National Fuel Gas Co (NFG) 2005 Q2 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the second quarter 2005 National Fuel Gas Company earnings teleconference. [OPERATOR INSTRUCTIONS]. I will now turn the presentation over to your host for today's conference, Ms. Margaret Suto, Director of Investor Relations. Please proceed.

Thank you. Good morning, everyone. Thank you for taking the time to join us this morning for a discussion on 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 National Fuel Gas Company Form 10-K on pages 48 through 51 of the 2004 annual report for a listing of certain specific risk factors. With that, we will begin with Ron Tanski.

Thank you, Margaret, and good morning, everyone.

As you have seen in our earnings release, reported GAAP earnings for the second quarter were $0.83 per diluted share. Excluding two items that I will discuss in a moment, recurring earnings were $0.84 per diluted share. Overall we're pleased with these results, which on a recurring basis, we're in the upper end of our guidance for the quarter.

Since the earnings release provides a great deal of information by segment, I won't repeat it again now. Instead I will spend a little more time on the two nonrecurring items included in the quarter, and then provide you with some additional details on the settlements reached in our two rate cases.

The first nonrecurring item was a $3.8 million income tax charge recorded in the international segment. Given the limited window provided by the American Jobs Creation act to enjoy a recaused tax rate on repatriated earnings, we decided that we could better utilize approximately of $80 million of U.S. equivalent earnings that we've generated from our investments in the Czech republic, in our domestic construction projects, rather than keeping those earnings permanently reinvested outside the U.S.

As a result of that decision, we have booked $4.2 million in taxes in the March quarter at the reduced rate of 5.25%. As I mentioned earlier $3.8 million was recognized in the income statement , and $400,000 was booked to other comprehensive income on the balance sheet. We're expecting to have arrangements in place to actually remit those earnings to the U.S. during our June quarter.

Now that tax expense offset earnings in the segment that were otherwise higher than forecast due to higher electricity sales, and a Czech crown exchange rate that was more favorable than we had forecast. You may have seen in the press that we have received indications of interest from parties seeking to acquire our Czech assets. Other than acknowledging that interest, it's premature to talk about any possible sale of those assets at this time.

Somewhat offsetting the tax expense in the international segment, we had a $2.6 million gain in our pipeline and storage segment. Supply Corporation, along with its other partners in the Ellisburg storage field, received FERC approval to convert base gas capacity to top gas or working gas capacity, and then sell the gas that was occupying that space. Supply Corporation's share of that space is 660 million cubic feet.

While this is a one-time gain for Supply Corporation, of approximately $2.6 million, we're more pleased that this will open up that 660 million cubic feet of space, for ongoing storage service. At current rates between $1.49 and $1.70 per mcf, this is an opportunity for Supply to increase revenues approximately $1 million per year with almost no increase in operating expenses associated with the higher revenues. That space has already been contracted for, effective as of April 1st.

Moving on to the utility segment, we're pleased that we settled our rate proceeding in Pennsylvania. New rates in Pennsylvania went into effect on April 15th. Under the settlement agreement, which was a black box settlement where individual expense items were not broken out, the parties simply agreed to put new rates into effect that are designed to increase base operating revenues by $12 million annually.

For the remainder of our 2005 fiscal year, we expect those new rates in Pennsylvania to generate an increase in base operating revenues of about $2.25 million with a net income impact of approximately $1.5 million or $0.017 per share for the Pennsylvania division. This should more than recover the loss in earnings to date due to lower average usage per customer.

For your forecast models, you can plug in a Pennsylvania rate base of approximately $270 million. In our New York division, we announced on April 15th, the signing of a settlement agreement by most all of the active parties in the case. I need to emphasize that there is still a lot that has to occur before that settlement becomes final and new rates can go into effect.

The administrative law judge has issued a procedural schedule, whereby the commission will publish a notice requesting public comments on the settlement agreement and the ALJ may conduct a hearing before the commission takes its final action. We're anticipating that the settlement agreement will be addressed by the commission in July, for a targeted August 1st effective date.

We're particularly encouraged because we think this settlement was a creative solution where all the parties got something, and the company was able to achieve a $21 million increase in its base rates, while the bills to our customers will actually decrease by approximately $15 million. For the remainder of our 2005 fiscal year, with August 1st targeted as an effective date, we expect to see New York base operating revenues increase by about $2.5 million, with a net income impact of approximately $1.1 million or $0.013 per share for the New York division.

Like the settlement in Pennsylvania, the New York settlement was essentially a black box settlement for most of the rate components. However, for your earnings models, you should plug in a New York rate base of between $640 million and $650 million. And also, for your models, for both states, you might also factor in an approximately capital structure as follows: 45% long-term debt at a cost of 6.65%. 5% short-term debt at a cost of between 3.5% and 4.5%. And a 50% equity component, with an implied rate somewhere between 10 and 11%.

We know there's some confusion regarding our April 15th press release announcing the New York settlement. Everyone is trying to figure out how we can get an increase in base revenues of $21 million, while reducing bills to our customers by about $15 million. Looking at it from the Company's point of view, the $21 million base revenue increase is made up of the following items: $4.5 million comes from the removal of bill credits, or bill reductions that are currently factored into our customer's bills as a result of our October 2000 rate settlement. $1.3million comes from the removal of another bill credit that was also introduced by the October 2000 settlement.

That credit was designed to offset a cost element in base rates related to the Home Insulation and Energy Conservation Act. That conservation program had ended and all parties recognized that the company was no longer incurring the costs that were factored into base rates. Rather than changing our base rates the October 2000 settlement instituted the offsetting credit. And finally, $15.2 million comes from an increase in our base rates.

Looking at it from the customer's point of view, that $21 million rate increase will be offset by two items: first, in each year of the settlement, the company will be refunding $16.25 million, that the company has previously collected through revenue taxes on our customers' bills. Those dollars are sitting on our balance sheet as a regulatory liability that had built up on our books when the state changed its method of assessing taxes on utilities from gross receipts tax on revenues to an income tax. We will be amortizing that amount and moving it through our income statement into operating revenues on a volumetric basis over the term of the settlement.

Second, there will be a net reduction of the revenue tax rate that is applied to our customers' bills which will total approximately $20 million. Adding the refund of the $16 million and the reduced taxes of $20 million, equals $36 million. When that amount is subtracted from the $21 million base revenue increase, the customers will actually see a net decrease in the delivery portion of their bills by approximately $15 million.

I have two words of caution: First, as I stated at the outset, we're a number of steps removed from Commission approval of the New York settlement. Secondly, for operating income assumptions in your modeling, the $21 million base increase will not translate into $21 million of operating income. Our new base rates will factor in the state income tax expense of approximately $3 million that was being funded by the revenue tax on the customers' bills. Additionally, there will be a total of approximately $8 million of other expenses factored into new base rates and some reductions in other revenues so that the $21 million base rate increase will translate into an operating income increase of approximately $10 million.

At the next earnings teleconference in July, I hope to be in a position to report that the New York commission has approved this settlement. Our timber and marketing segments and corporate and all other categories were roughly in line with our forecast. And before I turn it over to Jim Beck for his review of the exploration and production segment, let me talk about our expectations for the next two quarters. For our June quarter, we project earnings to be the range of $0.22 to $0.30 per share.

That's lower than many of the analysts' estimates that are reported by first call, and we expect that many of you have not factored in the basis differential that we're currently experiencing with our California heavy soured crude. For our final quarter we project earnings to be in the range of $0.08 to $0.13 per share, and for the entire year, we're confirming our previous guidance of $1.75 to $1.85 per share.

Now I will turn it over to Jim.

Thank you, Ron, and good morning everyone. The second quarter was a good quarter for Seneca. Operationally, our 98% drilling success has helped to improve our outlook for the future. The results from our drilling in the Gulf and in Canada were very good. A review of the financial results is summarized in detail on pages 15 and 16 of yesterday's press release. In addition to that summary, we'll provide you a short overview of our activities.

Production for the quarter was 13 bcfe, and year-to-date we're at 26.3 bcfe. We are on target to meet our 2005 forecast of 50 to 55 bcfe. Revenues for the quarter decreased 11.8%, to $70.3 million, and Seneca's net income for the quarter was $11.2 million or $0.13 per share. For the first half of the year, Seneca's net income was $.30 per share. Expenses for the quarter, excluding last year's credit, related to the Company's fiscal 2003 sale of Canadian oil properties, decreased $2.95 million, or 6.6%.

DD&A for the quarter was down nearly $1 million but on a dollars-per-mcf-basis, it actually increased, year-to-date to $1.68 for mcf. One reason for this increase is that we have not yet booked reserves for some of the new successful offshore wells because we did not perform expensive production tests. We booked these reserves as probable reserves until such time as they are placed on production. This means that the DD&A for mcf rate is above the $1.50 to $1.60 range provided in Seneca's forecast. As more of this production is brought online we expect this rate to gradually decrease.

In addition, drilling for the quarter, we had 65 gross wells and 60 net wells. In the Gulf this quarter, Seneca successfully drilled two exploration wells and we have now completed four successful offshore wells for the year. Our plans are to have the Eugene Island 320 well and the [Brazos] 502 well on production in fiscal 2006. Seneca's working interest in Eugene Island 320 well is 100%, while the Brazos 502 well working interest is 65%.

We anticipate drilling four more offshore wells during the fiscal -- this fiscal year. A rig is expected to spud the first of our shallow 3 well Chanex programs in May. In Canada, our third Sukunka well continues to be a strong producer. In its first three and a half months of production, the well has produced over 5.8 bcfe of sales gas. Seneca's working interest is 20%. Drilling is continuing on the Sukunka 75e well, and we expect to reach total depth on this well within the next three months.

In California, we have completed construction of our waste gas scrubber, and begun initial operations in April. The scrubber allows to us burn waste gas, rather than utility gas to generate steam. It is performing above expectations. The waste gas scrubber is expected to save Seneca nearly $400,000 per month in steaming costs.

On the drilling side our development drilling and Midway Sunset and North Lost Hills is proceeding ahead as planned. As we have indicated for the last six months, the high basis differential for our heavy sour crude has been a concern. The basis had increased from $5.50 a barrel to between $13 and $14 per barrel. We expected that this basis would start decreasing in 2005; however, it's now only begun a slight downward trend in April.

We still believe that it may return locally to a more normal range before the end of the year, primarily because a 60,000-barrel per day for heavy sour crude, that was to be shut down has been sold to a new owner and will continue operations. Looking ahead to our expectations for the third quarter, we anticipate production to be in the 12 to 14 bcfe range and Seneca will drill approximately 40 new wells.

Hedging for the remainder of fiscal 2005 can be summarized as follows: As of April 13th, 2005 we have 8 bcf of gas production edged at an average price of $6.16 per mcf, and we have 1.3 million-barrels of oil production hedged at an average price of $30.40 per barrel. The earning sensitivity to price changes for the remainder of 2005 assuming a static basis is as follows: For each $0.25 change in the average gas price, earnings will change $0.02 per share.

Now, since the basis in California remains high, we are using the following: For each $1 change in the average oil price for the remainder of the year, earnings will change about $0.005 cent. In closing, we continue to be focused on living within cash flow, and continue to expand our activity, mainly through drilling.. At this point I will turn it over to Phil.

Thank you, Jim and good morning, everyone. While we are at the higher end of our guidance for the quarter, the earnings per share not as good as I think they should have been. Largely because of the performance of the utility and the E & P segment.

On the other hand we have made a lot of progress in the quarter in fixing the utility with new rates in Pennsylvania and having a filed settlement in New York. In Seneca, we have the basis differential in California, which seems to be improving, and the wearing away of some of our lower priced oil hedges so that our average oil hedge price should jump about $4 per barrel starting in January of 2006. More good moves is our success in the Gulf and the continued pace of production from the third Sukunka well.

The completion of the California scrubber will also help our future earnings and exploration and production. And I hope that you are no longer surprised that once again, our production is on track with our guidance for production volumes. The expansion of storage that Ron mentioned likewise is a plus.

In taking about $80 million off the table in International, both reduces our exposure, and gives us additional financial flexibility to use to increase future earnings. Finally, effective April the 1st, we switched the roles of Dave Smith and Dennis Seeley as presidents of the distribution company and the pipeline and the storage units respectively. While Dave and Dennis are both long-term employees of National Fuel and have worked side by side, sometimes it seems valuable to give people a fresh perspective, and to bring a fresh look to different areas within the company. Dave's background is a lawyer, and Dennis' as an engineer has naturally tended to color the ways that they've looked at their respective operations. I think it will only be valuable to the Company to have them take a fresh look at each other's areas.

In summary, there have been a number of developments during the quarter, that I believe will have a positive impact on our earnings in 2006 and beyond, and for that I think we had a very good quarter. Operator, at this point I would like to take questions.

[OPERATOR INSTRUCTIONS]. Your first question will come from David Schanzer with Janney Montgomery Scott. Please proceed.

My question has to do with both the New York and Pennsylvania settlement. Is there -- or can you discuss that in addition to whatever that range of imputed ROE of say, 10 to 11%, are there are any additional incentives that would get you above that -- whatever that imputed amount is?

In New York, there are some incentives built in with respect to moving customers from the utilities gas sales to other marketers and we have the ability in New York to earn up to an 11.5% return. That's also part of the settlement agreement. Any earnings we achieve over 11.5% will then be shared 50/50 between the company and the customers. And in Pennsylvania, there's really no other incentive. No. There's nothing else in Pennsylvania.

Was there any indication in the Pennsylvania settlement of a band above whatever the imputed ROE is, that you can earn before they would be interested in calling you back?

No. None -- there is no --

No indication. No indication. Okay and then another thing of clarification. If I recall early in the call you mentioned something about a portion of earnings per share being remitted to shareholders. Was that correct? In the second quarter?

No. That was the earnings that we've generated in the Czech republic.

Oh, being remitted to shareholders.

Being remitted back to the U.S., repatriated to the U.S. Okay. Great. Thank you.

And your next question will come from Jay Yannello with UBS. Please proceed.

Good morning. I have to admit I was not expecting the price to actually go nowhere or slip. I was considering a wide basis differential but it really got very wide.

I'm wondering, looking to the third quarter, I know you said the utility -- we have some extra expenses, that will start being made up with the rate case later in the year and into '06, is there anything else kind of lumpy or weighing on the third quarter that might get you down to the low end of your range, or is that simply based on, you know weather outlook which might have some little impact and basis differentials? In other words what is the swing in the range for the fiscal third quarter? Is it just basis and production or are there other things in there?

It's primarily basis and production. You know, we had the odd amount here and there, you know, the timber had a particularly good second quarter because the weather was very conducive to timber production. We could have a rainy quarter or something like that that would cause the timber to maybe swing a penny the other way. And there's always -- I mean little odds and ends. I wouldn't say there's anything else particularly -- what was your expression, lumpy?

There's nothing lumpy or lurking out there, Jay.

Phil, since you are on the line here and I know, Ron, you said you weren't going to go into too many details but can you provide us some sort of flavor on potential sale of the Czech operations?

Well, I'm not sure exactly what kind of a flavor you are talking about. We did start once we had the offers in hand, start to consider seriously, once again, what we might do in the Czech Republic, and certainly the easiest decision was to take a lot of the money off the table there with this dividend. And where we go from there is another question.

Repatriating $80 million is a significant step towards getting out of international and reducing our exposure in that area. We did receive a number of offers. The offers are not directly comparable, and we're considering what life might look like after we've already recovered $80 million for thereabouts.

Okay. Fair enough. Thank you.

[OPERATOR INSTRUCTIONS]. And your next question will come from Mike Heim with A.G. Edwards. Please proceed.

Thanks. I have just a couple of questions on the repatriation. Does this officially end any thoughts of any investment in the Italy plan, et cetera?

Well, I wouldn't say it was an official end to it.

Can I say that it is very likely.

I would say that investment in Italy is unlikely.

Okay. Second, more of a semantic thing, it talks about $80 million in dividend to be repatriated and it doesn't look like there's anything in the cash flow statement, but taking the charges for the taxes this quarter. Why the timing difference?

That's an accounting requirement. You're right. The fact is that we have not yet received the money, but the accounting is that once you -- I forget what the test is I think it's probable --

Okay.

Once you determine that the repatriation is probable, you then have to recognize the tax.

Okay. Maybe a question for Jim. 65 gross wells drilled. Had you talked about doing 40 in the last conference call. Why the higher number? Was it favorable weather or just more opportunities came up?

Mike, the situation we had some opportunities come up in California to expand that development drilling there. And so, you will notice that most of the wells were drilled in California.

Mm-hmm.

Those wells, once we made a decision to do that, those wells take about three days to drill. So when a rig became available, we picked it up and we were able to accelerate the drilling in the quarter.

But you said 40 is your guess for next quarter so it's not a continuing trend?

Well, the reason it's down for this quarter, next quarter is because of spring breakup. That shuts down a lot of the rigs being able to move, particularly in New York and in Canada. And as soon as we get through spring breakup, we'll get the rigs working again.

So that was our estimate as to what -- where we'll probably be if the weather works to our favor, it could be a little more.

Okay. On the gas scrubber and the steaming cost savings, where does that show up in the line item? Does that reduce, you know, LOE costs or general administrative costs or where does that hit the line item?

That will be a reduction in the LOE costs. The gas that we buy to generate the steam comes out of our LOE line. So you will see a reduction in LOE.

Okay. And finally for Phil, I guess, no change in the guidance? You have seen a pretty good jump up in the commodity prices in the last three months. Refresh our memory what your commodity price assumption is and if that's changed in your guidance.

The commodity prices that we're seeing, unfortunately are substantially negative impacted by that California basis differential for the heavy sour crude.

So the offset to the higher prices we're seeing now in the market is an increase in the basis differential on the crude?

Right. Yes. You see, the market price that you are generally seeing is probably a sweet light crude as opposed to a heavy sour, or perhaps you follow west Texas intermediate. I'm not sure which market you're talking about, but both of those markets are significantly higher than the heavy sour.

How about on the gas side? I mean those numbers are up too.

Yeah, those numbers are up, and we're seeing some of that flow through. One of these people here can help -- if you want to know specifically the numbers that we used in our model for the earnings guidance, somebody is going to have to help me out with that.

Yeah that was -- the forecast we had used was the July 22nd last year forward strip on NYNEX and the average gas price on that was $6.21 and oil was $35 so what we are seeing now is the oil and the gas are both higher than that, but because of the basis, as that oil ran up, the differential ran up and we didn't realize any improvement in the oil at all because of the basis increasing, but we are seeing some improvement in the gas, even though that was a very aggressive price that we used last year.

I don't want to tie you too specific here, but are you saying that your current forecasts is based on the current strip, with the current differentials or that we're still using the July 22nd 6.21, 35 numbers.

Yeah, from our forecast position, we still take a look at -- we use that as our base forecast using last year's strip, and then we'll adjust it based on where we are each quarter. So right now, we are seeing a higher gas price with the oil not being -- as not as large.

Okay. All right. Thank you.

And your next question will come from Faisal Khan with Citigroup Smith Barney. Please proceed.

Yes, hi. A question for Jim. On the -- your planned number of wells I think you were going to drill in Canada, you gave us that last year. You talked about 50 to 60 wells and I think through this quarter, you drilled about -- is it 14 wells, I think?

Is this more of a seasonal thing or is it going to pick up -- are they going to pick up the drilling in there? I know this is a source of growth for your gas production over the next couple of years. I'm just trying to figure out or quantify the limits beyond that.

Right. Good question. Yeah. Part of the reason was the conditions were not favorable to be drilling up there. And so we didn't get as many welled drilled up there as we would have liked. We do have a number of wells planned to drill as soon as road bands come off and we can start moving rigs. So you will see an increase in the wells drilled in Canada.

We probably won't make the 60 this year, primarily because we've seen the employment market up there is very hot in Canada and it's very difficult to keep staff and we -- they are moving, essentially, it's musical chairs to keep staff up there. So that has put some limitations on how many wells we'll be able to drill. I would say that we probably won't drill the 60. It will probably be something less than that, but we are out there trying to expand the staff again. And what you will probably see, because of the Sukunka, is probably more of the deeper wells will take up that slack.

Okay.

In -- versus number, and we'll have some higher quality wells.

And the rig race has been kind of going out of control over there. Is that still something that you are seeing or that kind of isolated from other producers?

We have seen the rates go up about 20% and looking out into the future, they think it's going to flatten out some, maybe another 10% increase through the send of the year, but Canada, we have seen that kind of rate increase. California was already fairly high.

Okay. And then I think you talked about -- I didn't hear anything about High Island XXXVII. I think that was something you were evaluating at some point in time but I didn't hear you talk about that specific.

All right that is the fourth well that we had planned. We have our three shallow wells that we're going to be drilling with Chanex, and we're working with partners to ascertain whether or not we're going to proceed ahead this year or next with that 37 well.

Okay. Very good. Thank you for your time.

I would just like to kind of reiterate here that with the continued strong performance from that third Sukunka well, it's pretty clear that the fourth Sukunka well's results will be a big impact for us one way or the other.

Another strong performer there from the fourth Sukunka well would more than make up the differential with respect to how many wells we might not succeed in drilling versus our plan for Canada.

Got it.

And your next question will come from [Kathleen Putetic with WH Reeves]. Please proceed.

Good morning. I was wondering since you all are working on expanding storage if you could talk a little bit about the economics of new storage versus existing storage, and whether or not your storage expansion is predicated on the future gas price, or whether you have new contracts to back that storage expansion up?

The economics of new storage is that it's significantly more expensive to develop than old storage was. As you look at the incorporated $6 or 7 base gas and new storage that's clearly less economic than old storages that were built on 50-cent or $1 base gas.

On the other hand, there's limited amounts of old storage, and almost all of the old storage is price regulated. So there's not a tremendous opportunity to take those old storages and make incremental money on them by placing them at a greater market value than the regulated rates. Which is something I would dearly love to do but that's not the way it works.

The particular storage increment that we just achieved is an incremental deliverability and capacity of an existing old storage. So the cost of achieving that was essentially zero. With respect to the development of new storages, I think the market is going to support the development of new storages at whatever cost they might be. Now how many new storages the market will support is another question. But it's pretty clear that storage is becoming more and more necessary as the markets continue to expand.

I think the new storages may tend to be shorter deliverability storages, so perhaps you can turn them more often, so that they can be responsive to both the summer demands for electric generation for air conditioning and winter demands for heating, so that you may operate off two peaks rather than one. But you are still going to need to store during the shoulder months.

And to try to develop the storages with less reliability on base gas, perhaps drilling more wells, perhaps using more horizontal wells, to substitute other kinds of capital dollars for the dollars that you would have had invested in base gas.

Phil, do you have more capacities to expand existing storage?

We don't have as much -- we plucked the really low hanging fruit. You know, we continue to look at drilling additional horizontal wells in storage. We drilled a couple of those in previous years to try to get more bang for the buck from the existing fields, yes.

Okay. Thanks.

And you have no further questions at this time. I would like to turn the conference back over to Margaret Suto for closing remarks.

Thank you, Ann Marie. We now conclude our call and we, of course, thank everyone for taking the time to be with us today. A replay of the call will be available in about one hour on both our web site and by telephone. And both will run through the end of business on Wednesday, May 4th. Our web site address is www.nationalfuelgas.com. The telephone replay number is: 1-888-286-8010, using pass code 10530363. This concludes our conference for today. Thank you and good-bye.

Ladies and gentlemen, thank you so much for your participation in today's conference. This does conclude the presentation. You may now disconnect. Have a great day.