National Fuel Gas Co (NFG) 2008 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the first-quarter 2008 National Fuel Gas Company earnings conference call. My name is Francis and I will be your coordinator for today. At this time, all participants are in listen-only mode. We will be facilitating a question-and-answer session toward 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, Jim Welch, Director of Investor Relations. Please proceed.

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

Also since this call is being publicly broadcast, we remind you that today's teleconference discussion will contain forward-looking statements as defined by the Private Securities Litigation Reform Act of 1995. While National Fuel's expectations, beliefs and projections are made in good faith and are believed to have a reasonable basis, actual results may differ materially. These statements speak only as of the date on which they are made, and you may refer to last evening's earnings release for a listing of certain specific risk factors.

With that, we will begin with Dave Smith.

Thank you, Jim, and good morning to everyone. Phil Ackerman was scheduled to speak first this morning, but unfortunately he was delayed in the Chicago airport and is unable to be here.

First-quarter net income,. a consolidated $0.82 per share, was yet another record for the company. All of our major operating segments reported improved operating results. We are certainly pleased with that performance. More importantly, fundamentally National Fuel is in terrific shape. Our balance sheet is strong, our earnings are at record levels, and we expect to continue to grow the dividend. These achievements are a testament to the strength of our balanced, diversified and integrated business model.

Over the years we have assembled a portfolio of real assets that are worth more together than they are apart. We have stood by that strategy in the past, and we will continue to stand by that strategy in the future. From the wellhead to the burner tip, the building blocks are in place for us to continue to grow the Company and to increase shareholder value, not only in the short-term but over the long-term.

We are also pleased to have settled the proxy contest with our largest shareholder, New Mountain. At the end of the day, we both recognize the tremendous potential in our Appalachian acreage. While we may differ on how to best exploit that asset and we may differ with respect to certain other proposals, we believe that a cooperative effort will better serve our shareholders, our customers and our employees.

Turning now to the segments, Exploration and Production continues to be the immediate driver of earnings growth. The aggressive development of our Appalachian acreage remains a top priority, and we are pleased with the pace of our drilling in that region. Seneca's Appalachian production for the quarter, which for the first time surpassed 2 BCF, is up 35% over the prior year's quarter. We are on track to drill the 280 Upper Devonian wells we have planned for this year, and expect to drill between 330 and 350 wells in 2009.

While that is more than double the level we drilled just last year, we are exploring opportunities, within the bounds of our development strategy, to increase the pace of our drilling activity even further in future years.

With regard to the exploration of the Marcellus Shale that underlies most of our vast Appalachian acreage, we with our partner EOG, continue to make progress and remain very optimistic about the future of that play. It has the potential to provide continued earnings growth for many years.

In the Gulf, Seneca's new and more focused approach and our recent discovery at High Island 24L gives us reason to be cautiously optimistic. We will continue to pursue similar opportunities. Nevertheless, as we have indicated in the past, we intend to keep a watchful eye on those operations and are in the process of finalizing performance targets for that division. Simply put, if we don't meet our objectives, which we will review with the Board later this month, we are going to consider a sale of those assets. Matt will provide additional details on all of Seneca's operations.

In the Pipeline and Storage segment, during the fall construction season, we completed over 18 miles of the Empire Connector project, including numerous road crossings and a major directional drill under the Keuka Lake outlet. Construction will recommence when the weather permits, likely in the early spring.

To date, we have spent just about $45 million on the project and expect to spend another $132 million over the remainder of fiscal 2008 and into early fiscal 2009. Despite the widespread escalation in pipeline construction costs and the scarcity of pipeline contractors, we remain on time for a November 1, 2008 in-service date, and on budget.

Looking beyond the connector, we continue to pursue our proposed West to East project that would provide for new capacity from the Rockies Express and for increasing Appalachian production to Leidy and to interconnections with Millennium and Empire at Corning. We are working with an outside engineering firm to optimize the routing of that proposed line, utilizing largely existing rights-of-way and to refine our cost estimates.

Interest from prospective shippers has been strong, and hopefully by spring we will begin negotiating precedent agreements with anchor shippers. As we said in the past, we believe that the development of additional storage capacity will help set our West to East project apart from the many similar projects being pursued in the region.

To that end, one project the Supply Corporation is pursuing is an expansion of its East Branch and Galbraith storage facilities. Reservoir analysis suggests that these facilities could provide approximately 7 BCF of incremental storage capacity without the need for any additional base gas. We are now in the process of assessing the service facilities that will be needed to make the expansion a reality. Once that is complete, we will hold an open season for that capacity, probably, if all goes well, in conjunction with the West to East open season.

In summary, National Fuel's short and long-term prospects have never been better. The continued and accelerated development of our Appalachian acreage and the completion of the Empire Connector project as planned will be a significant source of immediate earnings growth. The Marcellus Shale and our additional pipeline storage expansion opportunities provide significant longer-term growth opportunities. And, as always, we are working to manage and improve our existing operations by, for example, implementing our revenue decoupling mechanism in our New York utility, and Ron will provide more detail on decoupling and on our New York rate case.

With that, I thank you for your attention and I'll turn the call over to Matt.

Thanks, Dave. Good morning, everyone. The fiscal '08 first quarter was a good one for Seneca, with U.S. production up 7% versus the first quarter last year, and successful exploration and development drilling in all three divisions. I'm going to discuss the details of each division's performance in a moment, but first I would like to review the strategic changes that we have made over the past year and touch upon where we are headed.

First of all, we've allocated a much greater share of our capital spending to our low-risk development drilling programs, both in Appalachia and in California. We've significantly increased our Appalachian drilling in 2007 and this year our East division will get the largest share of our E&P capital expenditures. In addition, in California we've implemented new drilling programs that will, for the first time in years, add new long life oil reserves to our California properties.

Second, we have sold our underperforming assets, specifically Canada. The Canadian division had not performed as expected and we felt that it would be difficult to add reserves and production at an acceptable cost.

And finally, we've adopted a more focused approach to exploration within the Gulf of Mexico; an approach that we feel can be successful and add value. Capital expenditures will be less than they have been historically, but with a more focused approach we can build a more consistent program. In fact, this approach is already paying off as I will explain later. In addition, we've begun divesting some marginal assets in the Gulf Coast division and will continue to do so as we identify properties that do not fit our program going forward.

With these strategic changes Seneca's performance should improve substantially. And in fact, the impacts of these changes are already evident in our outstanding first-quarter results and in our recent drilling success. Over the next several years you will see an increasing emphasis on low-risk drilling at Appalachian in particular. I expect finding and development costs to improve and East division production to grow significantly.

So let me start on the details with an update of Appalachia where our 2007 drilling program is beginning to be reflected in our production numbers. During the first quarter our East division production averaged over 23 million cubic feet equivalent per day, the highest level in Seneca's recent history and 37% over the same period a year ago. Our '07 development program resulted in 360% reserve replacement of our proved developed reserves and, including PUDs, 530% replacement of our total East division proved reserves, far superior to the majority of our peers. We currently have four rigs running in Appalachia and our drill program is ahead of where we were at this time last year.

In addition, we continue to ramp up our exploration of the Marcellus Shale with one horizontal wells currently being tested, a second horizontal well drilled but abandoned due to mechanical problems, and a third horizontal well drilling as we speak. We expect to have the first Marcellus horizontal well online within the next few weeks at a rate of 350 to 400 MCF per day. The well is currently shut in for a pressure buildup test to evaluate the possibility of a near well bore reservoir restriction that would explain the lower than expected rate. We expect to reach TD in the third horizontal well next week and that well will be completed in early March.

All of these initial exploration wells are paid for 100% by our partner, EOG. We maintain an override on any production from these initial exploration wells and we plan to participate at a 50% working interest once we believe commerciality is established or when development drilling begins.

And finally in Appalachia, we are now in a position to disclose the results of Netherland Sewell's analysis of prospective resources for our traditional shallow gas play. You may recall that Netherland Sewell's estimate of 3P reserves was 220 BCFE. As we pointed out in our October 11th press release, Netherland Sewell would only classify acreage as proved, probable or possible if it was relatively close to wells with reliable production data. Therefore the majority of our acreage was outside of the 3P area. Since then Netherland Sewell has completed their estimate of prospective resources and provided a statistical range of 400 BCFE to 1.0 TCFE with a most likely value of 670 BCFE.

One final comment on Appalachia. I think it is important for everyone to understand that although it may appear that New Mountain Vantage and National Fuel have differing views of our Appalachian position and the appropriate development strategy, fundamentally we are well aligned. We both recognize that in the current gas price environment our Appalachian position has great potential and much opportunity for future growth. Appalachia will continue to be the focus of our E&P efforts for many years and is expected to provide substantial earnings and shareholder value.

Now let's move to the Gulf of Mexico. Our first-quarter production averaged 41 million cubic feet equivalent per day, or up 8% from the previous quarter. The High Island 24L field came online in late October and is currently producing approximately 70 million cubic feet per day and 600 barrels of condensate per day. Seneca holds a 35% working interest.

Also our fiscal 2008 Gulf of Mexico exploration program is off to a great start with our first well finding over 100 feet of net pay in the first target. We are now partially through the second target and appear to have found additional pay. Seneca holds a 29% working interest. We have now drilled three consecutive exploration discovery wells in the Gulf of Mexico. We have also spud a new exploratory well in High Island Block 23L, only a couple of miles from our High Island 24L field.

As I said in my opening comments, our new focused approach is clearly paying off. With this new strategy our goals will be related to finding and development costs rather than growth or reserve replacement. We will spend less in the Gulf and, over time, the division will become a smaller share of our producing portfolio. However, we expect this smaller, more focused effort to have competitive finding and development cost, and a rate of return that is comparable to the other two divisions.

Moving on to California. In California we averaged 8,700 barrels of oil equivalent per day, up 6% versus last year's first quarter. We increased our steam generation capacity at Midway Sunset by 33% last summer, and the effect of increased steam injection is now apparent. Also of note, we have recently drilled five wells for the Marvic sand at Midway Sunset and the first two wells are now producing at a combined rate of 150 barrels of oil per day.

Just this morning I received a report on the third well and it appears that it will add another 60 barrels of oil per day. Once all five wells have been completed and are on production we will decide whether we will drill additional wells later this year. This is a new producing horizon for us at Midway Sunset and the program could add between 200,000 and 800,000 barrels of new reserves to our California base.

Historically in California we have focused on efficient low-cost operations. In fact, Barry and the West division team have managed to keep lifting costs nearly flat for years and well below industry average. Our capital has been spent on steam generation capacity and the drilling of PUDs and acceleration wells. What we are now adding to the mix are new reserve adding drill programs, such as the Marvic that I just mentioned. Although long-term production growth is unlikely in California, we hope to keep production relatively flat for at least several more years and a very slow decline thereafter.

Again, it's been a great quarter for Seneca. We contributed net income from continuing operations of $0.39 per share to the Company's consolidated earnings. Our production is up substantially and our exploration and development programs are off to an excellent start. We have high expectations for this fiscal year and beyond as we continue to implement the new initiatives that I've reviewed this morning. Now I'll turn it over to Ron.

Thank you Matt, and good morning, everyone. Looking at consolidated earnings, last evening's release detailing our first-quarter results was relatively straightforward with higher oil prices in our Exploration and Production segment that provided the largest component to the increase in this quarter's earnings compared to last year. GAAP earnings were also higher in the utility, energy marketing and timber segments, but it was the Exploration and Production segment that was the driver behind our record earnings.

On page 18 of the release you can see that oil prices after hedging were almost $29 per barrel higher than last year which caused the biggest boost to earnings. Higher natural gas commodity prices and increased production also contributed to the higher earnings. Average oil prices after hedging for the quarter were approximately $11 per barrel higher than the prices that had been built into our forecast and earnings guidance, while natural gas prices for the quarter were about a dime lower.

With a quarter of production under our belt and with approximately 57% of our remaining oil production for the year hedged and approximately 53% of our remaining natural gas production for the year hedged, we're in a position to raise the earnings guidance for the entire year by $0.10 per share. I'll remind everyone again that this guidance assumes that unhedged production in our forecast is priced out using the July 24th Nymex strip as modified by the average price differentials that we laid out in our third-quarter earnings release last August. To the extent that actual sales prices vary, our sensitivity table at page 21 of last night's release can give you an idea of the projected impact on earnings.

Moving from the Exploration and Production segment to the Utility segment, it was weather that was colder than last year in our New York jurisdiction plus a slight uptick in usage per account combined with a full quarter of higher base rates in Pennsylvania that explains higher utility earnings this year compared to last year. In the New York jurisdiction the Public Service Commission issued an order on December 21st that addressed the rate increase request that we filed in January 2007. While the order did not have a major impact on earnings for the first quarter, there are a couple of items worth noting for the future.

You may recall that when we filed our case over a year ago the total increase requested was $52 million; the approved increase ended up at $12.6 million, split between a $1.8 million base rate increase and a $10.8 million rate component to cover expenses associated with our conservation incentive program. As part of the rate order the New York Commission approved the implementation of a revenue decoupling mechanism where the recovery of our operating costs and margin is decoupled from customer usage.

We are now in a position to encourage our customers to conserve. Since the cost of the natural gas commodity is the largest component of our utility customers' bill the most effective way for our customers to reduce their overall heating expense is to burn less gas. Because of the Company's recovery of a majority of its operating costs had been tied directly to customer usage we could not fully recover our operating costs if customer conservation caused our throughput to decrease.

Our customers can see a substantial decrease in their bill by cutting back on their usage, and with the revenue decoupling mechanism the Company stands a much better change of recovering its operating expenses and margin through the revenue decoupling rate adjustments.

While we think the conservation incentive program and RDM are wins for both our customers and the Company, we think the low 9.1% return on equity authorized by the Commission is a bad deal for our shareholders. It's no consolation that the ROE is in line with awards to other gas utilities in the state and even 10 basis points higher than the recommended rate in ConEd's current electric case. The problem is that the New York Commission's ROE awards are at least 100 basis points below the average ROE provided to gas utilities across the U.S. during 2007.

I think the Commission needs to review its policies to make sure that utilities in the state can continue to attract investors and capital to maintain and develop critical infrastructure in the state.

One final note about the New York rate order. The Commission also approved a rate design change for our residential rates where a greater proportion of our overall revenue requirement will be recovered through our minimum charge and first usage rate blocks. This will have the effect, all else being equal, of shifting a portion of our customers' bills from the winter to the summer.

From a financial reporting segment, and for analyst's models, this change will reduce our second-quarter margin by approximately $8 million. That $8 million in margin will then be recovered through the third and fourth quarters.

Moving from the utility segment to the consolidated Company, you can see on the balance sheet at page 11 of last night's release that we had 83,946,575 shares outstanding at the end of December. Later on today when we file our 10-Q for the first quarter you'll note on the cover page that we report 83,526,251 shares outstanding at the end of January, or a decrease of a little over 420,000 shares. It's safe for you to assume that the decrease was the result of share repurchases made during the market dip last month under our authorized repurchase program.

And aside from that comment I'll revert to our standard protocol of saying nothing more about the repurchase details until we report on them in the second-quarter 10-Q. At this point there are no other changes to our forecast or earnings projections and that covers our prepared remarks so I'll ask the operator to open the lines for questions.

(OPERATOR INSTRUCTIONS). Wade Suki, RoundRock Capital.

Good morning, everyone. I have a couple questions for you. I wanted to get some clarity on the resource potential from Netherland Sewell. That does not include Marcellus potential, is that correct?

Correct.

Now, I'm interested -- we've seen some pretty good industry well results -- Range put out some pretty good numbers on their resource potential, I think last week Equitable put out some big numbers as well. I'm just curious when we might expect a similar disclosure from you guys. And I guess a follow-up to that is what are we waiting on here?

We're waiting on more well results before we're in a position to make any kind of resource potential projections. Range has got several wells producing; they're in a different position than we are.

All right. Is there a time frame that you hope to have some of this information available to disclose to investors?

You mean a time frame for when we plan to disclose our resource potential?

Yes.

No, no, there isn't any planned time frame for that. I think I would tend to focus more on our drilling results and our timing of that. Obviously the more wells we get drilled and particularly of those wells are successful and generate a development program for us the sooner we'll be able to talk about what the potential might be.

Wade, I think with respect to Range, my recollection of that is it was their seventh, eighth, ninth and tenth well. So they were a little bit ahead of us in terms of the drilling in the Marcellus.

In terms of Equitable, I think they've only got what, one well down? I don't even know that they've fracced that well yet.

Yes, I think Equitable takes a different approach with regard to perspective resource than we do. I think we tend to be more conservative that way.

Understand. Have you guys engaged Netherland and Sewell to perform an assessment of the Marcellus at all?

No, there's really not enough data yet.

Fair enough. Thank you, guys.

Shneur Gershuni, UBS.

Good morning, guys. A couple of quick questions. I guess this is one bigger question with respect to CapEx. You noted that you might be divesting some properties, just curious if you're going to be recycling that capital into the Gulf? You also mentioned with respect to pipeline and storage that there are a bunch of opportunities. What's your expectation if all these projects get greenlighted what kind of CapEx are we talking about?

And then with respect to Appalachia, is there enough midstream available for you at this point right now to gather the increased drilling program and potentially the growth in the program on a go-forward basis? Sort of putting it all into context on a consolidated basis, do you feel that you're prepared for the amount of CapEx and what kind of number are we talking about if everything gets greenlighted?

Yes, with respect to the project scenario, I think certainly the West to East is a very significant number and I know 700 million is the number out there and it might range from 650 to 750 depending on the response from the customers, depending upon the size of the play. So that's a significant number.

With respect to storage enhancements, it's a significant number, but we're really not at this point in a position to disclose that because we're -- I think we're leaning there toward market-based rates. And so I think it would be inappropriate to disclose the CapEx with respect to that. And certainly with respect to the Marcellus Shale, to the extent that we have significant results there we'd be looking to redeploy more capital.

And your question with respect to the gathering systems is a very good one. I think, no, there's not sufficient gathering capacity in the Appalachian region now. We have moved ahead -- we talked about this previously, we have moved ahead with our midstream company. The midstream company is now in the process of finalizing its first deal with respect to laying pipe.

And I think more importantly, the structure is in place, we've done all the legal work, all the regulatory work, everything is in place with the midstream so that when and if the Marcellus Shale is what people expect it to be we're ready and we'll be able to move very quickly to bring that gas out of that region. We see it as an incremental profit opportunity, Shneur.

and with respect to divestitures, if you look at the cash-flow statement for the first quarter, there was really like $1.5 million of sales of minor properties that Matt mentioned in the Gulf Coast division. I would expect that the trimming that you would see would be properties of that magnitude, so there wouldn't be a huge inflow of capital from the sale of properties and the outflow of capital with respect to increased drilling is going to really ramp up over the year. But it's --

And if I can just add to that, Ron. We've got a couple of other small divestitures in the Gulf Coast that are working and, meanwhile, we've got a couple of small acquisitions in California that are working. If you take the whole thing together it's about a wash.

Okay. If I could just ask two more opinion questions. Ron, with respect to the rate case, was the lower ROE a result of just the fact that it's a Democratic Governor now in the state of New York? Or is it really the cause of getting the decoupling? And then with Matt, have you had a chance to review the differing 2P and 3P reserve reports between what New Mountain had and what you guys had put together? And what were the key assumption differences in the report? Was it IP rates; was it the length of the tight curve drilling costs and so forth? Just (multiple speakers).

Haven't seen it yet, Shneur.

Okay, great.

And with respect to the rate case, as I mentioned, we're in line with the other orders across the state. We're in an era of decreased interest rates and the Commission still adheres to its policies that it put together in its generic financing case. And we think there are some issues with that structure and with that methodology. The ALJ in the case suggested that it may be time for the Commission to review its policies with respect to CAPM and DCF methodologies, but the ALJ was not in the position to do that. He suggested we take that up kind of legislatively, if you will, with the Commission.

With respect to the Schlumberger report and the information we'll be exchanging I wouldn't want to leave the impression that it's because of difficulties between the parties. In fact it's not. I talked to New Mountain just earlier this week and we're now arranging the exchange of that information.

Let me add one more thing to that. I don't think anyone has characterized their Schlumberger report as a reserves report. So I don't know that the kind of direct comparisons you're asking are necessarily going to be possible.

And let me add to it as well. There are confidentiality provisions in the agreement itself and I'm sure you've seen that agreement. So how much we would disclose and would be talking about is problematic and certainly subject to question.

Okay, great. Thank you very much. I've got more questions but I'll jump back in the queue.

Tim [Schneider], Citi.

Good morning, guys. Just one quick follow-up on the gathering infrastructure question actually. At this point is all the gas that you guys produce coming to market, or is there anything lost just because the infrastructure requirements are a little tight right now?

I guess the way I would characterize it is we're bumping the limit and we're constantly working on infrastructure issues to resolve that limit. Do we have anything significant shut in because of capacity constraints? No.

Chris, I think part of what we'd be looking for in the midstream as well is the market is constrained in areas there; much of that gas is going into existing markets. So we'd be looking to move that gas off of our system to the extent we can and that would be part of the plan with respect to the midstream company.

Okay, Great. Then jumping over to Gulf region for a second, you said you'd kind of take a look at if performance targets are met. What is the time frame on that?

On the setting the performance targets?

Exactly and kind of evaluating if they've been met or not and deciding whether (multiple speakers)?

We're going to meet with the Board very soon and discuss our performance targets that we have in mind and get their approval on those targets. And what we're talking about is a fiscal '08 specifically.

All right. Jumping back to the Marcellus, do you guys have any indication -- and I know EOG is carrying the cost right now of what the well costs are in that area yet?

The horizontal wells drilled, fraced, completed are on the order of $3 million, but that's in an exploration stage. Obviously we got to a development stage we would expect that cost to go down.

Okay. And that's with an IP of 350 to 450 a day, right?

I wouldn't call that an IP. That's the sales production rate roughly that we expect to get. So IP would be higher than that, but IP is probably less relevant than what you expect to sell.

All right. That does it for me. Thank you.

(OPERATOR INSTRUCTIONS). And there are no other questions in the queue at this time. I'd like to turn the call to Mr. Jim Welch for our closing remarks.

Thank you. At this point we'll conclude our call for today. We'd like to once again thank everyone for being with us on the teleconference. A replay of this call will be available in about one hour on both our website and by telephone and will run through the close of business on Friday, February 15th. To access the replay online visit our Investor Relations website at investor.NationalFuelgas.com and to access by telephone call 1-888-286-8010 and enter pass code 5926-0259. This concludes our conference call for today. Thank you and goodbye.

Thank you all for your participation in today's conference. This concludes the presentation. You may now disconnect and have a great day.