivalent to or somewhat better than our competitors.
I’d also like to point out that although in some previous years we may have been less active than other operators, in fiscal 2007, our Appalachian reserve growth was 32%, far higher than the average growth rate of most competitors over the last several years. In fact, our PDP reserve growth alone at 20% was far ahead of the pack. Contrary to what some might lead you to believe, Seneca is one of the leading drillers in Pennsylvania and quite possibly the leading company in terms of 2007 Appalachian reserve growth through drilling. Rest assured we are constantly evaluating and modifying our long-term strategy for Appalachia. As you can see, our growth plans are aggressive and our expectations are high.
Moving on to the Gulf of Mexico, the highlight of our fiscal 2007 program was the drilling of the High Island 24L — North Well and the subsequent development of the two well field. Production commenced on October 18th. We’re currently producing approximately 70 million cubic feet equivalent per day, which is 19 million cubic feet equivalent per day net to our revenue interest, or 18% of our company-wide production. Over the past several months, we’ve had many questions concerning our Gulf of Mexico business, and I would like to take this opportunity to briefly discuss how our Gulf of Mexico strategy has changed and why we intend to continue our operations in this division. First of all, Seneca has a long history of profitability in the Gulf of Mexico. Over a period of 17 years, we’ve invested $960 million and had net positive cash flow of $1.3 billion. This 17-year cash flow stream has an internal rate of return of 19%. Secondly, we have a very large 3D seismic database that has allowed us to build a core acreage position on trend to our recent success. Finally, because the results of the past several years have been inconsistent, our Gulf of Mexico strategy has changed, which Dave mentioned earlier — changed significantly from what it was a year ago. Our strategy is far more focused and will leverage off of our recent success. Our expectation is a rate of return that is competitive with other divisions and continued production growth from 2007 to 2008. For fiscal 2007, Gulf of Mexico had total net production of 14.7 Bcfe, an 11% increase over fiscal 2006. In the fourth quarter, we produced 3.5 Bcfe. At today’s rate of 47 million cubic feet equivalent per day, a full quarter of production would be equivalent to 4.2 Bcfe or 20% more than the fourth quarter of 2007. Also in the fourth quarter, we were the high bidder on five of our eight bids at the central Gulf of Mexico lease sale, all within our core acreage position.
Moving onto the West Division, California continues to provide stable and predictable production with excellent cash flow. Fiscal 2007 production was 18.3 Bcfe and we expect a similar production level for fiscal ‘08. For fiscal 2007, we drilled 57 new producers in California including proved undeveloped locations and Midway Sunset acceleration wells. The increased steam injection at Midway Sunset has begun to show its effects, with September oil up 360 barrels per day versus May, when increased steaming began. That’s an 8% increase.
To conclude my review of Seneca’s fiscal 2007 results, I’d like to discuss our year-end proved reserves. Our total proved reserves as of September 30th, 2007 are 491 Bcfe as compared to 581 Bcfe on September 30th, 2006. The changes in reserves can be attributed to 47 Bcfe of production, 31 Bcfe of net negative revisions and 49 Bcfe from the sale of our Canadian operations, offset by 37 Bcfe of discoveries and extensions. In the U.S. we replaced 90% of our production through drilling. But as I mentioned last quarter, the reserve audit by Netherland Sewell resulted in a net 42 Bcf negative revision, or 7% of our U.S. reserves. As expected, the Netherland Sewell revisions were primarily in the West. Even with these changes, including the sale of our Canadian operations, the net present value of Seneca’s reserves at year-end has increased by more than $100 million since last year. With Netherland Sewell’s initial audit behind us, we expect future companywide downward revisions to be rare and upward revisions to become much more common.
Looking forward to the new fiscal year, I am very excited about our program for 2008. We expect to continue to grow our U.S. production with 15 to 20% growth in Appalachia, 5 to 10% in the Gulf of Mexico and flat to only a very slight decline in California. Overall, the midpoint of our production guidance is a 4% increase to U.S. production. Our refocused Gulf of Mexico program includes several high potential exploration wells on trend to our recent success and, as I mentioned earlier, we expect to increase our shallow drilling in Appalachia to 280 wells, as well as drilling up to 10 horizontal wells in the Marcellus Shale. Our proprietary database combined with the extensive knowledge and expertise of our E&P team should continue to deliver outstanding returns to our shareholders in 2008 and beyond. Now I will turn it over to Ron.
Ron Tanski: Thanks, Matt. I only have a few items regarding our earnings numbers before we take questions. Our reported GAAP earnings of $3.96 per diluted share were $1.50 above the high end of the range of the guidance that I gave during our earnings call in August. Most of the $1.50, or $1.41 of that amount, came from Seneca’s sale of its Canadian Exploration and Production operation. Approximately $0.03 came from lower than forecast operation and maintenance expense in our utility and pipeline and storage segments. Higher than forecast prices on our efficiency gas sales made up $0.02 per share and higher oil prices in the Exploration & Production segment made up the remaining $0.04 difference between guidance and reported GAAP earnings. Our earnings release provides all the details for the quarter-to-quarter and year-to-year comparisons, so I won’t spend time on the call to repeat that information.
Looking forward to 2008 earnings, we’ve increased our guidance to a range between $2.50 and $2.70 per diluted share. As I mentioned last quarter, the biggest driver of the increase in earnings from 2007 to 2008 is increased commodity pricing after hedging in our Exploration and Production segment. We increased the guidance range since our August call because Seneca has layered in more hedges at prices higher than those embedded in our base forecast. Our hedged volumes for fiscal 2008 are listed on page 26 of the release. Using the midpoint of our production guidance, we now have 50% of 2008 production hedged. Having more production hedged also required us to reduce the range of earnings sensitivity related to unhedged production listed on page 29 of the release. We’ve also finalized our capital expenditure budget for 2008. Our spending budgets are $59 million in the utility segment, $146 million in the pipeline and storage segment, between $151 million and $159 million in the exploration and production segment, and $1 million in all other for an overall CapEx range of $357 million to $365 million. We made no major structural changes in the underlying business segment that should cause any analysts to change their underlying models. We do, however, expect to receive an order next month from the New York Commission in our New York rate proceeding. As we’ve previously announced, the Commission allowed us to have an early implementation of our conservation incentive program. Our customers that install energy efficient appliances after November 1st may be eligible for rebates, and we’ve listed those on our website. Any other rate changes that are approved by the Commission will go into effect right around the first of January. With that, operator, we’re ready for questions.
Question & Answer
Operator: (OPERATOR INSTRUCTIONS) Please stand by for your first question. The first question comes from the line of Jim Harmon with Lehman Brothers.
Jim Harmon: Good morning. I’ve got three questions, probably for Matt. The first is, if we could look at the Gulf of Mexico, we had a lot of focus on Appalachia. How would you — we’re seeing production growth out of that region, but we haven’t really seen reserve growth. So what in your mind over the next 12 to 18 months are you going to be doing with that region? Is it more for production or will we see reserve growth?
Matt Cabell: That’s a good question. I guess the way I would look at how we’re going to measure success — it’s going to be based on finding and development costs and on the rate of return that we estimate for the wells that we drill over the course of the year. So, at the rate of capital spending versus the production we’re going to have this year, it might not be any significant reserve adding activity. But, yet, it will be a value adding activity.
Jim Harmon: Okay, fair enough. Second question on rising gas environment and oil environments. You always get asked does it make sense to hedge [volumes]? I know it took a while for you to get your ability to hedge oil, I was wondering if at triple digit prices, does it make sense to lock more of that in? Because I didn’t see any new hedges in last night’s release.
Matt Cabell: I’m going to let Ron take that one.
Ron Tanski: We did have some new hedges from the last quarter’s release, Jim, but as I mentioned on the call, we have 50% hedged right now. I think as you say—
Jim Harmon: Oil?
Ron Tanski: Yes.
Jim Harmon: Okay, my mistake.
Ron Tanski: Yeah, that’s on page 26 of the release I believe.
Phil Ackerman: We’ll double check that.
Ron Tanski: We ran through those numbers. Right now we’re about 50% hedged overall. And as you say, given the rising prices right now, we’re comfortable with that.
Jim Harmon: Okay. It’s possible I missed something on a 30-page release. The last question is, assuming everything hits all cylinders in Appalachia, can Matt or anyone talk about what the infrastructure is like to handle the volumes and what would need to be done in order to make that operation as smooth as possible?
Matt Cabell: That’s a continuous challenge for us, is building the gathering system at a pace that will keep up with our drilling program but it’s not a challenge that can’t be met. It’s just one that is very much part of our emphasis.
Dave Smith: Jim, on the — this is Dave — in the upper Devonian, it’s just kind of an incremental keeping on building it out. Certainly if the Shale takes off like it might, we’ve already put in place the structure which would revolve around a number of limited partnerships. I mentioned previously that Duane Wassum has been heading that up, not only talking to Seneca but to a number of other producers in lining up what we need to do to in order to essentially run that as a separate business. Right now, it’s not needed with respect to the present Appalachian production. But certainly if the shale takes off, that’s a business we will be getting into. And, we have all the regulatory work, all the corporate work, all the legal work lined up and ready to go.
Jim Harmon: Okay.
Phil Ackerman: Jim, let me just add, this is Phil. If the Shale takes off as Dave says, it goes beyond mere gathering. It’s a different order of magnitude then. We wind up needing takeaway capacity to get all that gas completely out of the region. Then you’re looking at some significant transmission facilities as well.
Jim Harmon: Okay, great, thank you very much.
Operator: Our next question comes from the line of Carl Kirst with Credit Suisse. Please proceed.
Carl Kirst: Good morning, everybody. Three questions too, first one’s pretty easy, I didn’t get a chance to scroll down the numbers. Matt, I think you had run through what the production growth expectations were by region, could you —
Matt Cabell: Certainly, certainly. 15 to 20% in Appalachia, 5 to 10% in the Gulf of Mexico and flat to a slight decline in California.
Carl Kirst: Okay. Great. The second question really was kind of one keying off of Jim’s and your answer to him with respect to the Gulf is — F&D is certainly one of the metrics that you’re looking at to build value. Can you, I guess, two parts to this question — can you, with 2007 results here, is it possible to break out F&D by region for the three remaining regions, and two, when you’re saying for the Gulf of Mexico as we look forward, can you help us out with where you think F&D should be if you’re as successful as we all hope you are?
Matt Cabell: Let me answer that last part first and say that $4 is our target. With the high rates that we get in the Gulf of Mexico, $4 finding and development costs provides very economic projects. In terms of what our F&D — you’re asking about what was our F&D —
Carl Kirst: F&D by region, right.
Matt Cabell: For the year? I don’t have that off the top of my head. In the gulf it would have been relatively high, but I should caveat that by saying that we have significant probable reserves added in, but not disclosed, but added in the High Island 24L area — which if you included those, the finding and development costs wouldn’t look too bad.
Carl Kirst: Actually off of that, maybe the easier question is just for a company as a whole on the E&P side, as you look at your PV10 calculation here for year-end, what — in that calculation, do you have an estimate for what development costs, future development costs would be?
Matt Cabell: Not at my fingertips.
Carl Kirst: I can follow-up offline.
Phil Ackerman: We’re scurrying around here looking for it, maybe we can go to the next question.
Carl Kirst: Well, the —
Phil Ackerman: Actually we’ve got, let’s see... Well, this needs some refinement, Carl, because it has also all the P&A costs.
Carl Kirst: Okay.
Ron Tanski: So we’re going to have to refine this a little bit more.
Phil Ackerman: We’ll get back to you on that one.
Carl Kirst: Fair enough. Last question was simply on the West to East potential project coming up here. And I understand (inaudible) engineering and what the final size may or may not be, but is it possible — 324 mile pipeline through that area even though it’s on existing right-of-way I would think is not going to be a small project. Do you have any sort of book-ends of what size we might be talking about — whether or not that would then require you to take on a partner? How should we think about that?
Dave Smith: We’d be looking at 24 to 30 inch depending on what the market calls for. It is very helpful to have the existing rights as you recognize. And Carl, there are about 15, depending if you count the “over–the-top” projects, there are about 15 projects out there and certainly not all, or most of those projects are going to move forward. So my — we would not need to partner up, but I mean, we’re certainly not ruling that out. We have had discussions with other, with other pipelines and others about potentially partnering up. So, I mean, that certainly is something that we would consider, although at this point, we don’t regard it as necessary.
Carl Kirst: Okay, no, that’s helpful. As far as project capital cost size, should we be thinking of $1 million to $2 million a mile or could it be significantly less than that considering the—
Dave Smith: You’d be talking — estimates would range between $630 million and $725 million.
Carl Kirst: Okay.
Dave Smith: For the whole thing.
Carl Kirst: Okay. Appreciate the color. Thanks, guys.
Operator: (OPERATOR INSTRUCTIONS) Our next question comes from the line of Becca Followill with Tudor Pickering. Please proceed.
Becca Followill: Hello. First question is on the Marcellus. What is your disclosure going to be on that? Are you just going to disclose individual wells or give us periodic updates or are you going to wait until you have a significant amount of information? What’s the plan there?
Matt Cabell: Well, Becca, we recognize that all our shareholders are anxious to hear about our drilling results as soon as possible. While we recognize that, we’ve got to balance the value of that confidentiality with the benefit derived by disclosing those float rates and reserves. So the play is becoming very competitive. This is a long way to say, we don’t know yet exactly what we’ll disclose.
Becca Followill: Are you leasing at this point?
Matt Cabell: Well, that, that again goes into that same very question about competitive issues and I guess, I guess what I would say is — the success of the play is certainly going to drive our leasing activity and our leasing plans.
Becca Followill: Okay, thank you. Second question on, you mentioned, Phil, that, that the rebuttal to New Mountain would take a more lengthy document. I assume that you guys at this point are going to file, make another filing that rebuts New Mountain, is that correct?
Phil Ackerman: That’s right.
Becca Followill: And the timing for the annual meeting — would we expect that to be the normal time?
Phil Ackerman: It’ll be in February.
Dave Smith: Well, the annual meeting, but are you asking, Rebecca, when the rebuttal would —
Becca Followill: No, when the annual meeting – assuming it’s at the normal time. Finally back to the pipeline question, I think this is maybe the fifth or the sixth proposed pipeline that’s coming from the terminus of Rex. Why does this project have a competitive advantage over the others?
Dave Smith: There’s at least five or six. Number one, we were at it very quickly. I think we might have been the first out of the box. Number two, we do have the existing rights. Number three, fortunately because of our geographic area, there’s an awful lot of potential storage right on the — where we’re proposing to lay the line. So I think when you add all of that together, we’re in a relatively good position. That’s not to say, some of the other projects look interesting as well, but I think when you put it all together, we’re in a pretty good position. And we’ll know, we’ve been out talking with the customers at some length for some time, and we’re coming fairly close to a conclusion.
Becca Followill: Great, thank you. One last question on the New Mountain filing they made. They talk about the Schlumberger PV10 value. Do you think that that is an accurate assessment?
Phil Ackerman: I think we’ve said right along and Matt’s said we think it was a very cursory analysis based on numbers that don’t seem to agree with ours. The numbers that they appear to use in terms of reserves per well simply don’t agree with the reserve numbers that we come up with and with our actual experience. Seems to have been based on a different portion of the basin. And if we —
Matt Cabell: I’m going to add —
Phil Ackerman: Wish that number was there.
Matt Cabell: I’ll add one thing to Phil’s comments, Becca, that is beyond on proved reserves as you well know, particularly when you get outside of 3-P reserves and you’re talking about prospective resources, a recognition of risk is appropriate and required when you value those additional resources, and I guess my question would be, have they recognized that risk properly?
Becca Followill: Exactly, okay. I’m sorry, I remembered one more question. On the California reserve write down, I know there’s an auditor taking a look at it, but what were the big pieces behind that significant change in the reserves?
Matt Cabell: The vast majority of it was a change in our recovery factor.
Becca Followill: Can you give us metrics on from what to what?
Matt Cabell: I’m going to say from 80% to 70% but that’s a very rough —
Becca Followill: Ballpark. Great, thank you gentlemen.
Ron Tanski: If Carl’s still on the line, the CapEx, for future CapEx that’s built into our PV10 numbers, approximately $220 million.
Operator: And our next question comes from the line of Shneur Gershuni with UBS. Please proceed.
Chris Sighinolfi: Good morning guys. It’s actually Chris. Most of my questions have been answered, but I have one quick one. Given the recent strength in the stock and healthy CapEx levels for 2008, what’s the status of your share buyback?
Phil Ackerman: The share buyback remains authorized by the board. The number of shares that have actually been bought back are disclosed in the 10-Q.
Ron Tanski: We didn’t buy any shares during the last quarter, Chris.
Chris Sighinolfi: No, for sure, Ron. I’m just curious, looking forward is that — is that something to kind of carry on or are you, I mean — looking into the future at these levels, at these CapEx levels, I guess, the quarter’s buyback kind of something you’re targeting?
Ron Tanski: Well, I guess one way to look at it, yes, share buybacks are a competing use of capital, and, as Matt said, if the Marcellus takes off, we’d be looking at using more dollars there and investing it in the ground rather than buying back shares. But we’ve said it before, with respect to the share buyback, we’ve got board authorized targets and volumes and amounts and pricing that we’re not going to disclose beforehand.
Chris Sighinolfi: Okay. Well, thank you guys very much.
Operator: At this time there are no questions in queue. I’d now like to turn the call back to Jim Welch for closing remarks.
Jim Welch: Thank you, Lacey. At this point we’ll conclude our call for today. We’d like to once again thank everyone for taking the time to be with us today. A replay of this call will be available in about one hour on both our website and by telephone and both will run through the close of business on Friday, November 16th. Our website address is www.nationalfuelgas.com. The telephone replay number is 1-888-286-8010 using passcode 19287282. This concludes our conference call for today. Thank you and good-bye.
Operator: Thank you for your participation in today’s conference. This concludes your presentation. You may now disconnect. Good day.
Certain statements contained herein, including those regarding future earnings, developments and operational results, and those which use words such as “anticipates,” “estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” and similar expressions, are “forward-looking statements” as defined by the Private Securities Litigation Reform Act of 1995. Forward-looking statements involve risks and uncertainties, which could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. The Company’s expectations, beliefs and projections contained herein are expressed in good faith and are believed to have a reasonable basis, but there can be no assurance that such expectations, beliefs or projections will result or be achieved or accomplished. In addition to other factors, the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements: changes in laws and regulations to which the Company is subject, including changes in tax, environmental, safety and employment laws and regulations; changes in economic conditions, including economic disruptions caused by terrorist activities, acts of war or major accidents; changes in demographic patterns and weather conditions, including the occurrence of severe weather, such as hurricanes; changes in the availability and/or price of natural gas or oil and the effect of such changes on the accounting treatment of derivative financial instruments or the valuation of the Company’s natural gas and oil reserves; impairments under the Securities and Exchange Commission’s full cost ceiling test for natural gas and oil reserves; changes in the availability and/or price of derivative financial instruments; changes in the price differentials between various types of oil; inability to obtain new customers or retain existing ones; significant changes in competitive factors affecting the Company; governmental/regulatory actions, initiatives and proceedings, including those involving acquisitions, financings, rate cases (which address, among other things, allowed rates of return, rate design and retained gas), affiliate relationships, industry structure, franchise renewal, and environmental/safety requirements; unanticipated impacts of restructuring initiatives in the natural gas and electric industries; significant changes from expectations in actual capital expenditures and operating expenses and unanticipated project delays or changes in project costs or plans, including changes in the plans of the sponsors of the proposed Millennium Pipeline with respect to that project; the nature and projected profitability of pending and potential projects and other investments, and the ability to obtain necessary governmental approvals and permits; occurrences affecting the Company’s ability to obtain funds from operations or from issuances of short-term notes or debt or equity securities to finance needed capital expenditures and other investments, including any downgrades in the Company’s credit ratings; uncertainty of oil and gas reserve estimates; ability to successfully identify and finance acquisitions or other investments and ability to operate and integrate existing and any subsequently acquired business or properties; ability to successfully identify, drill for and produce economically viable natural gas and oil reserves; significant changes from expectations in the Company’s actual production levels for natural gas or oil; regarding foreign operations, changes in trade and monetary policies, inflation and exchange rates, taxes, operating conditions, laws and regulations related to foreign operations, and political and governmental changes; significant changes in tax rates or policies or in rates of inflation or interest; significant changes in the Company’s relationship with its employees or contractors and the potential adverse effects if labor disputes, grievances or shortages were to occur; changes in accounting principles or the application of such principles to the Company; the cost and effects of legal and administrative claims against the Company; changes in actuarial assumptions and the return on assets with respect to the Company’s retirement plan and post-retirement benefit plans; increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide post-retirement benefits; or increasing costs of insurance, changes in coverage and the ability to obtain insurance. The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date hereof or to reflect the occurrence of unanticipated events.
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