National Fuel Gas Co (NFG) 2004 Q3 法說會逐字稿

Good day, ladies and gentlemen. Welcome to the Q3 2004 National Fuel Gas Company earnings conference call. My name is Michelle, and I will be your coordinator for today. At this time, all participants are in a listen-only mode. We will be conducting a question-and-answer session toward the end of the conference. If at any time during the call you require assistance, please press star, followed by 0, and a coordinator will be happy to assist you. As a reminder this conference is being recorded for replay purse. I would now like to turn the presentation over to the host for the call, Ms. Margaret Suto. Please proceed, ma'am.

Thank you, Michelle. Good morning, everyone.

Thank you for joining us today for the discussion on last evening's earnings release. Today's presenters will be 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 today's 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 our belief 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 60 and 61 of the 2003 annual report for a listing of certain specific risk factors.

And with that, we will begin with Ron Tanski.

Thank you, Margaret. Good morning, everyone. As we announced last evening, consolidated earnings for the third quarter of our fiscal year were $32.56 million or 39 cents per diluted share. Excluding the minor non-recurring adjustment in our timber segment, earnings for the quarter were $33.3 million, or 40 cents per diluted share. Pages 8 and 9 of the earnings release detail the reconciliation between reported GAAP earnings and recurring earnings on both a dollar and earnings-per-share basis. All the details regarding the quarter and fiscal year-to-date comparisons to prior periods are in the earnings release. So I won't spend time repeating it all again here.

Like last quarter, it was the nonregulated segments that caused us to beat the high end of our quarterly earnings guidance by a dime. Commodity pricing in our exploration and production segment exceeded the high range of the estimate that was incorporated in our guidance back in April and made up 8 cents of that dime. Colder weather and increased electricity sales in the Czech Republic caused the earnings in the international segment to be higher than forecast and made up the other 2 cents per share. Minor variances in the other segments, none of which were significant, balanced out and were generally in line with our expectations. Although I will point out that efficiency gas revenues for supply corporation were $4.542 million for the quarter, in connection with volumes of 829,665 MCF.

The current high commodity pricing environment has allowed us to increase the earnings guidance for the fourth quarter to range of 7 to 12 cents per share, or guidance for the entire fiscal year to a range of $1.96 to $2.01, excluding the nonrecurring items. Our press release announced a preliminary guidance range of $1.75 to $1.85 per share for fiscal 2005. Let me give you an idea of the expected segment contributions to those earnings for next year. On the regulated side, in both the New York and Pennsylvania utility jurisdictions, we're facing a number of earnings pressures. Usage per account is still declining, and the sustained, high commodity pricing environment is putting continued pressure on our uncollectibles. In accordance with our last New York rate settlement, we filed documentation with the commission on June 1 that justifies the removal of a current $5 million bill credit effective October 1. We are also in the midst of preparing rate increase filings for both New York and Pennsylvania that we would expect to get on file sometime this quarter. Because we are still in the process of preparing the cases, it would be premature to discuss any details of the filings. Suffice it to say, absent an early settlement of these rate proceedings, the earnings in the utility segment next year are expected to be down slightly from this year's levels because of the pressures of the items I noted.

While you might expect the earnings in the pipeline and storage segment to be modestly higher next year due to some increased through-put, we plan to start preliminary spending on our previously announced Empire Millennium Connector. In line with our conservative posture on development expenses, we expect to expense a fair amount of these preliminary costs until our pipeline certificate application process is well under way. As a result, earnings in the pipeline and storage segment are expected to be flat. So, overall on the regulated side, we're looking at preliminary earnings numbers of $1.08 to $1.15 per share.

In our exploration and production segments, Jim Beck will provide a lot more detail in a few minutes, but with our announced expected lower production range, we expect earnings in this segment to be in the range of 55 cents to 60 cents per share. The marketing segment is forecast to contribute approximately 4 cents per share, with approximately 6 cents per share coming from the timber segment, while the corporate and all other will contribute 2 cents and offset a projected 2 cent loss in the international segment. Our capital expenditures for fiscal 2005 are expected to be as follows: in the utility segment, $54 million; pipeline and storage, $25 million; exploration and production, $88 to $93 million; international, $15 million; timber, $2 million; corporate and all other, $6 million, for a total of $190 million to $195 million.

Since June 30, our balance sheet has improved to show an equity component of 49%. After a slight dip at the beginning of our heating season while we finance our storage inventories, our positive cash flow projection for next year will allow us to be above the 50% equity level next year. We will be repaying another $100 million medium-term note next week, and we expect no capital markets activity through next fiscal year.

With that, I'll turn it over to Jim Beck to discuss more details about the exploration and production segment.

Well, thank you, Ron, and good morning, everyone. My comments this morning will be brief.

Seneca's earnings for the quarter are a result of the hard work of all our staff to maximize returns and reduce our operating costs. In addition to discussing the hows and whys of our quarterly results, we'll also provide you with a review of our 2005 forecast. While earnings for the quarter were up 106% excluding last year's impairment, production for the quarter was down 14%, primarily due to last year's sale of our southeast Saskatchewan properties. U.S. production was flat the last year. In our east division, production was down due to the weather delaying new well completions and accounting adjustments to actual production. In the west division, production was down mainly due to a decline in our older midway sunset wells. However, the good news came from the Gulf, where production was up nearly 11%. It should be noted that our Gulf division was able to increase production by placing 3 successful wells on production during the past year.

Seneca's goal is to maximize returns to its shareholders. If we can identify high quality, low risk, low-cost opportunities offshore, that meet our goal of providing double-digit returns, we're going to take them. For 2005, we anticipate drilling 4 to 7 wells that meet these objectives. I don't expect to see many more of these opportunities, but we will continue to look. As for the next offshore lease sale in August, we have not found any opportunities and do not plan to bid.

Seneca continues its onshore exploration plans. We plan to drill over 150 wells in 2005, and we're actively looking for an onshore acquisition opportunity. The other notable item this quarter was a reduction in operating expenses. Every category of expenses of lower on a quarter-to-quarter basis. This was the result of all our divisions working to become more efficient. The largest decreases were in the lease operating and production taxes. Over 90% of the $5.8 million reduction between these 2 items was primarily due to the sale of our Canadian properties last year.

Seneca is also continuing its program to help NFG achieve its 50-50 debt-to-equity ratio. During fiscal 2003, we paid down $139.5 million in debt. So far in fiscal 2004, we've paid down an additional $65.2 million. Looking forward to our expectations for the fourth quarter, production should be between 13 and 15 BCFE. We are anticipating at least one shutdown for a hurricane before October. While production would be slightly lower than each of the first 3 quarters for this year, we are still on target to reach our annual production goal of 57 to 62 BCFE.

Looking ahead to fiscal 2005, here is a breakdown of our expected results. A summary of this guidance can be found on page 17 of yesterday's press release. Production will be in the range of 50 to 55 BCFE with production composed of 53% gas and 47% oil. This guidance does not include any production from any of the 4 to 7 offshore wells that will be drilled next year or the Vermilion 96 discovery that we mentioned in our press release, even though the operator indicated in its press release on Monday that initial production would start as early as -- or in early 2005. Capital spending will be in the 88 to 93 million. This is flat to our 2004 forecast. And our plan is to drill over 150 wells. We maintain a living budget and will be moving capital dollars to the divisions where we are achieving the best results. The pricing used in our forecast was mimex [ph] based on prices based as July 22. The basis adjusted average oil prices for 2005 are gas price of $6.21 per MCF, oil price of $35.16 per barrel. This compares to our 2004 nine-month actual unhedged basis-adjusted prices of gas of $5.44 per MCF and oil of $31.28 per barrel.

Next is our expense breakdown on a dollars per MCFE basis. We are keenly aware that as our production decreases, our cost per MCF will increase. We are making every effort to bring our expenses in line with production. As you can see by our 2004 results, we have made some headway, and we are continuing to work to further reduce these expenses. Starting out first with DD & A, DD & A will be of $1.50 to $1.60. This is actually a decrease in actual dollars, but an increase on a per-MCF basis, due to increases in Canada and the Gulf. This is a slight increase above our 2004 actuals. LOE, LOE includes other taxes, but excludes other operating expenses. The range for LOE will be 91 cents to $1.03 for MCFE. This represents an increase from our 2004 year-to-date actuals. We are seeing across the board increases for all services, costs of all services. However, this will be a focus area for 2005 as it was for 2004, and we will attempt to minimize these increases.

Now a quick comment about other operating expenses listed on page 17. These are not included in our costs -- on our LOA costs. And these are mainly gas plan expenses. And in our consolidated report it's netted against plant revenue. So for a full year, that number is typically less than plus or minus $1 million.

G & A total expenses for the year in the range of $24 million to $27 million. Rather than provide on a cost-per-MCF basis, it's more appropriate to provide an actual dollar range since G & A costs only partially impacted by production. This range is higher than the 2004 actuals, primarily due to higher pension expense, increased costs to retain personnel in a market that is heating up, and expansion of our east division staff. Moving onto hedging. Hedging for 2005 can be summarized as follows -- 13.2 BCF of gas production is hedged at an average price of $5.87 per MCF, and 2.8 million barrels of oil production is hedged at an average price of $30.44 per barrel. Based on our average prices we just provided, the earnings sensitivity for these price changes for 2005 is as follows: for each 25-cent change in the average gas price for the year, earnings will change by 3 cents per share. For each dollar change in the average oil price for the year, earnings will change by 1 cent per share.

For fiscal 2005, we have three key focus areas. First, to live within cash flow. Second, to continue our growth via successful -- via success through the drill bit. And lastly, to initiate an acquisition program in Seneca's key onshore areas.

At this point, I'll turn it over to Phil.

Thank you, Jim.

We had another good quarter, as well we should have given the extraordinarily high levels of oil and gas prices. $32 million or 39 cents per share puts us on track to earn about $2 per share this year. Last month, the board increased the dividend for the 34th year in a row to $1.12 per year. Giving us about a 56% payout ratio. Strong cash flow and modest spending has raised our equity ratio at June 30 to 49%. Production of 15.2 BCFE keeps us on track for our projected 2004 production of about 60 BCFE.

The bad news with high gas prices is their impact on our customers, which translates into increased cancelation and increased payment difficulties. Payment difficulties, to one degree or another, have been a fact of life for years, and we were well aware that prices would be high this past winter. By promoting customer awareness, balanced billing, LIHEAP, and other programs, we kept this potential problem from getting out of hand. The vast majority of our customers want to pay their bills on time. And our total receiveables as of June 30 this year are less than they were a year ago. They are higher than June of '02, but again, they are less than they were in June of '01.

Our final bills, that is amounts owed by accounts which are no longer active are only $1.3 million more than they were in June of 2001. That is the last time we had a big price run-up. For 2005, we have a variety of factors which we see reducing earnings to the $1.75 to $1.85 range. But we will be working diligently to rectify those situations in future years. A decline in production for 2005 is anticipated. But the Sukunka L [ph], the discovery in west Cameron, and additional drilling in 2005 should all help 2006 volumes. Rate cases in 2005 should also help 2006, and the expense of pipeline project costs in 2005 should begin to generate profits in 2007. In short, 2004 should be an excellent year. 2005 should be a very good year, and we are looking forward to 2006, 7, and beyond.

I'm sure you have questions about the details that we've presented. Operator, I'd like to take those questions at this time.

Michelle, we're ready for the q-and-a part.

I'm sorry. [Caller Instructions]. Your first question comes from Rebecca Followill from Howard Weil. Please go ahead .

[Technical Difficulties] -- Relative to '04 and '03, what's that going to, and that I'll follow up just after each question. Thank you.

Rebecca, I'm completely sorry. The only part of that question I heard was the '04 and '03.

Okay. Let me start over again. International, CapEx you talked about $15 million for '05.

Yes.

And I had in my model $11 million for '04 and $2.5 million for '03. That may be incorrect. Can you talk about where that increased CapEx is going?

Basically, the CapEx for '05 is utility related investments in the Czech Republic. Having -- some of it has to do with air-quality equipment, some of it has to do with a proposed pipeline to enable us to use our own steam to serve our particular area as opposed to purchasing steam from a third party. And another element of that has to do with the retrofitting of a -- another boiler over there.

So it's going to existing facilities as opposed to new investments in incremental facilities?

It's going to the same project, as the pipeline would be in incremental facility, but it's for the same line of business in the same company, in the same country, i.e. the Czech Republic. It's not a new business.

Right.

It's -- it's a utility-type investment, that appears to have very attractive economics in terms of reducing our cost of steam.

Great. Thank you. And then on the E & P side, talked about that one of your goals for '05 is an acquisition program. Included in your $88 million to $93 million CapEx number, does that include potential acquisitions, and where are you looking at making acquisitions on shore?

That does not include any potential acquisition, and we're looking at acquisitions ideally in areas where we already operate. So we -- we feel our opportunities to achieve some synergies in connection with existing operations are better than going into a new basin or some area where we don't already operate. You know, the degree to which we will be successful in finding an acquisition that meets economics for us is -- is a question I think everybody has those questions. But we are going to be looking, we're not going to lower our standard for the sake of making an acquisition.

What kind of price decks do you assume when you're making acquisitions? Are you a flat price, you use the strip? What's the parameters that you go in to evaluate?

We're going to look at the pricing that we would be able to hedge production for, as we run the economics on the acquisition.

How far out?

Generally as far out as -- as far out as it takes to pay for the cost of the acquisition.

Okay.

You know, whenever payout would occur.

And two more quick questions. I'm sorry to take so much time. On E & P spending year to date, I have that it's about $58 million compared with your budget of $90 million. So, is a lot of this back end loaded similar to what it was in the fourth quarter of 2003?

I think that's correct.

Okay.

Jim, do you have any comment on that?

Yeah, some of that is for planned development expense offshore. And a lot of that we just don't know what that number's going to be. So we could come in under that budget depending on what happens on the development expense offshore.

Okay. And then final question. Big picture on cash flow, you're generating a substantial amount of cash flow and after the CapEx spending that you've outlined in dividends, you still have free cash flow. Debt to cap is down to around 50%. What are plans at this point to do with incremental cash going into '05 and '06?

Well, one of the things that we're looking for is expending a fair amount of cash on the Empire Millennium Connector project. We're going to spend -- modest amounts beginning immediately and doing environmental work and that kind of thing. But as we get into '06, that can be a very hefty construction program for us. So to some extent we're keeping our powder dry in connection with that. You know, so, too, we talked a little bit just now about potential acquisition on the E & P side. And then finally, you know, I don't think we should rule out, if -- if we have more cash than we know what to do with, the possibility of some sort of a stock buy-back program. You know, if there's -- if there's nothing else to do with the money, that certainly is a reasonable option.

Thank you very much.

Again, to ask a question, that's star followed by 1 on your touchtone telephone .

Michelle , there anyone else?

Yes, ma'am. Stacy Saul from WH Reaves & Company. Please go ahead, ma'am.

Hi. Stacy Saul, WH Reaves. Just one question. On international, you mentioned that weather was 22% colder than last year. What was it versus normal weather ?

Can you give us a minute on that one? We don't -- We don't have that number handy here. We're scurrying about --

Yes, Margaret can just get back to me.

I think that's what we're going to do on that one. We -- we're not quite as up to speed on the weather in the Czech Republic as we are --

Okay. Actually, I do have one other question. How much of your interest -- your debt is fixed versus floating? And you said you didn't have any plans to go into the capital markets over the next 15 months, but would you term out any of the debt?

Stacy, the only thing that we're going to have basically on a floating basis is the short-term working capital that we're using to finance the working -- or the storage gas right now. We have a slight uptick next week when we repay the $100 million medium-term note that comes due. But with the cash flow that we've had and the decreased CapEx program compared to prior years, we're -- basically out of the commercial paper market, and only have small amounts outstanding in the short-term debt. So everything else is -- all the long-term debt is fixed.

Okay, great, thank you.

Michelle, is there another question ?

The next question comes from Peter Hark of Talon Capital.

Yes, a couple of questions on the utility, if you could. First, what are the ROE's you're earning now in both Pennsylvania and New York?

In -- in about both, because of the pressures that we've mentioned, we've dipped below 8% in -- in both New York and PA. As I mentioned, we're in the midst of putting together our detailed testimony for filing for probably next month. I would hate to get into more detail on that now.

Okay. That's fine. What is the equity base at each one of those units?

In our system we're using the cap structure of the parent. So it's about 50/50. And --

On how sizeable a rate base?

And the rate base -- let me get that number. Sorry, I don't have it right at my fingertips.

That's fine. I could get back for Margaret or --

I think we'll have it here before the end of the call.

We'll have it actually right here. In New York, the $658 million --

I'm sorry, say again.

In New York, $658 million. In Pennsylvania, $257 million.

Okay. And -- and that's 50% equity roughly earning about an 8% ROE. That type of --

No. Actually it was a -- 8% return on rate base.

Okay. Okay could good. Thank you. And then, then shifting over to -- you said in '05 earnings guidance that you were going to be absorbing O & M associated with the Empire Connector, and I didn't know how much that was going to be and whether that was going to be a run rate for O & M going for '05 and beyond.

At the outset, we're looking at approximately $2 million to be spent beginning, as Phil said, almost immediately, carrying on into fiscal '05. That -- those are the preliminary dollars that we expect would get us to a point in the -- in the certificate application process that we would probably start to capitalize after that.

Okay. Okay. Then lastly, I might have missed this. What's your projected production levels for 2005 versus -- relative to '04?

Jim could you have that number?

Yeah, that is 50 to 55 for 2005. And we're 57 to 62 for 2004.

Okay. Perfect. Thank you, everybody.

And your next question comes from Doug Christopher of Crowell Weeden, please go ahead, sir.

Hi, good morning. Just -- going back to the utility, I think you mentioned that you're going to be removing I think it was a $5 million credit on October 1. Could you go into a little bit more just detail on that. Is that $5 million -- per month or how -- what's the impact to the results?

Okay. For that particular credit, that goes back a number of settlements -- or I'm sorry, a number of years ago in our New York jurisdiction, where we settled the proceedings, and it dealt with dollars that would -- had been collected in pipeline refunds. Through -- no.

In simpler terms -- it's $5 million per year as opposed to per month.

Okay. Okay, now -- and the impact there, and I guess summarizing this would -- you're talking about the rate cases, and I know you mentioned it was premature to go into any detail there. But is there a potential impact sometime in fiscal '05, like, you know, in -- by next year when we're talking at this time, or is it longer than that?

If we assume a -- a filing in August, the suspension period for the New York case would be 11 months. So we would --

Okay.

So we would be, say the beginning of August, not during the heating season in New York. So it wouldn't be much help for 2005, fiscal year. In Pennsylvania, it's a nine-month suspension period.

And then lastly, just overall and strategically, your guidance that we're looking at, preliminarily 175 to 185. Do you view that as conservative? How do you view that? How do you characterize that?

I want people to view me as conservative. I'm trying very hard to come up with realistic production forecast numbers. I'm very pleased that we're going to meet the production forecast numbers this year. And that we've -- we're on track after 3 quarters to do that. Those people who've been following the Company for a while will realize that that's the first time in too long that we've done that. And I'm very happy that we've raised our earnings guidance a couple times this year, and with respect to 2004, and I would be very pleased if we're able to do that again in 2005.

That's great. Thank you. You're doing a great job.

And your next question comes from Philip Salles of Credit Suisse First Boston. Please go ahead, sir.

Thank you very much. First, I want to compliment you on the press release. Probably one of the better ones this reporting season. And I appreciate all the additional information that you provided. I'm glad finally a company's kind of listening to what we're asking for. Just a couple of quick questions in the EMP group. And I noticed that the Appalachian production was down sequentially, third quarter versus the second. And just if you can give us some color there, it would be appreciated.

Yeah. That -- part of that change, as we said, number one, the -- putting the new wells on production, it was very rainy and delayed putting some of the newer wells on. The wells that we had put on last year are starting to decline. And so we're seeing some of that impact, and so we didn't get the newer wells on to make up for that loss. The other thing that happened is we have an accrual system where we estimate production each month, and then it takes about a two-month lag to get the actuals. And so that's the accounting adjustments, and they'd overestimated in January and February, and then that had to be reversed in the third quarter. The actual production really is -- is much more -- very consistent there. Very flat, and it's really more an accounting situation than it is a change in production.

What kind of decline rates do you see out there, Jim?

Well, one -- the older wells, the decline rates are very low. They're in the 3% to 7% range. On the new wells, they will decline upwards of 50% in the first year, and then they flatten out and get to that 5% to 7% over a couple of years.

I see. Thank you. And as long as you have the microphone, I'll -- just continue. LOE expenses up in your guidance, you know, 10 to 20 cents. Pretty wide range there. You know, what are you seeing on the service side, and, you know, what -- what are your thoughts and that you're including in those assumptions?

Well, the key ones there are work-over costs and rate costs. We're seeing a dramatic increase for work-over costs. All of the service companies are taking advantage of these high prices now. They're feeling very comfortable that we're into a higher price regime and they've all started bringing -- bringing those costs up or charging more for their services, and so we're seeing a significant increase in work-over rig, services, mud, any kind of activity in the field. And so that's one of the main drivers. The other big driver in those costs going up is that production is going down. And on an MCF basis when we give you that number, it makes it look -- actual dollars aren't going up that much. But because production is going down that automatically means you're going to see an increase on an MCF basis.

Well, thank you. You -- you talked about the exploratory drilling that that's ongoing. Could you give us some additional, you know, insights. Could we get our arms around, you know, what kind of reserves you're looking for. You did talk about the one in west Cameron and possibly going commercial. You know, or at least having some more information on the development. But could you just, you know, when will Canada go commercial? When can we see some, you know, initial production coming out of both Canada and the west Cameron?

The key there is that we're not the operator. You know, typically in the past, we've been the operator, and so we can tell you what our plans are and give you ideas as to when we expect production to come on. But both in Canada and on the west Cameron block, we're not the operator. So we have to depend on them to tell us what they're going to do and when they're going to do it. And right now, as I said in the press release that -- the operator in west Cameron 96 did, he said he thought it was to be on sometime early in '05, but we have not received any information, and I don't know when that would be. So rather than put that production in the numbers, we just leave it out. And if he's right, well, then that will -- that will be a little extra for next year. Same thing in Canada. We depend on Talisman to tell us what they're going to do. In the way of putting wells on production and testing, and those kind of things. And, too, so far this year, they have not given us any information. I'm sure when they make their determinations, we'll see some kind of press release from them. And then maybe that will give you an idea as to what we can anticipate.

Well -- is there any idea of IP, what you're looking for, ultimate recoverable reserves from, you know, either one of those regions?

No, that's -- the key in all the areas is to have some tests and until you get a test, you can't book any crude reserves. So at this point we don't have tests that we can -- can use to reference what it would add in the way of reserves or -- or what it could do in the area. So right now, we're -- we're sort of waiting just like you are. And as soon as we get that information, we will get it out. Now the other part of your question on the exploration offshore, we do plan on drilling those 4 to 7 wells. Those will be typical of the kind of wells we drilled in the 1990's. They will be low cost, they will be for the most part normal pressure. And would add reserves hopefully fairly quickly, and as we drill those wells and bring them on, we will update and provide that information as soon as possible.

Part -- I appreciate the answer. And part that answer was a perfect segue to my last question on reserves. You know, this was the -- a while where in past you hadn't really talked or pointed to acquisitions as being a driver, and -- you know, I'm hearing the comments today that, you know, as to -- as to a potential possible acquisition. Could you just, you know, shed some light on reserves, and, you know, will -- will we have some reserve adds, will reserves continue to decline, kind of what is your recent thinking and outlook?

Okay. Well we can't -- you know, it's very nebulous. A lot depends on getting these wells that we talked about tested and analyzed, and then be able to come up and give you a definitive number on reserves. Obviously, if -- if they're commercial, we will be adding reserves on both of those projects. And they'll -- if we get them tested in the fourth quarter, then we'll be allowed to book some reserves and we'll be able to tell you something on the reserves. I would say -- I would anticipate for the -- for the year, we'll see a decrease in the overall reserve picture. It may -- it's not going to be real significant, but we are producing at a very solid rate. And at this point, I'm not sure we'll replace 100% of those reserves that we're going to produce. So I would expect a slight decrease, but with the programs coming up in '05, I feel a lot more comfortable because we've got such a number of wells to drill. Both in Canada, in the Gulf, plus our ongoing exploration in -- in the east that will make up for it in the next year.

That's great. I appreciate all your time and answering my questions. Thank you very much.

Phil, I'd like to make a little editorial comment here. Your questions are good ones and reasonable ones. But with the magnitude of the fine that Shell is facing with respect to the suspicions or the -- the uncertainties surrounding the reserve numbers that they had come out with, we're obviously reluctant to make any kind of reserve announcements where we don't have third-party audit of those reserve numbers. I've -- kind of admonished Jim to dance around those numbers. And I stand by that admonishment.

I didn't consider Jim's answers a soft shoe. I appreciated his comments --

That's too bad. I'm going to tell him to be more soft next time.

All right. Thank you.

And I would now like it turn the presentation back over to Margaret Suto for closing remarks.

All right. Thank you, Michelle. I will presume there are no further questions for us. We'd like to thank everyone for taking the time to be with us today. And a replay of the call will be available in about one hour on both our website and by telephone. And both will run through the end of business on Friday, August 6. The website address is www.nationalfuelgas.com. The telephone replay number is: 1-888-286-8010. And please use pass code 67746105. And this conclude our call for the day. Thank you very much and good-bye.

Thank you for your participation in today's conference. This concludes the presentation. You may now disconnect. Good day.