Southwestern Energy Conference Call
Company Summary
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2001 Strategy and Outlook Conference
Monday, December 18, 2000
Chaired by
Harold Korell
President and Chief Executive Officer
Korell: Good morning and thank you for joining us for our 2001 strategy and
outlook conference. With me today are Greg Kerley, our Chief Financial Officer;
and Brad Sylvester, our Manager of Investor Relations. Before we get started,
our attorneys have asked that I point out that some of the comments during this
teleconference may be regarded as forward-looking statements, that involve risk
and uncertainties, which are detailed in the company's Securities and Exchange
Commission filings. While we believe they are reasonable representations of the
company's expected performance, actual results could differ materially.
Another point I'd like to make is that we are web casting this
teleconference simultaneously with a slide show. For the first time, I might
add. So make sure you click on the link to view the supporting slide show. In
the event you are listening to this web cast live, I'll tell you when to go to
the next slide. This teleconference will also be archived on our web site at
www.swn.com.
Before getting to 2001 and the outlook, I'd like to share with you a
few statistics about our performance for the year 2000. Operationally we are
having one of the best years that we've ever had as a company. We expect to show
a production growth of 8% over 1999 volumes, accomplished primarily with a drill
bit. Reserve replacement this year should be near 200%, versus 150% in 1999,
again primarily with the drill bit. 63% of our capital investments in the E&P
area this year went to the drill bit. Our finding costs should come in near our
target of $1 per Mcfe, and something we're even more proud of is that we
continue to grow our inventory of exploration projects, which provide the fuel
for out future drilling activity.
Our challenge this year was the Hales judgment of $109 million. As you
know, we increased our borrowings to fund that payment, and as a result, we
announced in June that we would pursue the sale of our utility business. I'd
like to talk for a few minutes about that activity.
Since July, Morgan Stanley has been running an auction process for the
sale of the utility. As a result of that process, we have received several
serious expressions of interest from bona fide parties. However, in the
company's judgment, to date we have not received an offer that reflects the true
value of our utility company. Accordingly, at this time the sale of the utility
is not imminent. The bottom line is, we're comfortable holding the utility
assets for the time being, until we are able to get an acceptable price.
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From a financial perspective, the utility will provide in excess of $19
million of EBIDTA next year, and requires $6-7 million of capital expenditures.
Thus, the utility generates sufficient cash to fund its capital requirements,
and provides excess cash flow to pay down debt. Although we have not found a
buyer for the utility, we are fortunate to have benefited from the gas price run
up over the past few months. This has afforded us the opportunity to hedge a
significant percentage of our targeted 2001 production, at price levels
sufficient to fund our expanding E&P program, and improve our balance sheet. We
will not sell the utility until we are able to obtain a price we feel is
adequate.
Looking forward, we will continue to focus our management time,
primarily on the E&P business, as the growth vehicle for the company. Now I'd
like to turn to the strategy and outlook for 2001, which means that each of you
should go to the next slide titled, `Strategy for 2001'. We will continue to
pursue the sale of the utility on appropriate terms. In the way of background,
as we look at utility transactions that have been done this year, versus the
year of 1999, 2000 has certainly not been as robust a year for activity. Clearly
effecting the transaction we were targeting to do. Of course commodity prices,
as I mentioned earlier, are certainly helping us, and provide additional timing
for us to do that transaction.
The second part of our strategy is our hedging strategy, and we have
hedged approximately 80% of our 2001 gas production, which gives us the
flexibility to pay down debt, allows us to fund our expanding capital program,
and gives us the opportunity to pursue our E&P strategy, which has been building
momentum over the last couple of years.
Our capital program for 2001 will be approximately $82 million, that's
up 9% from the 2000 investment level. Nearly all that capital, $75 million, will
go into the E&P area.
Now if you would move to the next slide, which is titled `Core
Operating Areas'. This slide is a snapshot of our operating areas and defines
our overall E&P strategy for 2001. Shown on the side are the reserve and
production metrics for each of the focus areas, along with, shown in yellow, the
2001 capital investments for each of those areas for our plan. The Arkoma Basin,
what we like to call the legacy asset of the company, provides a stable base of
production and reserves, and our strategy for the Arkoma Basin again in 2001 in
one word, would be described as `maintain'. That is maintain our reserve and
production levels in the Arkoma.
In 2001 we're planning to invest about $21 million to drill 53 wells,
in which we would have an average working interest of 50%. We always like to
keep as much of that as we can at a higher working interest.
Moving to the Mid-Continent, this is an area we plan to exit. 'Harvest'
is the one word that describes our strategy for the Mid-Continent; we've reduced
our expenses in this area, and will either produce these reserves out, trade
them or sell them, as is appropriate.
Moving further south, the Permian Basin in west Texas and southeast New
Mexico, along with our east Texas area, represent the medium risk layer of our
portfolio. We've had significant
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success in the Permian over the past three years, and in 2001 we plan to
continue, by participating in 25 wells, mainly targeting the Atoka / Morrow
play.
In east Texas, we plan to drill eight wells, we would in fact like to
drill more there, in the Overton Field, and I'll talk a little more about that
in just a minute.
Finally, our exploration program in south Louisiana represents a higher
risk, but higher potential area. We're planning to drill a total of nine wells
there, including six exploration wells. We have two development wells planned in
North Grosbec in 2001, on our discovery from this year.
Another fact that we're really happy about is that our plan would
indicate that, of our E&P capital, 75% of the capital will go to the drill bit
in 2001.
Now if you would move to the next slide, titled `Overton Field
Potential'. This shows a map of the Overton field in east Texas. We acquired
this property in April of this year. We acquired about 7.5 billion cubic feet of
reserves for about $6.1 million. We made this acquisition primarily because it
was one of the few fields left in east Texas that had not been down spaced from
its 640-acre spacing. In other words, there's quite a bit of potential here to
increase the number of wells drilled, and therefore increase the production and
reserves in this field. We spent the majority of this year, after we bought it,
doing regional geological and engineering work that was necessary, and in 2001
we will start our infill drilling program.
The field currently has 16 active wells; we're planning to drill at
least eight more wells here in 2001. It represents a significant low risk
project for us, and for those of you looking at the slide, there's a little box
there that shows the number of wells, and potential of reserve if we were to
down space it all the way to 160.
Now moving onto the next slide, entitled the `Atchafalaya Mini-Basin',
you'll see a map of the mini-basin, in south Louisiana, where we've been active
in exploration. We've had two discoveries within this area in the last 12
months, both generated by our in-house team of people. Our first discovery that
came out of this 3-D seismic area, was at Gloria, in fact about a year ago, it
was December 1999. And as you can see by looking at the information on the
slide, the Gloria prospect, the one well that's producing there, is still
producing in excess of 9 million cubic feet of gas per day, and over 300 barrels
of condensate per day.
Our discovery at North Grosbec, that's another one of the red blocks on
that map, occurred in February of 2000, and its proved to be one of the largest
discoveries in the company's history, and continues to produce at very high
rates. Again that rate shown there, over 15 million a day, and nearly 600
barrels of condensate a day. Our plan for 2001 includes drilling two offset
wells on the North Grosbec prospect.
We're currently drilling at Malone, which is shown there a bit further
south of Gloria, and we're encouraged at this point with the drilling that's
going on there. We should know something there in the next couple of weeks.
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Our North Jeanerette prospect in Iberia and St. Martin parishes, is one
of our high potential prospects, and will be tested in 2001. You can see the
size of it, its in excess of 390 bcf, as we would see its potential. Again,
that's something we'll be drilling next year. We have several other prospects in
south Louisiana that are not shown on this map, because they're in different
areas of south Louisiana. But all in all, there is a significant potential of
reserves for us to be targeting with our exploration program there.
Now moving to the next slide, the one that's titled `Outlook for 2001'.
We're targeting a production volume of 38 bcfe next year, which would be about a
7% increase over our expected 2000 levels. There are financial numbers presented
on this table, with assumptions for different levels of gas price. For example
if gas prices turn out to be $3.50 and oil at $25, the numbers shown in the
column below that would be what we would expect, with prices at those levels.
And then we've also presented a $4.50 and $5.50 gas price. Those financial
indicators shown on the table take into account the effect of the hedges that we
have in place at this time.
Now moving onto the final slide, the one titled `The Road to V Plus',
basically the road to adding value. The points of our strategy are shown there,
and that is to continue to pursue the sale of the utility on our terms, stay the
course with our balanced E&P strategy, which I've described briefly. Build on
our exploration success, reduce debt or improve our balance sheet using excess
cash flow, deliver the numbers, we know we need to increase production and
reserve volumes. And we're targeting doing that, primarily through the drill
bit. And adding value for every dollar we invest. And finally, to increase our
cash flow multiple to those of our peers. All in all, as I sum up and look
forward to 2001, I couldn't be happier operationally about this company. We have
had a continuing success built from '98 to '99, and 2000 will be an even better
year than the prior two years, regarding our fundamental strategy.
I think that pretty much wraps up the prepared comments. If the
operator would take this over at this point, we're ready for any questions that
people might have.
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Questions and Answers
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1. Just a question on the debt itself that was associated, kind of the debt that
you brought on. Actually I don't remember all the terms, I guess I figured just
mentally that would be paid down as the utility was sold. Is there anything
special that happens with that debt? Is there any sort of term that we have to
be aware of? Or is that one where its just expensive money, and you just have to
keep paying it down with this excess cash flow?
Kerley: The terms that we have on the debt right now we've been fairly pleased
with. You remember that's borrowing at LIBOR plus about 112 basis points. Our
other long-term debt that we have with the company is about 7%. The debt that we
took on as a result of the judgment is higher than that, but it has been less
than 8%. That debt was put up as a 12 month facility initially, and we're
discussing with the banks right now extending the terms of that. So that's where
we are on that.
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2. Fair enough, so really you've got some more time. When does that 12 months
end? Is that some time in June or May?
Kerley: It is in July of 2001.
3. And then just one quick question on the E&P side, is there any thought of
going beyond the budget laid out if there is that incremental cash flow, as you
look at that matrix of what you might expect from cash flow, is there some
thought of taking excess cash flow and putting more into E&P projects, or would
it all go into paying down debt?
Korell: I think that what we will do in fact, will be guided by the
opportunities that we have in front of us at that time, versus our desire to
reduce the debt. And in addition to that where prices are at that point in time.
The one kind of project that we strongly have a desire to do more of as we view
it right now, is more drilling at Overton. And of course by the time we get
further into the year, we're going to know what those results are. And if gas
prices are still at a very high level, the turn around on investing in Overton
could be very much of a plus thing to do, rather than paying down debt at that
time.
4. Just on the budget, have you all been able to, or do you feel pretty
comfortable about securing the services and the rigs that would allow you to
affect that capital budget? Or is that still in limbo?
Korell: Well, as you know, the availability of services have tightened, and the
prices have gone up. And we've factored the reasonable price increases into our
plan. We began about two months ago to lay out the entire drilling schedule for
2001, and to lay plans along side of that to secure the equipment, particularly
the drilling rigs, to carry that out. And it would appear that although we will
be in a tight market, it would appear that we will be able to accomplish this
plan because of the planning that we've done in 2001.
5. Looking at the way you broke the budget out and assuming that the Arkoma and
the Permian are more or less bread and butter kinds of things, can you give us a
sense of what kinds of finding costs you're budgeting out there? Is it $1.25?
I'm trying to make the assumption that you're going to more or less replace
production in those areas, and its all upside in Louisiana. Is that a fair way
to look at it?
Korell: The answer to your first question is, when we sum up our entire capital
plan, we come out, and this sounds like a real specific number, but about $1.07
per mcfe. There is certainly upward pressure on prices of services, so we'll be
subject to things being not altogether in our control on that.
6. Given your answer, I'm assuming that south Louisiana is part of that $1.07,
but obviously you're risking some kind of, the amount of gas you'll recover
there. I guess I'm coming to the conclusion, rightfully or wrongfully, that with
good success here the number could come down, but if you fail it could go up. Is
that fair?
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Korell: Well our budget is built on, as you are correct, on an expected value
basis, where each one of our prospects, we risk internally at some probability
of success. The Arkoma Basin we are fairly sure in our results there, and so we
tend to have a higher probability of success, hence I describe it as a lower
risk. And the probabilities of success are in the 70% range. The Permian Basin
and east Texas area, we have some exploration in there, and it would be viewed
generally as higher probability of success than south Louisiana, but lower than
the Arkoma.
When we move into south Louisiana, we tend to get into what our beliefs
are that have lower probabilities of success, although this year based on our
results this year, we've had a very high probability of success in south
Louisiana. But nonetheless we have continued to risk things at more reasonable
levels. So if all of them work out our finding and development costs would be
lower than $1.07. Adversely, if none of them work out, it would be higher.
7. Let me follow that up then with a quick one on North Jeanerette. Can you give
a little more specifics on that, as how deep is it, what's the formation, when
do you think you'll spud, just in general terms? How long will it take to drill
it? I mean that's an awful big prospect.
Korell: You're right. It looks like in our plan North Jeanerette is in the third
quarter; it's a 20,000-foot deep test. We'll be seeking partners for that as we
go along. Fortunately we've not had much problem here recently with people
signing up for exploration prospects fairly readily. That was a big one, but it
is later in the year, and we would view it as a lower probability of success
than a number of the other things we have.
8. So you're 100% today, and expect to be promoted down, get down to 25% and not
have to carry a lot of the drilling costs, is that the general plan?
Korell: We will be seeking partners for it. Al Stevens is not here with me
today, and Al would be able to answer that specifically as to what our current
partnering is there. But I think we hold most of it.
9. Is NOARK; is that part of the assets that were put up for sale? And I believe
your partner was Oneok in that, if I remember right. If it was part of it, was
that a stumbling block? With Oneok's significant shareholder kind of going
through its own restructuring? Was that a problem in terms of the asset sale?
Korell: NOARK was not part of what we were offering for sale. It's not part of
the utility. We were just offering the assets within the utility, and our
partner there is not Oneok, its Enogex, so I don't think it had anything to do
with it.
10. Ok, is it fair to say that Oneok, was maybe, in terms of its interest in you
and the utility somewhat restricted given what was going on at Western
Resources?
Korell: Well I don't think I should talk about who the parties were who were
interested in the utility. I won't do that today. I will just say in general,
the market for utilities this year was not what it was in 1999. You look at the
number of transactions that occurred. We do know that, I think that it would be
people like you that follow these other companies would know that some of
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the companies who you would consider possibly to be strategic buyers for our
utility assets have problems of their own, or had done other transactions or
something of that nature.
11. Can you give us a little more detail on the Permian details for next year,
the number of wells, number of exploratory wells?
Korell: We have 19 exploration wells, and six development wells that are
planned in the Permian Basin.
12. Do you plan on drilling deeper than the Atoka and Morrow?
Korell: We do have some tests that are deeper than that, yes, Devonian tests.
13. Just some more, if you could, about the Mid-Continent sale, you talked a
little bit about it. But say maybe some timing, or how you plan to go about it.
And then I see that you don't have any capital expenditures planned, so the
assumption is that you would do that early. Assuming some proceeds from that,
where would you most likely see those applied?
Korell: We've been pretty much saying the same thing about the Mid-Continent now
for a year or more, and what we have done in the Mid-Continent, its not as
though we haven't done anything. We have sold off the bottom end of those
properties that we had in the Mid-Continent in two different auction processes
that we think brought more value than they would if they had been packaged with
the sale of the higher end of those. And so we've cleaned up the bottom end,
we've reduced our costs there. And our thought, and our strategy there is to
sell or trade those, trading is always hard, and doesn't really ever seem to
occur.
At some point we will sell those assets, and what we would like to do
is redeploy those in an acquisition in the Permian area, where we have a greater
focus. We will have some very minimal amount of capital going to the
Mid-Continent, basically the Anadarko area, which I would call maintenance
capital, or capital where others might request a well be drilled, and we have a
very small working interest.
14. It sounds like the proceeds would be used more to find other areas to go
into, more just to expand your presence in some areas you're already in.
Korell: Yes and notionally you can think of the acquisition that we did of the
Overton field in east Texas was that way. In 2000 we sold, about $12 million
of low end properties off the bottom at auctions, in the Mid-Continent. We took
roughly $7 million of that to deploy in the Overton acquisition, where we saw
a real opportunity for developing additional reserves.
15. A question about North Grosbec, what about timing there on your development
wells? Do you have a partner lined up there for the development wells, and who
is the operator there?
Korell: At North Grosbec we have a partner already, the people who drilled the
discovery well with us. Petrohunt is the operator of North Grosbec, and I'm
trying to think of when the first development well will be drilled there. Is
that a February date they're supposed to
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start there. They had to build a fairly long road into the location that they'll
be spreading that well from.
16. So sometime in the first quarter, or the first part of the second quarter
for the first well.
Korell: Yes.
17. Following up with at question about the sale of the utility. How long have
your investment advisors, I mean we're talking about putting this off for a year
or two years, or indefinitely?
Korell: Well I wish I knew the answer completely to that. We think that we have
been through a very thorough process with the auction that Morgan Stanley ran
for us here recently. The result didn't yield an offer that we thought was
acceptable, and we will continue to seek a buyer. We are past the formal process
part of that, and when it would happen would be when we receive an offer that we
feel like is a fair price, an acceptable price, one that is accretive to the
shareholders. The timing of that is hard to predict. As I mentioned earlier, we
do know that some of the logical buyers were pretty well tied up doing some
other things this year. But of course the market in general was not as robust as
it was in 1999. So I don't have a specific answer for that, but I think I've
answered it as specifically as I can.
18. Well it sounds like we shouldn't count on it, if somebody as good as Morgan
Stanley has looked for you. I'm sure that they've turned up everything that
they can. Thank you.
19. On the sale of the utility, what really makes you think that that market
gets better down the road? I mean I guess I could think in a case of rising gas
prices the values of utilities drop, maybe I'm wrong. Two, where are we at
really on these Mid-Continent assets? Are you definitely going to sell those
assets? I mean clearly with gas prices at record highs, it seems to me timing
would make sense. And why wouldn't you use those proceeds to repay debt, I
guess, instead of reinvesting in some other area? And kind of what is the game
plan in handling the debt going forward?
Korell: Well the game plan is to use our surplus, our excess cash flow above the
levels that are required to support our 2001 capital program that I've outlined,
it will be about $82 million. The plan is to use the excess to pay down debt
next year. We have fixed our level reasonably well by the hedges that we've
done, and that's the reason that we've done the hedging there.
The intent would be that we would want to reduce our debt further as we
go along with any excess cash flow that we have beyond what we can see in our
plan, unless we have a capital investment that is something we can see a real
short pay back and turn around on.
Now as to why we wouldn't just outright sell our Oklahoma assets
immediately, we are generating a good cash flow out of those projects as well. I
haven't seen a lot of transactions done right now. Although gas prices are
extremely high, I think the bid ask is, what's bid or what people are willing to
pay, or what people want, or what cash flow multiples might be on transactions
is in kind of a wild time right now. So is this the right time to sell the
Oklahoma assets? I don't know.
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Why we want to just sell them outright, and not invest that money into
other projects? Generally speaking, nearly everyone that talks to us wants to
see growth in production and reserves, and anything we sell, of course, doesn't
do that. Our preference would be to sell the utility. Why do I think we might
see a higher price for the utility down the road? I can't predict where the
cycles are going to go in regard to a utility asset, that's beyond my control. I
do know that some of the logical players really were not available to play this
game in the way that they would have in 1999.
20. Again following up a little bit on the utility, if I could. You made the
statement that you wanted, that you did not want to sell it unless it would be
accretive to shareholders, and I assume that means book value. Are you saying
that you did not get any offers in excess of book value?
Korell: That's not what I'm saying specifically, I don't want to discuss the
price or the level of the offers. And of course offers are not just a number,
offers have other stipulations in them as well. And we have to look at the
overall offers when they do come in. What's the price, what are the other
aspects of it? And that's what we did in making the judgment we did to this
point.
21. Another kind of related, you say the market is poorer this year than 1999.
For those who don't follow the gas utility industry, could you say kind of
relative to book, what the transactions have been in 2000, and what they were in
1999 as a generalization?
Korell: In 1999 transactions seemed to be on the order of nine to ten times
EBITDA, and there were a lot of them. Which is another factor, there were a lot
more transactions in 1999. The market this year hasn't been as robust as that,
and we're at discounts basically from that level. So that's pretty much all I
would say about that.
22. Kind of like 20% discounts from that kind of a valuation maybe?
Korell: I don't have a number here.
23. And on the E&P while I have you, a few additional questions. You said that
you might not spud North Jeanerette until the fall 2001.
Korell: That's the way it's in our plan currently. It could happen earlier than
that.
24. Now earlier, a number of some months ago, you were talking about spuding
Jeanerette maybe as early as the first quarter of 2001, and I'm kind of
wondering, is there problems with getting equipment, or if there is more G&G
work on the prospect, or what is it?
Korell: We have done more work on the prospect, but additionally it's a deep
expensive test, and we'll need to find partners to participate in that with us,
which is probably the bigger part of the timing on it.
25. And Horeb, can you tell us what the story on that is, has it been sold, and
when a spud date on that is?
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Korell: I think our spud date, it's planned, per our current plan, to spud in
March. Currently we're showing us having a 27.5% working interest, and that's, I
think we have partners for that one. Again, Al is not here with me today, so I
can't really tell you who they are, but I think we have partners for that one.
26. On the Robertson, can you tell us what the status in terms of hooking that
up is, and what you expect from it?
Korell: Robertson, the one that we call Havala in house here, which is a part of
that same survey apparently, where Horeb is, where we're partners with Edge, I
think that Havala will be on line before the end of the year. They're in the
process right now of hooking it up.
Korell: Well thank you again for spending the time this morning with us. I think
you can tell from my comments that I'm very happy with the progress we've made
in 2000, we've just built year-on-year, '98, '99, and 2000 is our best year
operationally. We look forward to 2001; we have an active drilling program.
Fortunately with gas prices where they are we've been able to protect our cash
flow in a way that we can continue to let our program work, and still pay down
some debt, improve our balance sheet.
So again, thank you for joining us, and I wish you all a merry
Christmas.
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