National Fuel Gas Co (NFG) 2005 Q4 法說會逐字稿

Good day, ladies and gentlemen, thank you for your patience and welcome to the fourth quarter 2005 National Fuel Gas Company earnings conference call. [OPERATOR INSTRUCTIONS] As a reminder, today's conference is being recorded for replay purposes. I would now like to turn the conference over to your host for today's presentation , Ms. Margaret Suto, Director of Investor Relations. Please proceed, Ma'am.

Good morning, everyone, thank you for joining us on today's conference call for a discussion of last evenings earnings release. Today's presenters are Phil Ackerman, Chairman, President and Chief Executive Officer of National Fuel Gas Company; Ron Tanski, Treasurer of National Fuel Gas Company; and Jim Beck, President of Seneca Resources Corporation. At the end of the prepared remarks we will open the discussion to questions. Also, since this call is being publicly broadcast, we remind you that today's teleconference discussion will contain forward-looking statements as defined by the Private Securities Litigation Reform Act of 1995. While National Fuel's expectations, beliefs, and projections are made in good faith and are believed to have a reasonable basis, actual results may differ materially. These statements speak only as of the date on which they are made, and you may refer to last evening's earnings release for a listing of certain specific risk factors. With that, we will begin with Ron Tanski.

Thank you, Margaret and good morning everyone. In our earnings release last evening, we announced consolidated earnings for the fourth quarter of our fiscal year of $49.2 million, or $0.57 per diluted share. For the entire fiscal year, consolidated earnings were $189.5 million, or $2.23 per diluted share. The large increase in this year's fourth quarter earnings compared to last year was primarily attributable to the sale by Horizon Energy Development of its assets in the Czech Republic. In the earnings release, we tried our best to methodically break apart reported GAAP earnings to separately show earnings from discontinued operations, and to further refine earnings from continuing operations into recurring and nonrecurring categories.

Pages 10 and 11 of the earnings release detail the reconciliation between reported GAAP earnings and all other categories of earnings for the segments on both the dollar and earnings per share basis. Let me try to clarify what items we put into the nonrecurring category. These are classifications of items that under SEC pro forma presentation rules haven't occurred in the past two years or that we expect will not occur again in the next two years. The base gas sale and the reversal of the gain contingency in the pipeline and storage segment are items that we do not expect to take place on a regular basis. The recurring earnings are everything that's left. Recurring earnings may include unusual items, or variances in certain expense categories. Let me use our larger bad debt accrual as an example. Just because there may be a variance, we really can't classify the entire category of bad debt expense or even just the year-over-year variance as nonrecurring.

On page 11 of the earnings release, the third line from the bottom of the page is what we refer to as earnings from continuing operations before or excluding the nonrecurring items. Looking just at the $0.16 per share of earnings from continuing operations before nonrecurring items for the quarter, that's about $0.11 less than the middle of the range that we gave in our October 7, update release. I want to talk about the two largest items that caused this $0.11 difference. The first item was the larger bad debt expense that we recorded in the utility segment. Steadily increasing gas cost caused our accounts receivable to grow. This past summer, our collection efforts resulted in a large number of turnoffs and final bills. Disconnections in Pennsylvania doubled from the prior year, where a change in the law facilitated our collection efforts.

You can see on page 16, a year-over-year increase in receivable balances of approximately $8 million. At the end of the fiscal year, and heading into this heating season, we took a good hard look at our receivables balance to determine their collectability. After that analysis, we took an incremental $9.2 million charge for bad debts that on an after-tax basis was almost $0.07 per share.

The second item that caused a variance from our October 7, guidance update was a mark-to-market adjustment for some derivatives in the exploration and production segment that we cautioned about in that update. The rules governing hedge accounting are very complex and the issue we faced at Seneca at the end of the fiscal year was also complex. In simple terms, Seneca uses derivative contracts to hedge the variability and cash flows it expects to receive for its monthly oil and gas production.

In order for those derivative contracts to qualify for hedge accounting treatment, two things have to occur. First, Seneca links each derivative contract to a corresponding amount of future physical oil and gas production. And second, management must be of the opinion that it's probable that the future physical production that's linked with the derivatives will actually occur in the time period that the derivatives cover. If both of those conditions are met, Seneca can defer any losses on those derivative contracts until the production occurs. Now, if it's no longer probable that the production will occur when those derivative contracts are scheduled to settle, Seneca can no longer defer those losses, they must be immediately charged to expense.

During fiscal 2004, Seneca entered into a variety of hedging contracts that extended into fiscal 2006 and were linked to October, November, and December 2005 production. As we reported on October 7, Hurricane Rita caused us to shut in our Gulf production and only 45% of that has come back on line. Consequently, as of September 30, we determined that approximately 1 bcfe of hedged Gulf oil and gas production would not occur when we originally forecasted. As a result, approximately 5 million of losses on derivatives related to that now shut in production, that would have been carried on our balance sheet as an item in other comprehensive income and recognized in the first quarter of fiscal 2006, had to be recognized in the fourth quarter of fiscal 2005. On an after-tax basis, that amounted to almost $0.04 per share.

The recognition of that $0.04 expense in fiscal 2005 means that it won't be recognized in the first quarter of fiscal 2006, but since we expect first quarter physical production to be delayed, there won't be an immediate pickup in the first quarter. We do, however, currently project that production will return during fiscal 2006, and we'll get the $0.04 back over the year, and that's allowed us to maintain our fiscal 2006 guidance. Now, incidentally, that one bcfe of production that I just discussed, is our estimate of delayed production, not the total amount of production that has been delayed due to Rita.

Because more details regarding the quarter and fiscal year comparisons to prior periods are already in the earnings release, I won't spend time repeating it all again here. But with all the pluses and minuses discussed in last night's release, the $0.57 of earnings per share for the quarter and the $2.23 of earnings per share for the fiscal year were within the range that we provided in our October 7, update release. That release also provided a lot of information regarding operations in the exploration and production segment, I'll let Jim Beck review Seneca's current situation in a minute, but now I'd like to focus on our fiscal 2006 earnings guidance.

As we confirmed last evening, we're providing consolidated earnings per share guidance in the range of $2.30 to $2.50 per share. If you compare the 2006 segment earnings per share guidance table on page 21 to the fiscal 2005 segment results on page 10 of the earnings release, you'll see that the projected earnings increase in fiscal 2006 will come primarily from the exploration and production segment where higher commodity prices are expected throughout the fiscal year, as well as from the utility segment where higher base rates will be in effect for the entire fiscal year. Looking at the first quarter of fiscal 2006, we're providing earnings guidance in the range of $0.53 to $0.65 per diluted share. That's a pretty wide range, but with the Gulf Coast production uncertainties, that's about the best we can do. Now, let me turn it over to Jim Beck.

Well, thank you, Ron, and good morning everyone. Fiscal 2005 saw record oil and gas prices. It was an unusual year for hurricanes, and Seneca's earnings of 50.7 million for the year were the second highest on record, we achieved these results despite a nearly 13% drop in production. In addition to reviewing the financial information from yesterday's earnings release, we'll provide you with an operational update on the conditions described in our October 7, release. Earnings for the quarter were up 14%, to 11.7 million, while production for the quarter was down 6.4% primarily due to the expected declines in Gulf production, exacerbated by the impact of Hurricane Rita.

Seneca's offshore daily production prior to Hurricane Rita was 46 million cubic feet equivalent per day. As reported in yesterday's press release Seneca has 45% of its production back online, an additional 46% of our production is ready to come online as soon as we receive word from the offshore pipelines that they are ready, they have completed their repairs and are ready to receive production. The remaining 9% of our production is waiting on equipment to complete our repairs.

In our East division, production was down approximately 3.2%. However, in September, we started to see an increase in production rates as more of the 39 wells drilled in the quarter were brought online. In addition, 20 of the newly drilled wells had their productions delayed primarily due to the construction of a new third-party processing facility, which is expected to be finished in November.

In the West division, production was down 1% primarily due to normal declines in our older mid grade Sunset wells. Production in the west is also expected to improve in 2006, as we have finished drilling and are currently completing 115 wells in that division. In Canada, production increased nearly 40% from the prior year's quarter, due to the results of our Sukunka drilling. Seneca Canada, in fiscal 2005, drilled 34 wells while we had forecasted drilling between 50 and 65 wells. The main reason for this reduction was the very wet summer in Alberta which limited rig moves.

Among other notable items this quarter was the reduction in G&A expenses. Where outside legal costs have been reduced along with a reduction in our staff in Canada. Seneca's total capital expenditures for 2005 were 121.2 million, versus forecast of 139.4. The main reason for this shortfall was the limitation on operations in the offshore, where we had drilling and construction delays due to the two hurricanes. This delayed some of our capital spending into fiscal 2006. In Canada in 2005, we participated in one new well drilled in the Sukunka area, we're currently participating in drilling two additional Sukunka wells and we'll provide updates as they are released by Talisman, the operator of these wells.

Talking about Canada, we are concerned about the performance of our Canadian operation. As you can see from yesterday's press release, we had a decrease in our Canadian reserves. This has-yielded some changes in our Canadian operation. First, we have hired a new exploration manager and are currently working to rebuild our exploration staff. Second, I'm now more actively involved in building our exploration and development programs. With the increased finding and development costs experienced in Canada, we're working to identify some niche opportunities in our core areas where we will provide better results. As we have stated in the past, we will spend our capital in whichever division achieves the best results. That is still our plan.

Seneca anticipates its capital spending for 2006 to be at least 115 million. We have four offshore projects ready to drill, however, with a very tight offshore rig market, we're not sure when a rig will be available. Meanwhile, we have two rigs drilling in each of our East, Canadian and West divisions and plans to drill over 200 wells in fiscal 2006. As anticipated, Seneca's total production for 2005 was 52.4 bcfe well within the range of 50 to 55 bcfe that we had announced at the beginning of the fiscal year. As you saw in our October 7, updated release, beginning in fiscal 2007, Seneca will be allowed to recover nearly $45 million in royalty relief from offshore production in federal waters. Of this $45 million, Seneca's share is approximately $19 million. To ensure Seneca recovers this revenue as quickly as possible, we are reviewing the best options to increase our offshore production.

Looking forward to our expectations for the first quarter of 2006, production should be in the range of 10 to 12 bcfe in our original estimate for 2006 production of 46 to 51 bcfe is based on our latest information available. We'll keep you advised as to any updates on any significant revisions that need to occur. Commodity prices used in our 2006 guidance from the October 7, operational update were NYMEX-based prices as of September 13. The basis adjusted average price without hedges are gas, $10.49 per mcf, oil $55.22 per barrel. This compares to our actual 2005 unhedged basis-adjusted prices of gas $6.86 per mcf, and oil, $44.72 per barrel.

Since we have tentatively lowered our production forecast due to Hurricane Rita and are seeing increased costs for rigs and services, we are revising our expenses on an mcfe basis. One optimistic note about these projections, as the offshore production is brought online, these per mcf expenses per LOE will likely decline. With that in mind, our revised expense forecasts are as follows.DD&A is now expected to be in the range of $1.85 to $1.95 per mcfe. LOE, including taxes but including plant expenses will be in the range of $1.25 to $1.35 per mcfe.

G&A has not changed and will still be in the range of 22 to 24 million. Hedging for fiscal 2006 can be summarized as follows. As of October 28, we have 15.9 bcf of gas production hedged at an average price of $8.45 per mcf. And we have 1.9 million barrels of oil production hedged at an average price of $34.14 per barrel. Based on these average prices we've just provided, the earnings sensitivity to price change for 2006, assuming a static basis is as follows. For each $1 change in the average gas price for the year, earnings will change by $0.11 per share. And for each $1 change in the average oil price per year, earnings will change by $0.01 per share. At this point, I'll turn it over to Phil.

Thank you, Jim. Considering the volume of our press releases this month, including 22 pages yesterday, there are not many details left to give. I think you all know that by traditional measures that equity ratios, payout ratios, cash flow, coverage ratios, et cetera, the fundamentals of the Company are very sound. We've sold the Czech assets which were worrisome for some investors. We've essentially doubled our reserve for bad debts against about a 10% increase in receivables. We recorded impairments of two minor generating assets. We charged to 2005 earnings, mark-to-market losses on some 2006 derivative contracts. And we still reported 2005 earnings of $2.23 per diluted share, versus $2.01 last year.

We have outlined the impact of Hurricane Rita, we have recognized the weakness in our Canadian E&P operations. We are cognizant of potential conservation and demand destruction and our 2006 earnings guidance is still $2.30 to $2.50. As Jim reminded you, this guidance is based on September 13, NYMEX prices. Current prices are significantly above those levels. Providing a nice cushion against any unforeseen events. In short, we fully expect to deliver 2006 earnings as indicated, and National Fuel is stronger than ever before. With that, Bill, we'd like to open it up to questions.

Thank you very much, sir. [OPERATOR INSTRUCTIONS] Your first question comes from the line of Jay Yannello of Polly Capital, please proceed.

I think you just answered this, but did you say the guidance does assume a doubling in bad debt expense and conservation, and if so, assumes conservation, what level of conservation? Thank you.

No, I said we doubled the bad debt reserve in fiscal 2005, so that going into 2006 the reserve for bad debts is about twice what it was going into 2005.

Okay, fair enough.

The forecast, the guidance does assume a level of conservation of decline in usage per customer, and some people here are scrambling to find that exact number.

No problem, I can wait. Thank you.

Ron, have you got that?

Yes, okay. For -- we've seen, over the last few months, our normal residential usage per account drop about two mcf. We've gone from a $1 -- or I'm sorry, 109 mcf per account to about 107 mcf per account. Maybe about a 1 to 2% reduction in usage per account, Jay.

Okay. What percentage of your customers are on balanced bill?

We -- about 30%. I have that number, too, but it will take me a minute to flip to it.

Ballpark is fine. Okay, thank you.

Thank you very much, sir, ladies and gentlemen, your next question comes from the line of Faisel Khan of Smith Barney. Please proceed.

Good morning, guys, it's Sebastian. Can you tell me at the utility how much gas you had hedged for this coming winter season?

That's a pretty difficult question to answer in terms of what you mean by "hedge." We've got a volume that's placed into storage. We've got another volume that's based on fixed price contracts. And then we've got a volume that floats. We'll get you the approximate percentages of each of those volumes as they represent winter flow.

Okay, that works.

I think the aggregate that's fixed one way or another is about 70%.

Okay, that's fine.

We'll have a more precise number.

That's okay, 70% works. I guess for Jim, can you give us anymore updates on the Sukunka wells or--?

Yes, since we are the minority operator there, and have only 20%, we depend on Talisman. They control what can be said about the wells, so we have to wait until they make some releases before we can say anything.

Okay. In the Gulf, where do the pipelines stand in terms of actually being able to accept some of the production from your 45.6% of production that's ready to come online? Is that getting pretty close or are we still pretty far away there?

It's a very -- that's a good question. It's something that's a very fluid situation that we've out there. We've had pipelines call us up, and say okay you can bring on production tomorrow on a platform, then thy'll call back, and say no, you can't bring it on. So it is very difficult to say exactly when some of this production will be allowed to come back on. We've heard two to four weeks on some of our lines. We've heard some of the lines say it could be longer than that. It could be as long as three months. It's very fluid. I don't think they know for sure. As they make the repairs and do their pressure tests, and then work on their onshore facilities, it's become very difficult to predict exactly when. And so we've tried to take a very conservative approach in forecasting what's going to happen for this first quarter.

Okay. Thanks. And lastly, do you, I'm trying to get a better understanding for the change in Gulf production from your previous guidance to your updated guidance on October 7. I know there's a slide that you provide with some impact of wells for '06. Can you kind of walk us through that and tell us what's embedded from the Gulf or what has changed? Because it seems like it's a pretty big move when most of your production is ready to come back on, just waiting on pipelines.

We're going to be updating all of that in our presentations that we'll be doing here in New York and Boston here and have a whole new slide to give you an impact of what all the wells are that we'll be planning for this year. And the results of the '05. But the big thing that's happened is getting the lines back on, getting the pipelines back on line. Because that has had the biggest impact on the Gulf and that's the biggest variable there. The one key well that we did have in our slide show presentation was the Highland 37A-5 well which was going to be a major impact well. The eye of the hurricane went right over that platform. However, we did not have a lot of damage, and the rig was on location at the time, the rig is fine. And we are now back to drilling. But that did delay our entire drilling program on that block about three weeks. So we're still currently drilling on that well, and it will still have an impact in the '06 time period, it's just depends on when we get the well finished.

Okay. But in terms of getting platforms to the other wells that you were awaiting platforms on, that hasn't been an issue?

Been slight delays because the priority has been to repair the old platforms that are out there, so a lot of the welders and those type people have been out making those repairs so there's a slight delay, but we don't think it's going to be significant in the impact on the production forecast that we have for 2006.

Okay, great. Thanks a lot, guys.

Thank you very much, sir. Ladies and gentlemen, your next question comes from the line of Jason Selch of Magnetar Capital.

Yes, I have two questions, you filed something last week, I think relating to financing. Are you anticipating doing a financing shortly? The second one is, what's the status with your rigs? Do you have rigs in the Gulf of Mexico locked up for your program or not?

With respect to the financing, I mean, the only thing that we have filed recently was a FERC application regarding the building of the Empire Connector. But nothing specifically with respect to any planned financing. The next planned debt refinancing that we have is May, 2008. I'll turn it over to Jim for the rig question.

Okay. On the rigs, we have this rig that we're currently using on our Highland 37 for one more we well. One of the other wells that we were going to be drilling here right away, the rig was destroyed by the hurricane, that has forced the operator to go out and start looking for a new rig. And as I said, the rig market is very, very tight. When you lose 10 rigs due to storms, that means everybody that was going to be using those rigs to drill, has to go out and find other rigs. So we're finding it very difficult. We're out actively looking for windows on rigs to drill. The other thing we've seen is that the rig costs have gone up nearly double from what it was a year ago for comparable kinds of rigs. So it's very expensive, and it's going to be difficult to get the rigs, I think, that we need for the year. But we're out there actively pursuing it right now.

So in the Gulf of Mexico, if you stop drilling, normally your production declines pretty sharply, does your production guidance for 2006 assume that there's going to be a sharp decline in the Gulf of Mexico, then?

No, see, what happens is it takes about a year to get the wells that you're drilling now on. So that would impact '07 potentially. We have -- we had a number of wells that we had drilled in '05, and our building facilitates and we'll be putting those on. And so that's not going to be impacting the '06 production. We still are going to be setting some platforms and putting those wells online as we get it done. So that shouldn't have a big impact on our overall forecast. And most of our forecasts do not include exploration opportunities going forward. So right now, we're in good shape for the '06 time period, and if we get the rigs that we need to drill for '06, that would be an impact on '07. As I said, we're actively working out there to find the best way to recover or increase production in the Gulf because we want to get some of that royalty relief that we're going to be allowed starting October 1, of 2007.

Okay, thank you.

Thank you very much, sir. Ladies and gentlemen, your next question comes from the line of Rebecca Followill of Howard Weil. Please proceed.

Jim that leads right into my question, you said you wanted to find ways to increase the production. Besides this four offshore projects, what other ways are you looking to do that?

We're looking at all avenues. The nice thing about it, is that because we get royalty relief on all our production, it does give us an economic advantage in just about every arena, whether it's acquisitions, buying more leases, or doing more exploration. So we're looking at what's the best way and most effective way to increase that production and we're looking at all three of those.

So we could see you more active in at least sales and there is a potential for an acquisition in the Gulf?

That's correct.

Okay, thank you.

Thank you very much, ma'am. [OPERATOR INSTRUCTIONS] Our next question comes from the line of Yani Manzares of Sendel Asset Management. Please proceed.

Hi guys, good morning, I had a question on the Empire Connector Pipeline. I was wondering what sort of earned ROE you would be getting at the current subscription level, which last time I checked was about 60%?

The question is what kind of an ROE would we have at the current subscription level?

Yes.

Based solely on the volumes that we have under contract, we would not anticipate that the ROE would be particularly attractive. I'm dancing around that I recognize, but the answer is it's a very poor ROE. What we assume, and based on what we see of the current basis differentials, that the Empire Pipeline and the Empire Connector would be taking advantage of, is that we expect that we would be able to keep the pipeline full or nearly full based on either short-term or interruptible transportation.

Yes.

Contracts. And then that would get us up to whatever ROEs the FERC will allow. Once again, that's a FERC-regulated project, and whatever the ultimate ROE's going to be subject to FERC regulation.

What are you expecting that internally to be?

Well, we're expecting somewhere in the 12 to 14%.

Okay.

ROE.

Okay, perfect, thanks a lot.

Thank you very much, sir. [OPERATOR INSTRUCTIONS] Our next question comes from the line of Shnuar Gorshuni of UBS Securities. Please proceed.

Thank you. Most of my questions have actually been answered. However, I did want to ask about the payout, the current payout level, dividend level and the potential for share buybacks, and whether it was discussed in the Board meetings and so forth, and what levels you would be comfortable with given the amount of cash that you currently have available right now?

I have to apologize, I was working on the answer to the question about how much of the winter supply would be hedged. But as I understand it, you were asking about a potential share buyback and whether that had been discussed with the Board? And the answer is we have been talking about share buybacks. We have not come to a formal determination to do one. Obviously we're going to have significant cash available as we come out of the winter, and begin to liquidate receivables and storage inventories. And at that point a share buyback is an obvious alternative.

Would it be fair to say that the Board would be considering alternative uses for the cash as opposed to paying for the injection, I'm sorry, for the winter injection at the regulated gas utility, but rather once that's done, that you would actually consider a substantial dividend increase in potential share buybacks once you've gone through the winter heating season?

You're breaking up a little bit there on the question, but as I understand -- well, I think you asked would it be fair to consider or to believe that the Board would be considering a share buyback or dividend increase or other use of the cash flow that would be occurring as we come out of the winter and reduce inventory levels and reduce receivable levels. If that was your question, the answer to that question is yes. That is a reasonable assumption. That we'll obviously have to consider that. We're going to have a lot of cash and there's only two or three things that it makes sense to do with cash. One is to husband it against some future presently unknown opportunity or requirement, two is to increase dividends and three is to do share buybacks.

Has there been a level that the Board has generally tried to target in terms of payout levels?

Oh, I don't know whether you would call it a target per se, but we've been comfortable in the 60% range.

Okay. Thank you.

Thank you very much, sir. Ladies and gentlemen, that concludes our Q&A for today. I'd like to turn the call back over to Margaret Suto for any closing remarks.

Margaret, before you do that, Ron, do you have an answer there, based on a quick calculation, we determined that approximately 58% of the winter season requirements, based on normal weather, could be considered to be fixed in terms of price, either the fixed-price contracts or the amount that would likely be coming out of storage. That can vary month to month, but call it 60%.

Okay. I guess if there are no more questions, we will conclude our call then. Thank you for 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. Both will run through the end of business on Friday, November 4. Our website address is www.nationalfuelgas.com. The telephone replace number is 1-888-286-8010, using pass code 16926875. This concludes our call for today. Thank you and good-bye.

Thank you very much. Thank you, ladies and gentlemen, for your participation in today's presentation. We appreciate your patience and you may now disconnect. Have a good day.